AUDIT INFORMATION |
12 Months Ended |
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Dec. 31, 2022 | |
| Audit Information [Abstract] | |
| Auditor Name | Deloitte & Touche LLP |
| Auditor Location | Denver, Colorado |
| Auditor Firm ID | 34 |
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands |
Dec. 31, 2022 |
Dec. 31, 2021 |
|---|---|---|
| Statement of Financial Position [Abstract] | ||
| Other property and equipment, accumulated depreciation | $ 7,329 | $ 4,742 |
| Preferred stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
| Preferred stock, shares authorized (in shares) | 25,000,000 | 25,000,000 |
| Preferred stock, shares outstanding (in shares) | 0 | 0 |
| Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
| Common stock, shares authorized (in shares) | 225,000,000 | 225,000,000 |
| Common stock, shares issued (in shares) | 85,120,287 | 85,120,287 |
| Common stock, shares outstanding (in shares) | 84,572,846 | 84,572,846 |
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2022 |
Dec. 31, 2021 |
Dec. 31, 2020 |
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| Income Statement [Abstract] | |||
| General and administrative expense, stock-based compensation | $ 31,367 | $ 15,558 | $ 6,156 |
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) - $ / shares |
12 Months Ended | |
|---|---|---|
Dec. 31, 2022 |
Dec. 31, 2021 |
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| Statement of Stockholders' Equity [Abstract] | ||
| Cash dividends (in dollars per share) | $ 6.29 | $ 1.16 |
CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions |
Dec. 31, 2022 |
Dec. 31, 2021 |
Dec. 31, 2020 |
|---|---|---|---|
| Statement of Cash Flows [Abstract] | |||
| Restricted cash included in other noncurrent assets | $ 0.1 | $ 0.1 | $ 0.1 |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES |
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| Accounting Policies [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Description of Operations Civitas is an independent exploration and production company focused on the acquisition, development, and production of oil and associated liquids-rich natural gas in the Rocky Mountain region, primarily in the DJ Basin of Colorado. Basis of Presentation The accompanying consolidated financial statements include the accounts of the Company and have been prepared in accordance with GAAP, the instructions to Form 10-K, and Regulation S-X. All significant intercompany balances and transactions have been eliminated in consolidation. Additionally, certain prior period amounts have been reclassified to conform to current period presentation in the accompanying financial statements. During the current year, the Company is presenting inventory of oilfield equipment within prepaid expenses and other on the accompanying balance sheets. Accordingly, prior year amounts have been reclassified from inventory of oilfield equipment to prepaid expenses and other assets to conform to current year presentation. In connection with the preparation of the accompanying consolidated financial statements, the Company evaluated events subsequent to the balance sheet date of December 31, 2022, through the filing date of this report. Use of Estimates The preparation of the consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities and commitments as of the date of our financial statements. Actual results could differ from those estimates. Industry Segment and Geographic Information The Company operates in one industry segment, which is the acquisition, development, and production of oil and associated liquids-rich natural gas. All of the Company’s operations are conducted in the continental United States. Cash and Cash Equivalents The Company considers all highly liquid investments with original maturity dates of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximate fair value due to the short-term nature of these instruments. The Company maintained cash balances in excess of federal deposit insurance limits as of December 31, 2022 and 2021, potentially subjecting the Company to a concentration of credit risk. To mitigate this risk, we maintain our cash and cash equivalents in the form of money market deposit and checking accounts with financial institutions that we believe are creditworthy and are also lenders under our Credit Facility. Accounts Receivable The Company’s accounts receivable primarily consists of receivables due from purchasers of the Company’s oil, natural gas, and NGL production and from joint interest owners on properties the Company operates. The Company is exposed to credit risk in the event of nonpayment by the purchasers of its production and joint interest owners, nearly all of which are concentrated in energy-related industries. The Company continuously evaluates the creditworthiness of its purchasers and joint interest owners. Generally, the Company’s oil, natural gas, and NGLs receivables are collected within to two months. For receivables due from joint interest owners, the Company generally has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. The Company has historically experienced minimal bad debts. The Company does not believe the loss of any single purchaser of its production would materially impact its financial position or results of operations, as oil, natural gas, and NGLs are products with well-established and highly liquid markets. For the periods presented below, the following purchasers of the Company’s production accounted for more than 10% of the Company’s revenue as follows:
Property and Equipment Proved Properties. The Company accounts for its oil and natural gas properties under the successful efforts method of accounting. Under this method, the costs of development wells are capitalized to proved properties whether those wells are successful or unsuccessful. Capitalized drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities, are depleted using the units-of-production method based on estimated proved developed reserves. Proved leasehold costs are also depleted; however, the units-of-production method is based on estimated total proved reserves. The computation of depletion expense takes into consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging equipment. Because all of our proved properties are currently located in a single basin, we apply depletion on a single-basin basis. During the years ended December 31, 2022, 2021, and 2020, the Company incurred depletion expense of $773.5 million, $212.5 million, and $82.6 million, respectively. The Company assesses proved properties for impairment whenever events or circumstances indicate that their carrying value may not be recoverable. If carrying values exceed undiscounted future net cash flows, impairment is measured and recorded at fair value. Due to a lack of quoted market prices for proved properties, the Company estimates the fair value using valuation techniques that convert estimated future net cash flows to a single discounted amount. Significant inputs and assumptions to this estimation include, but are not limited to, reserves volumes, future operating and development costs, future commodity prices, inclusive of applicable differentials, and a market-based weighted average cost of capital rate. The expected future cash flows used for impairment reviews include future production volumes associated with proved developed producing reserves and risk-adjusted proved undeveloped reserves as well as risk-adjusted probable and possible reserves, as applicable. The partial sale of a proved property within an existing field is accounted for as a normal retirement and no net gain or loss on divestiture activity is recognized as long as such treatment does not significantly affect the units-of-production depletion rate. The sale of a partial interest in an individual proved property is accounted for as a recovery of cost. A net gain or loss on divestiture activity is recognized in the accompanying statements of operations for all other sales of proved properties. As of December 31, 2022 and 2021, the net book value of the Company’s midstream assets in the accompanying balance sheets was $326.8 million and $276.1 million, respectively. Depreciation on the Company’s midstream assets is calculated using the straight-line method over the estimated useful lives of the assets and properties they serve, which is approximately 30 years. Unproved Properties. Unproved properties consist of the costs to acquire undeveloped leases and are not subject to depletion until they are transferred to proved properties. Leasehold costs are transferred to proved properties on an ongoing basis as the properties to which they relate are evaluated and proved reserves established. Additional costs not subject to depletion include costs associated with development wells in progress or awaiting completion at year-end. These costs are transferred into costs subject to depletion on an ongoing basis as these wells are completed and proved reserves are established or confirmed. Unproved properties are routinely evaluated for continued capitalization or impairment. On a quarterly basis, management assesses undeveloped leasehold costs for impairment by considering, among other things, remaining lease terms, future drilling plans and capital availability to execute such plans, commodity price outlooks, recent operational results, reservoir performance and geology, and estimated acreage value based on prices received for similar, recent acreage transactions by the Company or other market participants. Changes in our assumptions of the estimated nonproductive portion of our undeveloped leases could result in additional impairment expense. The partial sale of unproved property is accounted for as a recovery of cost when there is uncertainty of the ultimate recovery of the cost applicable to the interest retained. Exploratory. Exploratory geological and geophysical, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage are expensed as incurred. Under the successful efforts method of accounting, exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are found, exploratory well costs will be capitalized as proved properties. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. The application of the successful efforts method of accounting requires judgment to determine the proper designation of wells as either development or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes. Once a well is drilled, the determination that economic proved reserves have been discovered may take considerable time and judgment. Exploratory dry hole costs are included in the cash flows from investing activities section as part of exploration and development of oil and natural gas properties within the accompanying statements of cash flows. Oil and Natural Gas Reserves. The successful efforts method of accounting inherently relies on the estimation of proved oil and natural gas reserves. Reserve quantities and the related estimates of future net cash flows are critical inputs in our calculation of units-of-production depletion and our evaluation of proved and unproved properties for impairment. The process of estimating and evaluating crude oil and natural gas reserves is complex, requiring the evaluation of available geological, geophysical, engineering, and economic data to estimate underground accumulations of oil and natural gas that cannot be precisely measured. Consequently, the Company engages third-party independent reserve engineers Ryder Scott to prepare our estimates of oil and natural gas reserves. Significant inputs and engineering assumptions used in developing the estimates of proved oil and natural gas reserves include reserves volumes, future operating and development costs, historical commodity prices, and the Company’s ability to convert proved undeveloped reserves to producing properties within five years of their initial proved booking. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history, and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur. We cannot predict the amounts or timing of such future revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in impairment of proved property. Other Property and Equipment Other property and equipment such as office furniture and equipment, buildings, and computer hardware and software are recorded at cost. Cost of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed as incurred. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets, which range from to 25 years. Leases The Company determines if an arrangement is representative of a lease at contract inception. Right-of-use assets represent our right to use the underlying assets for the lease term and the corresponding lease liabilities represent our obligations to make lease payments arising from the leases. Right-of-use assets and lease liabilities are recognized at the lease commencement date based on the present value of the lease payments over the lease term. When evaluating a contract, the Company applies certain judgments to determine, among other factors, lease classification as either operating or financing, lease term, and discount rate. The terms of certain of our leases include options to extend or terminate the lease, only when we can ascertain that it is reasonably certain we will exercise that option, as well as evergreen periods for which the penalties associated with termination are considered to be significant. Leases with an initial term of one year or less are not recorded on the accompanying balance sheets. As the Company does not have any leases with an implicit interest rate that can be readily determined, we utilize our incremental borrowing rate based on information available at the lease commencement date in determining the present value of lease payments. We determine our incremental borrowing rate at the lease commencement date using our Credit Facility benchmark rate and make adjustments for facility utilization and lease term. Subsequent measurement, as well as presentation of expenses and cash flows, is dependent upon the classification of the lease as either an operating or finance lease. Please refer to Note 13 - Leases for additional discussion. Carbon Offsets and Renewable Energy Credits The Company periodically purchases carbon offsets and renewable energy credits as a means to offset carbon emissions generated by its operations and purchased electricity that could not otherwise be reduced or eliminated. Commensurate with their use, purchased carbon offsets and renewable energy credits are initially capitalized at cost as an intangible asset within other noncurrent assets on the accompanying balance sheets. Subsequently, capitalized carbon offsets and renewable energy credits are expensed when applied to the Company’s carbon emissions through depletion, depreciation, and amortization expense on the accompanying statements of operations. Purchased carbon offsets and renewable energy credits expected to be utilized within the next 12 months are presented as short-term within prepaid expenses and other on the accompanying balance sheets. Deferred Financing Costs Deferred financing costs include origination, legal, and other fees incurred to issue debt or amend existing credit facilities. Deferred financing costs related to the Credit Facility are capitalized to prepaid expenses and other and other noncurrent assets on the accompanying balance sheets and amortized to interest expense, net on the accompanying statements of operations on a straight-line basis over the life of the Credit Facility. Deferred financing costs related to senior notes are capitalized within senior notes on the accompanying balance sheets and amortized to interest expense, net on the accompanying statements of operations using the effective interest method over the life of the respective borrowings. Asset Retirement Obligations The Company recognizes an asset retirement obligation at fair value based on the present value of costs expected to be incurred in connection with the future abandonment of its oil and natural gas properties, including wells and facilities, in accordance with applicable regulatory requirements. This obligation, and the corresponding capitalized cost recorded to proved properties, is recorded at the time assets are acquired, a well is completed and begins production, or a facility is constructed. The Company recognizes a periodic expense in connection with the accretion of the discounted asset retirement obligation over the remaining estimated economic lives of the respective long-lived assets. The accretion expense is recorded as a component of depreciation, depletion, and amortization in our accompanying statements of operations. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the corresponding capitalized cost recorded to proved properties. The recognition of an asset retirement obligation requires management to make various assumptions informed by historical experience and applicable regulatory requirements including estimated plugging and abandonment costs, economic lives, inflation rates, and the Company’s credit-adjusted risk-free rate. Cash paid to settle asset retirement obligations is included in the cash flows from operating activities section of the accompanying statements of cash flows. Please refer to Note 10 - Asset Retirement Obligations for a reconciliation of the Company’s total asset retirement obligation liability as of December 31, 2022 and 2021. Derivatives The Company periodically enters into commodity price derivative instruments to mitigate a portion of its exposure to potentially adverse market changes in commodity prices for its expected future oil and natural gas production and the associated impact on cash flows. These instruments typically include commodity price swaps and collars. The oil instruments are indexed to NYMEX WTI prices, and natural gas instruments are indexed to NYMEX HH and CIG prices, all of which have a high degree of historical correlation with actual prices received by the Company, before differentials. As of December 31, 2022, all derivative counterparties were members of the Credit Facility lender group and all commodity derivative contracts are entered into for other-than-trading purposes. The Company does not designate its commodity derivative contracts as hedging instruments. Commodity price derivative instruments are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities, with the exception of derivative instruments that meet the “normal purchase normal sale” exclusion. The Company measures the fair value of its commodity price derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates, volatility factors, and nonperformance risk. Changes in the fair value of the Company’s commodity price derivative instruments are recorded in the accompanying statements of operations as they occur. As of December 31, 2022 and 2021, all derivative instruments held by the Company were subject to master netting arrangements with various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between it and the counterparty, at the election of both parties, for transactions that settle on the same date and in the same currency. The Company’s agreements also provide that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to not offset these positions in its accompanying balance sheets. Derivative (gain) loss as well as derivative cash settlement gain (loss) are included within the cash flows from operating activities section of the accompanying statements of cash flows. Please refer to Note 9 - Derivatives for additional discussion. Revenue Recognition The Company recognizes revenue from the sale of produced oil, natural gas, and NGL at the point in time when control of produced oil, natural gas, or NGL volumes transfer to the purchaser, which may differ depending on the applicable contractual terms. The Company considers the transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the oil, natural gas, or NGL production. Transfer of control dictates the presentation of gathering, transportation, and processing expenses within the accompanying statements of operations. Gathering, transportation, and processing expenses incurred by the Company prior to the transfer of control are recorded gross within gathering, transportation, and processing in the accompanying statements of operations. Conversely, gathering, transportation, and processing expenses incurred by the Company subsequent to the transfer of control are recorded net within oil, natural gas, and NGL sales on the accompanying statements of operations. Oil sales. Under the Company’s crude purchase and marketing contracts, the Company typically delivers production at the wellhead, or other contractually agreed-upon delivery points, and collects an agreed-upon index price, net of pricing differentials. In this scenario, the Company recognizes revenue when control of its oil production transfers to the purchaser at the wellhead, or other contractually agreed-upon delivery point, at the net contracted price received. Natural gas and NGL sales. Under the Company’s natural gas processing contracts, the Company delivers natural gas to a midstream processing provider at the wellhead, inlet of the midstream processing provider’s system, or other contractually agreed-upon delivery points. The delivery points are specified within each contract, and the point at which control transfers varies between the inlet and tailgate of the midstream processing facility. The midstream processing provider gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs and residue gas. For the contracts where the Company maintains control through the tailgate of the midstream processing facility, the Company recognizes revenue on a gross basis, with gathering, transportation, and processing fees presented as an expense in the accompanying statements of operations. Alternatively, for those contracts where the Company relinquishes control at the inlet of the midstream processing facility, the Company recognizes natural gas and NGL revenues based on the contracted amount of the proceeds received from the midstream processing entity and, as a result, the Company recognizes revenue on a net basis. In certain natural gas processing agreements, the Company may elect to take its residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the Company delivers product to the third-party purchaser at a contractually agreed-upon delivery point and receives a specified index price from the third-party purchaser. In this scenario, the Company recognizes revenue when the control transfers to the third-party purchaser at the delivery point based on the index price received from the third-party purchaser. The gathering and processing expense attributable to the natural gas processing contracts, as well as any transportation expense incurred to deliver the product to the third-party purchaser, are presented as gathering, transportation, and processing expense in the consolidated statements of operations. The Company records revenue in the month production is delivered and control is transferred to the purchaser. However, settlement statements and payment may not be received for 30 to 60 days after the date production is delivered and control is transferred. Until such time settlement statements and payment are received, the Company records a revenue accrual based on, amongst other factors, an estimate of the volumes delivered at estimated prices as determined by the applicable contractual terms. The Company records the differences between its estimates and the actual amounts received for product sales in the month in which payment is received from the purchaser. Please refer to Note 3 - Revenue Recognition for additional discussion. Stock-Based Compensation The Company recognizes stock-based compensation based on the grant-date fair value of the equity instruments awarded. Stock-based compensation expense is recognized in the financial statements on a straight-line basis over the requisite service period for the entire award. The Company accounts for forfeitures of stock-based compensation awards as they occur. Please refer to Note 7 - Stock-Based Compensation for additional discussion. Income Taxes The Company accounts for income taxes under the asset and liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the balance sheet or tax returns. Deferred income tax assets and liabilities are measured using enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. If we determine that it is more-likely-than-not that some portion or all of the deferred income tax assets will not be realized, a valuation allowance is recorded, thereby reducing the deferred income tax assets to what is considered to be realizable. The Company recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The Company’s policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. There were no uncertain tax positions during any period presented. The tax returns for 2021, 2020, and 2019 are still subject to audit by the Internal Revenue Service. Please refer to Note 12 - Income Taxes for additional discussion. Earnings Per Share The Company uses the treasury stock method to determine the effect of potentially dilutive instruments. Please refer to Note 11 - Earnings Per Share for additional discussion. Acreage Exchanges From time to time, we enter into acreage exchanges in order to consolidate our core acreage positions, enabling us to have more control over the timing of development activities, achieve higher working interests and provide us the ability to drill longer lateral length wells within those core areas. We account for our nonmonetary acreage exchanges in accordance with the guidance prescribed by Accounting Standards Codification (“ASC”) 845, Nonmonetary Transactions. For those exchanges that lack commercial substance, we record the acreage received at the net carrying value of the acreage surrendered to obtain it. For those acreage exchanges that are deemed to have commercial substance, we record the acreage received at fair value, with a related gain or loss recognized within gain (loss) on property transactions, net in the accompanying statements of operations, in accordance with ASC 820, Fair Value Measurement. Business Combinations As part of our business strategy, we regularly pursue the acquisition of oil and natural gas properties. We utilize the acquisition method to account for acquisitions of businesses. Pursuant to this method, we allocate the cost of the acquisition, or purchase price, to assets acquired and liabilities assumed based on fair values as of the acquisition date. Please refer to Note 2 - Acquisitions and Divestitures for additional discussion. Fair Value of Financial Instruments The Company’s financial instruments consist of cash and cash equivalents, accounts receivables, and accounts payable and are carried at cost, which approximates fair value due to the short-term maturity of these instruments. As discussed above, the Company’s commodity price derivative instruments are recorded at fair value. The Company’s Senior Notes, as defined in Note 5 – Long-Term Debt, are recorded at cost, net of any unamortized deferred financing costs, and their respective fair values are disclosed in Note 8 – Fair Value Measurements. The recorded value of the Company’s Credit Facility, as defined in Note 5 – Long-Term Debt, approximates its fair value as it bears interest at a floating rate that approximates a current market rate. The Company’s warrants were recorded at fair value upon issuance, with no recurring fair value measurement required. Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would realize upon the sale or refinancing of such instruments. Please refer to Note 8 - Fair Value Measurements for additional discussion. Recently Issued and Adopted Accounting StandardsThere are no accounting standards applicable to the Company that would have a material effect on the Company’s financial statements and disclosures that have been issued but not yet adopted by the Company as of December 31, 2022, and through the filing date of this report.
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| Business Combination and Asset Acquisition [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| ACQUISITIONS AND DIVESTITURES | ACQUISITIONS AND DIVESTITURES All mergers and acquisitions disclosed were accounted for under the acquisition method of accounting for business combinations. Accordingly, we conducted assessments of the net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values. Associated transaction and integration costs were expensed as incurred. The fair value measurements of assets acquired and liabilities assumed were based on inputs that are not observable in the market, and therefore represent Level 3 inputs. Please refer to Note 8 - Fair Value Measurements for additional discussion regarding the various levels within the fair value hierarchy. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of proved properties include estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows, and a market-based weighted-average cost of capital. These inputs required significant judgments and estimates by management at the time of the valuation. HighPoint Merger On April 1, 2021, Civitas acquired HighPoint Resources Corporation (“HighPoint”), pursuant to the terms of HighPoint’s prepackaged plan of reorganization under Chapter 11 of the United States Bankruptcy Code (the “Prepackaged Plan”) (the “HighPoint Merger”). Pursuant to the Prepackaged Plan, each share of common stock of HighPoint issued and outstanding was converted into 0.11464 shares of common stock of Civitas (“Civitas Common Stock”). As a result, Civitas issued 488.0 thousand shares of Civitas Common Stock to former HighPoint stockholders. Concurrently with the HighPoint Merger and pursuant to the Prepackaged Plan, in exchange for the aggregate principal amount outstanding of HighPoint’s senior notes, Civitas issued an aggregate of (i) 9.3 million shares of Civitas Common Stock and (ii) $100.0 million aggregate principal amount of 7.5% Senior Notes due 2026 (“7.5% Senior Notes”). Please refer to Note 5 - Long-Term Debt for further discussion of the 7.5% Senior Notes, which have since been redeemed in full. The purchase price allocation was finalized as of the first quarter of 2022. The following tables present the merger consideration and final purchase price allocation of the assets acquired and the liabilities assumed in the HighPoint Merger:
_________________________ (1)Based on the number of shares of common stock of HighPoint issued and outstanding as of April 1, 2021 and the conversion ratio of 0.11464 per share of Civitas Common Stock. (2)Based on the closing stock price of Civitas Common Stock on April 1, 2021.
The valuation of proved oil and natural gas properties for the HighPoint Merger applied a market-based weighted-average cost of capital rate of approximately 13%. Extraction Merger On November 1, 2021, Civitas completed its merger with Extraction Oil & Gas, Inc. (“Extraction”), pursuant to the terms of the related Agreement and Plan of Merger (the “Extraction Merger Agreement”) (the “Extraction Merger”). Pursuant to the Extraction Merger Agreement, each share of common stock of Extraction issued and outstanding was converted into 1.1711 shares of Civitas Common Stock (the “Extraction Exchange Ratio”). As a result, Civitas issued 31.1 million shares of Civitas Common Stock to former Extraction stockholders. Additionally, each unvested award of restricted stock units issued pursuant to Extraction’s 2021 Long Term Incentive Plan (the “Extraction Equity Plan”) was assumed by Civitas and converted into a number of restricted stock units with respect to shares of Civitas Common Stock (such restricted stock unit, a “Converted RSU”) using the Extraction Exchange Ratio. Each Converted RSU continued to be governed by the same terms and conditions that were applicable immediately prior to the Extraction Merger closing date. Further, Civitas executed warrant agreements to replace the warrants previously issued by Extraction consisting of (i) 3.4 million Tranche A warrants to purchase Civitas Common Stock at an exercise price of $91.91 in whole or in part, at any time or from time to time on or before January 20, 2025, issued pursuant to a warrant agreement by and between Civitas and Broadridge Corporate Issuer Solutions, Inc., as warrant agent (“Broadridge”), dated as of November 1, 2021 (the “Tranche A Warrants”), and (ii) 1.7 million Tranche B warrants to purchase Civitas Common Stock at an exercise price of $104.45 in whole or in part, at any time or from time to time on or before (i) January 20, 2026, issued pursuant to a warrant agreement by and between Civitas and Broadridge, as warrant agent, dated as of November 1, 2021 (the “Tranche B Warrants,” and, together with the Tranche A Warrants, the “Warrants”). A holder of a warrant, in its capacity as such, is not entitled to any rights whatsoever as a stockholder of Civitas, except to the extent expressly provided in the applicable warrant agreement. Please refer to Note 8 - Fair Value Measurements for further discussion. The purchase price allocation was finalized as of the fourth quarter of 2022. The following tables present the merger consideration and final purchase price allocation of the assets acquired and the liabilities assumed in the Extraction Merger:
_________________________ (1)Based on the number of shares of common stock of Extraction issued and outstanding as of November 1, 2021 and the conversion ratio of 1.1711 per share of Civitas Common Stock. (2)Based on the closing stock price of Civitas Common Stock on November 1, 2021.
The valuation of oil and natural gas properties for the Extraction Merger applied a market-based weighted-average cost of capital rate of approximately 10%. Crestone Peak Merger On November 1, 2021, Civitas completed its merger with CPPIB Crestone Peak Resources America Inc. (“Crestone Peak”), pursuant to the terms of the related Agreement and Plan of Merger (the “Crestone Merger Agreement”) (the “Crestone Peak Merger”). Pursuant to the Crestone Merger Agreement, the shares of Crestone Peak common stock were converted into 22.5 million shares of Civitas Common Stock. The purchase price allocation was finalized as of the fourth quarter of 2022. The following tables present the merger consideration and final purchase price allocation of the assets acquired and the liabilities assumed in the Crestone Peak Merger:
(1)Based on the closing stock price of Civitas Common Stock on November 1, 2021.
The valuation of oil and natural gas properties for the Crestone Peak Merger applied a market-based weighted-average cost of capital rate of approximately 10%. Revenue and earnings of the acquiree The amount of revenue of HighPoint, Extraction, and Crestone Peak included in our statement of operations during the year ended December 31, 2021 was approximately $244.7 million, $172.3 million, and $114.8 million, respectively. We determined that disclosing the amount of HighPoint, Extraction, and Crestone Peak related earnings included in the statements of operation is impracticable, as the operations from these mergers were integrated into the operations of the Company from the dates of each acquisition. Supplemental pro forma financial information The following unaudited pro forma financial information (in thousands, except per share amounts) represents a summary of the consolidated results of operations for the year ended December 31, 2021 and 2020, assuming the HighPoint, Extraction, and Crestone Peak mergers had been completed as of January 1, 2020. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the mergers had been effective as of this date, or of future results, and includes certain non-recurring pro forma adjustments that were directly attributable to the business combinations (in thousands, except per share amounts).
Bison Acquisition On March 1, 2022, the Company acquired the privately held DJ Basin operator Bison Oil & Gas II, LLC (“Bison”) for merger consideration of approximately $280.4 million (the “Bison Acquisition”). Net assets acquired under the purchase price allocation were $294.0 million and consequently resulted in a bargain purchase gain of $13.6 million. Because of the immateriality of the Bison Acquisition, the related revenue and earnings, supplemental pro forma financial information, and detailed purchase price allocation are not disclosed. Merger transaction costs Merger transaction costs related to the aforementioned mergers and acquisitions are accounted for separately from the assets acquired and liabilities assumed and are included in merger transaction costs in the statements of operations. The Company incurred merger transaction costs of $24.7 million, $43.6 million, and $6.7 million during the years ended December 31, 2022, 2021, and 2020, respectively. Acquisition of additional working interests in Company-operated wells On July 5, 2022, the Company acquired additional working interests in certain Company-operated wells for cash consideration of $80.7 million, after customary purchase price adjustments.
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REVENUE RECOGNITION |
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| Revenue from Contract with Customer [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| REVENUE RECOGNITION | REVENUE RECOGNITION Oil and natural gas sales revenue presented within the accompanying statements of operations is reflective of the revenue generated from contracts with customers. Revenue attributable to each identified revenue stream is disaggregated below (in thousands):
For the years ended December 31, 2022, 2021, and 2020 revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was insignificant. As of December 31, 2022 and 2021, the Company’s receivables from contracts with customers were $343.5 million and $362.3 million, respectively.
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ACCOUNTS PAYABLE AND ACCRUED EXPENSES |
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| Payables and Accruals [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| ACCOUNTS PAYABLE AND ACCRUED EXPENSES | ACCOUNTS PAYABLE AND ACCRUED EXPENSESAccounts payable and accrued expenses contain the following (in thousands):
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LONG-TERM DEBT |
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| Debt Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| LONG-TERM DEBT | LONG-TERM DEBT 5.0% Senior Notes On October 13, 2021, the Company issued $400.0 million aggregate principal amount of 5.0% Senior Notes due 2026 (the “5.0% Senior Notes”) pursuant to an indenture (the “5.0% Indenture”), among Civitas Resources, Wells Fargo Bank, National Association, as trustee, and the guarantors party thereto. The Company used the net proceeds and cash on hand to repay all borrowings under the Credit Facility (as defined below), all borrowings outstanding under the Crestone Peak credit facility, and for general corporate purposes. Interest accrues at the rate of 5.0% per annum and is payable semiannually in arrears on April 15 and October 15 of each year. Payments commenced on April 15, 2022. The 5.0% Indenture contains covenants that limit, among other things, the Company’s ability to: (i) incur or guarantee additional indebtedness; (ii) create liens securing indebtedness; (iii) pay dividends on or redeem or repurchase stock or subordinated debt; (iv) make specified types of investments and acquisitions; (v) enter into or permit to exist contractual limits on the ability of the Company’s subsidiaries to pay dividends to Civitas Resources; (vi) enter into transactions with affiliates; and (vii) sell assets or merge with other companies. These covenants are subject to a number of important limitations and exceptions. The Company was in compliance with all covenants under the 5.0% Indenture as of December 31, 2022, and through the filing of this report. In addition, certain of these covenants will be terminated before the 5.0% Senior Notes mature if at any time no default or event of default exists under the 5.0% Indenture and the 5.0% Senior Notes receive an investment-grade rating from at least two ratings agencies. The 5.0% Indenture also contains customary events of default. At any time prior to October 15, 2023, the Company may redeem the 5.0% Senior Notes, in whole or in part, at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) the “make-whole” premium at the redemption date, plus (iii) accrued and unpaid interest, if any. On or after October 15, 2023, the Company may redeem all or part of the 5.0% Senior Notes at redemption prices (expressed as percentages of the principal amount redeemed) equal to (i) 102.5% for the twelve-month period beginning on October 15, 2023; (ii) 101.25% for the twelve-month period beginning on October 15, 2024; and (iii) 100.0% for the twelve-month period beginning October 15, 2025 and at any time thereafter, plus accrued and unpaid interest, if any. The Company may redeem up to 35% of the aggregate principal amount of the 5.0% Senior Notes at any time prior to October 15, 2023 with an amount not to exceed the net cash proceeds from certain equity offerings at a redemption price equal to 105.0% of the principal amount of the 5.0% Senior Notes redeemed, plus accrued and unpaid interest, if any, provided, however, that (i) at least 65.0% of the aggregate principal amount of the 5.0% Senior Notes originally issued on the issue date (but excluding 5.0% Senior Notes held by the Company) remains outstanding immediately after the occurrence of such redemption (unless all such 5.0% Senior Notes are redeemed substantially concurrently) and (ii) the redemption occurs within 180 days after the date of the closing of such equity offering. The 5.0% Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by all of Civitas’ existing subsidiaries. 7.5% Senior Notes In conjunction with the HighPoint Merger, the Company issued $100.0 million aggregate principal amount of 7.5% Senior Notes due 2026 (the “7.5% Senior Notes”) pursuant to an indenture, dated April 1, 2021, by and among Civitas Resources, U.S. Bank National Association, as trustee, and the guarantors party thereto. Interest accrued at the rate of 7.5% per annum and was payable semiannually in arrears on April 30 and October 31 of each year. On May 1, 2022, the Company redeemed all of the issued and outstanding 7.5% Senior Notes at 100.0% of their aggregate principal amount, plus accrued and unpaid interest thereon to the redemption date. The 7.5% Senior Notes and 5.0% Senior Notes are recorded net of unamortized deferred financing costs within senior notes on the accompanying balance sheets. There were no discounts or premiums associated with either issuance. The tables below present the related carrying values as of December 31, 2022 and December 31, 2021 (in thousands):
Credit Facility The Company is party to a reserve-based revolving facility, as the borrower, with JPMorgan Chase Bank, N.A. (“JPMorgan”), as the administrative agent, and a syndicate of financial institutions (the “Lender Syndicate”), as lenders, that has an aggregate maximum commitment amount of $2.0 billion and matures on November 1, 2025 (with all subsequent amendments, the “Credit Facility” or the “Credit Agreement”). The Credit Facility is guaranteed by all restricted domestic subsidiaries of the Company, and is secured by first priority security interests on substantially all assets, including a mortgage on at least 90% of the total value of the proved properties evaluated in the most recently delivered reserve reports prior to the amendment effective date, including any engineering reports relating to the oil and natural gas properties of the restricted domestic subsidiaries of the Company, subject to customary exceptions. The Credit Facility contains customary representations and affirmative covenants. The Credit Facility also contains customary negative covenants, which, among other things, and subject to certain exceptions, include restrictions on (i) liens, (ii) indebtedness, guarantees and other obligations, (iii) restrictions in agreements on liens and distributions, (iv) mergers or consolidations, (v) asset sales, (vi) restricted payments, (vii) investments, (viii) affiliate transactions, (ix) change of business, (x) foreign operations or subsidiaries, (xi) name changes, (xii) use of proceeds, letters of credit, (xiii) gas imbalances, (xiv) hedging transactions, (xv) additional subsidiaries, (xvi) changes in fiscal year or fiscal quarter, (xvii) operating leases, (xviii) prepayments of certain debt and other obligations, (xix) sales or discounts of receivables, (xx) dividend payment thresholds, and (xxi) cash balances. In addition, the Company is subject to certain financial covenants under the Credit Facility, as tested on the last day of each fiscal quarter, including, without limitation, (a) permitted net leverage ratio of 3.00 to 1 and (b) a current ratio, inclusive of the unused commitments then available to be borrowed, to not be less than 1.00 to 1. The Company was in compliance with all covenants under the Credit Facility as of December 31, 2022, and through the filing of this report. On April 20, 2022, the Company entered into an amendment to the Credit Agreement that increased the Company’s borrowing base from $1.0 billion to $1.7 billion and increased the aggregate elected commitments from $800.0 million to $1.0 billion. In addition, this amendment resulted in the removal and replacement of LIBOR with the Secured Overnight Financing Rate (“SOFR”) as a mechanism to determine interest for borrowings made under the Credit Facility using a term-specific SOFR. As a result, borrowings under the Credit Facility bear interest at a per annum rate equal to, at the option of the Company, either (i) the Alternate Base Rate (“ABR”, for ABR Revolving Credit Loans) plus the applicable margin, or (ii) the term-specific SOFR plus the applicable margin. ABR is established as a rate per annum equal to the greatest of (a) the rate of interest publicly announced by JPMorgan as its prime rate, (b) the applicable rate of interest published by the Federal Reserve Bank of New York plus 0.5%, or (c) the term-specific SOFR plus 1.0%, subject to a 1.5% floor plus the applicable margin of 1.0% to 2.0%, based on the utilization of the Credit Facility. Term-specific SOFR is based on one-, three-, or six-month terms as selected by the Company and is subject to a 0.5% floor plus the applicable margin of 2.0% to 3.0%, based on the utilization of the Credit Facility. Interest on borrowings that bear interest at the SOFR shall be payable on the last day of the applicable interest period selected by the Company, and interest on borrowings that bear interest at the ABR shall be payable quarterly in arrears. On October 27, 2022, and as part of the regularly scheduled, semi-annual borrowing base redetermination under the Credit Facility, the Company’s aggregate elected commitments of $1.0 billion were reaffirmed and borrowing base was increased from $1.7 billion to $1.85 billion. The next scheduled borrowing base redetermination date is set to occur in April 2023. The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Credit Facility as of the dates indicated (in thousands):
In connection with the amendments to the Credit Facility, the Company capitalized a total of approximately $11.9 million in deferred financing costs. Of the total post-amortization net capitalized amounts, (i) $5.5 million and $7.5 million are presented within other noncurrent assets on the accompanying balance sheets as of December 31, 2022 and 2021, respectively, and (ii) $3.0 million and $2.7 million are presented within prepaid expenses and other on the accompanying balance sheets as of December 31, 2022 and 2021, respectively. Interest Expense For the years ended December 31, 2022, 2021, and 2020, the Company incurred interest expense of $32.2 million, $16.0 million, and $3.8 million respectively. The Company capitalized zero, $6.3 million, and $1.8 million of interest expense during the years ended December 31, 2022, 2021, and 2020, respectively.
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COMMITMENTS AND CONTINGENCIES |
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| Commitments and Contingencies Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| COMMITMENTS AND CONTINGENCIES | COMMITMENTS AND CONTINGENCIES Legal Proceedings From time to time, the Company is involved in various commercial and regulatory claims, litigation, and other legal proceedings that arise in the ordinary course of its business. The Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its consolidated financial statements. In accordance with authoritative accounting guidance, an accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the most likely anticipated outcome or the minimum amount within a range of possible outcomes. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, the Company may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matters. The Company regularly reviews contingencies to determine the adequacy of its accruals and related disclosures. Upon closing of the HighPoint, Extraction, and Crestone Peak mergers and Bison Acquisition, the Company assumed all obligations, whether asserted or unasserted, of HighPoint, Extraction, Crestone Peak, and Bison. As of the filing date of this report, there were no probable, material pending, or overtly threatened legal actions against the Company of which it was aware, other than the following: Boulder County. In prior periods, there was ongoing litigation between Boulder County and Extraction which has been previously disclosed as having the potential to prevent oil and gas operations for the development of minerals contained within Boulder County, Colorado. Boulder County had initiated suit in District Court for Boulder County that was primarily a contract case, where the relevant contracts were the conservation easement over the Blue Paintbrush location, Extraction’s Surface Use Agreement for the Blue Paintbrush location, and the leases that Boulder owns within the Blue Paintbrush drilling and spacing unit. Boulder sought invalidation of these leases in the litigation. This litigation has been resolved as to all substantive issues, and the Company is awaiting final dismissal of the matter by the trial court. In May 2022, the Company became aware that Boulder County is alleging new legal theories and requesting termination of the leases previously at issue in the Blue Paintbrush litigation. No formal action has been initiated, but the Company intends to vigorously defend against all claims alleged by Boulder County. If an action is brought by Boulder County, an adverse outcome in any such litigation could result in the Company failing to meet its development objectives in Blue Paintbrush. Enforcement. Disclosure of certain environmental matters is required when a governmental authority is a party to the proceedings and the proceedings involve potential monetary sanctions that the Company believes could exceed $0.3 million. The Company has received Notices of Alleged Violations (“NOAV”) from the COGCC alleging violations of various Colorado statutes and COGCC regulations governing oil and gas operations. The Company has further received notices from the Colorado Air Pollution Control Division. The Company continues to engage in discussions regarding resolution of the alleged violations. As of December 31, 2022 and December 31, 2021, the Company accrued approximately $0.7 million and $1.0 million, respectively, associated with the NOAVs and Colorado Air Pollution Control Division notices, as they were probable and reasonably estimable. Commitments Firm Transportation Agreements. The Company is party to a firm pipeline transportation contract to provide a guaranteed outlet for production on an oil pipeline system. The contract requires the Company to pay minimum volume transportation charges on 12,500 barrels per day through April 2025, regardless of the amount of pipeline capacity utilized by the Company. The aggregate financial commitment fee over the remaining term was $34.0 million as of December 31, 2022. The Company expects to utilize most, if not all, of the firm capacity on the oil pipeline system. Minimum Volume Agreement - Oil. The Company is party to a purchase agreement to deliver fixed and determinable quantities of crude oil. Under the terms of the agreement, the Company is required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitment of 20,000 gross Bbls per day over a term ending in December 2023. The aggregate financial commitment fee over the remaining term is $47.3 million as of December 31, 2022. The Company has not and does not expect to incur any deficiency payments. Minimum Volume Agreement - Gas and Other. The Company is party to a gas gathering and processing agreement (the “Gathering Agreement”) with a third-party midstream provider over a term ending in 2029 with an annual minimum volume commitment of 13.0 billion cubic feet of natural gas. The Gathering Agreement also includes a commitment to sell take-in-kind NGLs from other processing agreements of 7,500 Bbls a day through 2026 with the ability to roll forward up to a 10% shortfall in a given month to the subsequent month. The aggregate financial commitment over the remaining term is $121.7 million as of December 31, 2022, which fluctuates with commodity prices as this is a value-based percentage of proceeds sales contract. Based on current projections, the Company may incur approximately $52.6 million of shortfall payments under the Gathering Agreement during the remaining term of approximately seven years; however, the Company is actively engaging alternative strategies to reduce any potential contract deficiencies incurred in future periods. Additionally, the Company is also party to a gas gathering and processing agreement with several third-party producers and a third-party midstream provider to deliver to two different plants over terms that end in August 2025 and July 2026. The Company’s share of these commitments requires an incremental 51.5 and 20.6 MMcf per day, respectively, over a baseline volume of 65 MMcf per day for a period of seven years following the in-service dates of the plants. The Company may be required to pay a shortfall fee for any incremental volume deficiencies under these commitments. These contractual obligations can be reduced by the Company’s proportionate share of the collective volumes delivered to the plants by other incremental third-party volumes available to the midstream provider that are in excess of the total commitments. Because of the third-party producer reduction provision, we believe that the aggregate financial commitment fee over the remaining term is zero as of December 31, 2022. The Company has not and does not expect to incur any deficiency payments. The Company is also party to additional individually immaterial agreements that require the Company to pay a fee associated with the minimum volumes over various terms ending in April 2025, regardless of the amount delivered. The aggregate financial commitment fee over the remaining term for these contracts was $8.3 million as of December 31, 2022. The minimum annual payments under the these agreements for the next five years as of December 31, 2022 are presented below (in thousands):
___________________________ (1)The above calculation is based on the minimum volume commitment schedule (as defined in the relevant agreement) and applicable differential fees. Other commitments. The Company is party to a drilling commitment agreement with a third-party midstream provider such that the Company is required to drill and complete a total of 106 qualifying wells, whereby a minimum number of wells out of the total must be drilled by a deadline occurring every two years over a period ending December 31, 2026. The drilling commitment agreement provides for, among other things, a number of specifications such as minimum consecutive days of production, well performance, and lateral length. Wells operated by others can satisfy this commitment, subject to limitations. If the Company were to fail to complete the wells by the applicable deadline, it would be in breach of the agreement and the third-party midstream provider could attempt to assert damages against Civitas and its affiliates. As of the date of filing, the Company cannot reasonably estimate how much, if any, damages will be paid. Refer to Note 13 - Leases for lease commitments.
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STOCK-BASED COMPENSATION |
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| Share-Based Payment Arrangement [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| STOCK-BASED COMPENSATION | STOCK-BASED COMPENSATION Long Term Incentive Plans In April 2017, the Company adopted the 2017 Long Term Incentive Plan (“2017 LTIP”), which provides for the issuance of restricted stock units, performance stock units, and stock options, and reserved 2,467,430 shares of common stock. In June 2021, the Company adopted the 2021 Long Term Incentive Plan (“2021 LTIP”), which reserved an incremental 700,000 shares of common stock to those previously reserved under the 2017 LTIP. Finally, pursuant to the Extraction Merger Agreement, Civitas assumed the Extraction Equity Plan, which reserved 3,305,080 shares of common stock now issuable by Civitas. The 2017 LTIP, 2021 LTIP, and Extraction Equity Plan are collectively referred to herein as the “LTIP”. In November 2021, the Company adopted a non-employee director compensation program (the “Director Compensation Program”), which provides that non-employee directors will receive grants of deferred stock units (“DSUs”). In connection with the adoption of the Director Compensation Program, the Company adopted a First Amendment to the 2021 LTIP that, among other things, allows the Company to determine whether dividend rights granted pursuant to the LTIP should be reinvested, paid currently or paid in accordance with the terms of an associated award. The Company records compensation expense associated with the issuance of awards under the LTIP on a straight-line basis over the vesting period based on the fair value of the awards as of the date of grant within general and administrative expense. The following table outlines the compensation expense recorded by type of award (in thousands):
As of December 31, 2022, unrecognized compensation expense related to the awards granted under the LTIP will be amortized through the relevant periods as follows (in thousands):
Restricted Stock Units (“RSUs”) and Deferred Stock Units The Company typically grants RSUs to officers, directors, and employees and DSUs to directors as part of its LTIP. Each RSU and DSU represents a right to receive one share of the Company’s common stock upon settlement of the award at the end of the specified vesting period. RSUs generally vest and settle either over a (i) one-year vesting period, with the entire grant vesting and settling on the anniversary date or (ii) three-year vesting period, with one-third of the total grant vesting and settling on each anniversary date. DSUs generally vest in quarterly installments over a one-year period following the grant date. DSUs are settled in shares of the Company’s common stock upon the director’s separation of service from the Board. The fair value of RSUs and DSUs is equal to the closing price of the Company’s common stock on the date of the grant. A summary of the status and activity of non-vested RSUs and DSUs for the year ended December 31, 2022 is presented below:
The fair value of the RSUs and DSUs granted under the LTIP during the year ended December 31, 2022 was $29.4 million. Performance Stock Units (“PSUs”) The Company grants PSUs to officers as part of its LTIP. The number of shares of the Company’s common stock issued to settle PSUs ranges from zero to two times the number of PSUs granted and is determined based on performance achievement against certain criteria over a three-year performance period. PSUs generally vest and settle on the third anniversary of the date of the grant. Performance achievement is determined based on one to two criteria. The first criterion is based on either, or a combination of, the Company’s absolute and relative total shareholder return (“TSR”) over the performance period. Absolute TSR is determined based upon the performance of the Company’s common stock over the performance period relative to the price of the Company’s common stock at the grant date. For awards with relative TSR component, the Company’s absolute TSR is compared with the absolute TSRs of a group of peer companies over the performance period. The absolute TSR for the Company and each of the peer companies is determined by dividing (A) (i) the volume-weighted average share price for the last 30 trading days of the performance period, minus (ii) the volume-weighted average share price for the 30 trading days preceding the beginning of the performance period, plus (iii) dividends paid by (B) the volume-weighted average share price for the 30 trading days preceding the beginning of the performance period. The resultant amount is then annualized based on the length of the performance period. The second criterion, if applicable, is based on the Company’s annual return on average capital employed (“ROCE”) for each year during the three-year performance period. The total number of PSUs granted under the LTIP was split as follows for the relevant grant years:
The compensation expense associated with PSUs that are dependent on a performance-based settlement criterion is adjusted based on the number of units expected to vest based on the Company’s expected ROCE performance. Of the grant-date fair value, the portion of the PSUs tied to TSR performance required a stochastic process method using a Brownian Motion simulation. A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the PSUs tied to TSR performance, the Company could not predict with certainty the path its stock price or the stock prices of its peers would take over the performance period. By using a stochastic simulation, the Company created multiple prospective stock pathways, statistically analyzed these simulations, and ultimately made inferences regarding the most likely path the stock price would take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the Brownian Motion Model, was deemed an appropriate method by which to determine the fair value of the portion of the PSUs tied to TSR performance. Significant assumptions used in this simulation include the Company’s expected volatility, risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the performance period, as well as the volatilities for each of the Company’s peers. The following table presents the range of assumptions used to determine the fair value of the PSUs with market-based settlement criteria as granted under the LTIP throughout each of the periods presented:
A summary of the status and activity of non-vested PSUs for the year ended December 31, 2022 is presented below:
___________________________ (1)The number of awards assumes that the associated performance condition is met at the target amount (multiplier of one). The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the performance condition. The fair value of the PSUs granted under the LTIP during the year ended December 31, 2022 was $18.5 million. The PSUs granted in 2020 vested as of December 31, 2022 and are expected to be released during the first quarter of 2023 with 200% and 92% of shares tied to TSR and ROCE performance, respectively, distributed to the recipients. In addition, certain PSUs vested during 2022 pursuant to change in control provisions in the applicable award agreements. Stock Options The LTIP allows for the issuance of stock options to the Company’s employees at the sole discretion of the Board. Options expire ten years from the grant date unless otherwise determined by the Board. Stock options are valued using a Black-Scholes Model where expected volatility is based on an average historical volatility of a peer group selected by management over a period consistent with the expected life assumption on the grant date, the risk-free rate of return is based on the U.S. Treasury constant maturity yield on the grant date with a remaining term equal to the expected term of the awards, and the Company’s expected life of stock option awards is derived from the midpoint of the average vesting time and contractual term of the awards. A summary of the status and activity of non-vested stock options for the year ended December 31, 2022 is presented below:
The aggregate intrinsic value of options exercised during the year ended December 31, 2022 was $0.2 million.
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FAIR VALUE MEASUREMENTS |
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| Fair Value Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| FAIR VALUE MEASUREMENTS | FAIR VALUE MEASUREMENTS The Company follows authoritative accounting guidance for measuring the fair value of assets and liabilities in its financial statements. This guidance defines fair value as 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. Further, this guidance establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. The fair value hierarchy is broken down into three levels based on the reliability of the inputs as follows: Level 1: Quoted prices in active markets for identical assets or liabilities Level 2: Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable Level 3: Significant inputs to the valuation model are unobservable Financial and non-financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy. Derivatives The Company uses Level 2 inputs to measure the fair value of oil and natural gas commodity price derivatives. The fair value of the Company’s commodity price derivatives is estimated using industry-standard models that contemplate various inputs including, but not limited to, the contractual price of the underlying position, current market prices, forward commodity price curves, volatility factors, time value of money, and the credit risk of both the Company and its counterparties. We validate our fair value estimate by corroborating the original source of inputs, monitoring changes in valuation methods and assumptions, and reviewing counterparty mark-to-market statements and other supporting documentation. Refer to Note 9 - Derivatives for more information regarding the Company’s derivative instruments. The following tables present the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2022 and 2021 and their classification within the fair value hierarchy (in thousands):
Long-Term Debt The 5.0% Senior Notes are recorded at cost, net of any unamortized deferred financing costs. As of December 31, 2022, the fair value of the 5.0% Senior Notes was $369.4 million. This fair value is based on quoted market prices, and as such, is designated as Level 1 within the fair value hierarchy. The recorded value of the Credit Facility approximates its fair value as it bears interest at a floating rate that approximates a current market rate. Please refer to Note 5 - Long-Term Debt for additional information. Warrants As discussed in Note 2 - Acquisitions and Divestitures, the Company issued warrants in connection with the Extraction Merger. The warrants issued are indexed to the Company’s common stock and are required to be net share settled via a cashless exercise. The Company evaluated the warrants under authoritative accounting guidance and determined that they should be classified as equity instruments. The Company’s share price traded below the exercise price of the warrants and therefore were not exercisable during the years ended December 31, 2022 and 2021. The fair value of the warrants on the issuance date was determined using Level 3 inputs including, but not limited to, volatility, risk-free rate, and dividend yield under the Cox-Ross-Rubinstein binomial option pricing model. The warrants were included as a component of merger consideration and are recorded within additional paid-in capital on the accompanying balance sheets at a fair value of $77.5 million, with no recurring fair value measurement required. There have been no changes to the initial carrying amount of the warrants since issuance. Acquisitions and Impairments of Proved and Unproved Properties We measure acquired assets or businesses at fair value on a nonrecurring basis and review our proved and unproved oil and natural gas properties for impairment using inputs that are not observable in the market, and are therefore designated as Level 3 within the valuation hierarchy. During the years ended December 31, 2022, 2021, and 2020, the Company recorded no impairments of proved properties and incurred $18.0 million, $57.3 million, and $37.3 million, respectively, of abandonment and impairment of unproved properties. Please refer to Note 1 – Summary of Significant Accounting Policies for information on the Company’s policies for determining fair value of its proved and unproved properties and related impairment expense.
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DERIVATIVES |
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| Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| DERIVATIVES | DERIVATIVES The Company periodically enters into commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in commodity prices for its expected future oil and natural gas production and the associated impact on cash flows. The Company’s commodity derivative contracts consist of swaps, collars, and basis protection swap arrangements. As of December 31, 2022, all derivative counterparties were members of the Credit Facility lender group and all commodity derivative contracts are entered into for other-than-trading purposes. The Company does not designate its commodity derivative contracts as hedging instruments. A typical swap arrangement guarantees a fixed price on contracted volumes. If the agreed upon published third-party index price (“index price”) is lower than the fixed contract price at the time of settlement, the Company receives the difference between the index price and the fixed contract price. If the index price is higher than the fixed contact price at the time of settlement, the Company pays the difference between the index price and the fixed contract price. A typical collar arrangement establishes a floor and ceiling price on contracted volumes through the use of a short call and a long put (“two-way collar”). When the index price is above the ceiling price at the time of settlement, the Company pays the difference between the index price and the ceiling price. When the index price is below the floor price at the time of settlement, the Company receives the difference between the index price and floor price. When the index price is between the floor price and ceiling price, no payment or receipt occurs. A minority of our collar arrangements combine a two-way collar with a short put that holds an exercise price below the floor price (“three-way collar”). In these arrangements, when the index price is below the floor price at the time of settlement, the Company receives the difference between the index price and the floor price, capped at the difference between the floor price and the exercise price of the short put. Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For basis protection swaps, the Company receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract. As of December 31, 2022, the Company had entered into the following commodity price derivative contracts:
Subsequent to December 31, 2022, the Company entered into a series of fixed price, natural gas basis protection swaps on all of its outstanding NYMEX HH positions through the third quarter of 2024 to mitigate exposure to adverse pricing differentials between NYMEX HH and CIG. The weighted-average contract price entered of $(0.13) per MMBtu represents the amount of reduction to the NYMEX HH natural gas price for the contracted volumes covered by the basis protection swaps. Derivative Assets and Liabilities Fair Value The Company’s commodity price derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities. The following table contains a summary of all the Company’s derivative positions reported on the accompanying balance sheets as well as a reconciliation between the gross assets and liabilities and the potential effects of master netting arrangements on the fair value of the Company’s commodity derivative contracts as of December 31, 2022 and 2021 (in thousands):
The following table summarizes the components of the derivative gain (loss) presented on the accompanying statements of operations for the periods below (in thousands):
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ASSET RETIREMENT OBLIGATIONS |
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| Asset Retirement Obligation Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| ASSET RETIREMENT OBLIGATIONS | ASSET RETIREMENT OBLIGATIONS The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties, including facilities requiring decommissioning. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is drilled or acquired, or a facility is constructed. The increase in carrying value is included in proved properties in the accompanying balance sheets. The Company depletes the amount added to proved properties and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective long-lived assets. Cash paid to settle asset retirement obligations is included in the cash flows from operating activities section of the accompanying statements of cash flows. The Company’s estimated asset retirement obligation liability is based on historical experience plugging and abandoning wells, estimated economic lives, estimated plugging and abandonment cost, and regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. A roll-forward of the Company’s asset retirement obligation is as follows (in thousands):
___________________________ (1)Revisions to estimates for the year ended December 31, 2022 and 2021 were primarily a result of increases in the Company’s estimated plugging and abandonment cost.
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EARNINGS PER SHARE |
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| Earnings Per Share [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| EARNINGS PER SHARE | EARNINGS PER SHARE Earnings per basic and diluted share are calculated under the treasury stock method. Basic net income per common share is calculated by dividing net income by the basic weighted-average common shares outstanding for the respective period. Diluted net income per common share is calculated by dividing net income by the diluted weighted-average common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities consist of unvested RSUs, DSUs, PSUs as well as outstanding in-the-money stock options and warrants. When the Company recognizes a loss from continuing operations, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted earnings per share. As discussed in Note 7 - Stock-Based Compensation, PSUs represent the right to receive a number of shares of the Company’s common stock ranging from zero to two times the number of PSUs granted based on the performance achievement over the applicable performance period. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the performance period applicable to such awards. The Company has also issued stock options and warrants, which both represent the right to purchase the Company’s common stock at a specified exercise price. The number of potentially dilutive shares related to the stock options and warrants is based on the number of shares, if any, that would be exercisable at the end of the respective reporting period, assuming that date was the end of such stock options’ or warrants’ term. Stock options and warrants are only dilutive when the average price of the common stock during the period exceeds the exercise price. The following table sets forth the calculations of basic and diluted net income per common share (in thousands, except per share amounts):
There were 20,699, 178,051, and 248,744 unvested awards that were anti-dilutive for the years ended December 31, 2022, 2021, and 2020 respectively. The exercise price of the Company’s warrants was in excess of the Company’s stock price during the years ended December 31, 2022 and 2021; therefore, they were excluded from the earnings per share calculation.
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INCOME TAXES |
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| Income Tax Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| INCOME TAXES | INCOME TAXES Deferred tax assets and liabilities are measured by applying the provisions of enacted tax laws to determine the amount of taxes payable or refundable currently or in future years related to cumulative temporary differences between the tax basis of assets and liabilities and amounts reported in the accompanying balance sheets. The tax effect of the net change in the cumulative temporary differences during each period in the deferred tax assets and liabilities determines the periodic provision for deferred taxes. The provision for income taxes consists of the following (in thousands):
Temporary differences between the financial statement carrying amounts and tax basis of assets and liabilities that give rise to the net deferred tax liability and asset result from the following components (in thousands):
The following table outlines the Federal net operating loss (“NOL”) carryforwards acquired and deferred tax assets and liabilities recorded as a result of the mergers that closed in 2021 (in millions):
(1)The net operating loss carryforwards acquired in the HighPoint, Extraction, and Crestone Peak mergers will be subject to an annual limitation under Section 382 of the Code of approximately $5.6 million, $7.0 million, and $16.8 million, respectively. The Company had $1.8 billion and $2.0 billion of net operating loss carryovers for federal income tax purposes as of December 31, 2022 and 2021, respectively. Due to change of ownership provisions of Section 382 of the Code, utilization of net operating loss carryovers and other tax attributes are limited. Federal net operating loss carryforwards incurred prior to January 1, 2018 of $569.2 million will begin to expire in 2035. Federal net operating loss carryforwards incurred after December 31, 2017 of $1.2 billion have no expiration and can only be used to offset 80% of taxable income when utilized. The Company assesses the recoverability of its deferred tax assets each period by considering whether it is more-likely-than-not that all or a portion of the deferred tax assets will be realized. In making such determination, the Company considers all available (both positive and negative) evidence, including future reversals of temporary differences, tax-planning strategies, projected future taxable income, and results of operations. As a result of the HighPoint Merger, the Company had a valuation allowance of $25.4 million and $48.1 million as of December 31, 2022 and 2021, respectively, against certain acquired net operating losses and other tax attributes due to the limitation on realizability caused by the change of ownership provisions of Section 382 of the Code. The Company will continue to monitor facts and circumstances in the reassessment of the likelihood that the deferred tax assets will be realized. Recorded income tax expense or benefit differs from the amount that would be provided by applying the statutory United States federal income tax rate of 21% to income before income taxes. These differences primarily relate to the effect of state income taxes, excess tax benefits and deficiencies on stock-based compensation awards, tax limitations on compensation of covered individuals, changes in valuation allowances, and other permanent differences, as follows (in thousands):
The Company had no unrecognized tax benefits as of December 31, 2022, 2021, and 2020. The tax returns for 2021, 2020, and 2019 are still subject to audit by the Internal Revenue Service. On August 16, 2022, the Inflation Reduction Act (“IRA”) was signed into law. Among other provisions, the IRA imposes a 15% corporate alternative minimum tax (“Corporate AMT”) for tax years beginning after December 31, 2022, imposes a 1% excise tax on corporate stock repurchases after December 31, 2022, and provides tax incentives to promote various energy efficient initiatives. The Company is evaluating the potential impact of the Corporate AMT on our current income tax expense and income taxes payable; however, we currently do not believe this will materially affect our income taxes paid for the 2023 tax year.
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LEASES |
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| Leases [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| LEASES | LEASES The Company’s right-of-use assets and lease liabilities are recognized on the accompanying balance sheets based on the present value of the expected lease payments over the lease term. As of December 31, 2022 and 2021, the Company did not have any agreements in place that were classified as finance leases. The following table summarizes the asset classes of the Company’s operating leases (in thousands):
____________________________ (1)Includes compressors, certain natural gas processing equipment, and other field equipment. The following table summarizes the components of the Company’s gross lease costs incurred for the periods below (in thousands):
___________________________ (1)Includes office rent expense of $4.3 million, $2.2 million, and $1.1 million for the years ended December 31, 2022, 2021, and 2020, respectively. (2)Includes drilling rigs and other equipment. Short-term drilling rig costs include a non-lease labor component, which is treated as a single lease component. (3)The Company subleased a portion of one of its office spaces for the remainder of the office lease term (4)Variable lease costs represent differences between lease obligations and actual costs incurred for certain leases that do not have fixed payments related to both lease and non-lease components. Such incremental costs include lease payment increases or decreases driven by market price fluctuations and leased asset maintenance costs.Variable lease costs were not material for the years ended December 31, 2022, 2021, and 2020. Lease costs disclosed above are presented on a gross basis. A portion of these costs may have been or will be billed to other working interest owners. The Company’s net share of these costs is included in various line items on the accompanying statements of operations or capitalized to proved properties or other property and equipment, as applicable. The Company recognizes operating lease cost on a straight-line basis. Short-term lease costs are recognized as incurred and represent payments for leases with a lease term of one year or less, excluding leases with a term of one month or less. The Company’s weighted-average remaining lease terms and discount rates as of December 31, 2022 are as follows:
Future commitments by year for the Company’s leases with a lease term of one year or more as of December 31, 2022 are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the accompanying balance sheets as follows (in thousands):
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SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION |
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| Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION | SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION Supplemental cash flow disclosures are presented below (in thousands):
(1)Includes $542.6 million, $2.1 billion, and $2.3 billion in non-cash property additions related to the HighPoint, Extraction, and Crestone Peak mergers, respectively, for the year ended December 31, 2021. (2)Includes $374.9 million, $1.8 billion, and $1.3 billion in non-cash consideration related to the HighPoint, Extraction, and Crestone Peak mergers, respectively, for the year ended December 31, 2021.
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DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) |
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| Results of Operations, Revenue from Oil and Gas Producing Activities [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) | DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) The Company’s oil and natural gas activities are located entirely within the United States. Costs incurred in the acquisition, development, and exploration of oil and natural gas properties, whether capitalized or expensed, are summarized below (in thousands):
(1)Acquisition costs for unproved properties for the years ended December 31, 2022, 2021, and 2020 were $16.8 million, $648.0 million, and $2.3 million, respectively. There were $420.3 million, $4.2 billion, and $9.0 million in acquisition costs for proved properties for the years ended December 31, 2022, 2021, and 2020, respectively. (2)Development costs include workover costs of $8.6 million, $2.2 million, and $1.2 million charged to lease operating expense for the years ended December 31, 2022, 2021, and 2020, respectively. (3)Includes amounts relating to asset retirement obligations of $64.7 million, $13.8 million, and $(1.0) million for the years ended December 31, 2022, 2021, and 2020, respectively. Suspended Well Costs The Company did not incur any exploratory well costs during the years ended December 31, 2022, 2021, and 2020. Reserves The proved reserve estimates at December 31, 2022, 2021, and 2020 were prepared by Ryder Scott, our third-party independent reserve engineers. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes, and other factors. All of the Company’s oil, natural gas, and natural gas liquids reserves are attributable to properties within the United States. A summary of the Company’s changes in quantities of proved oil, natural gas, and natural gas liquids reserves for the years ended December 31, 2022, 2021, and 2020 are as follows:
________________________ (1)During the years ended December 31, 2022, 2021, and 2020, horizontal development resulted in extensions, discoveries, and other additions of 27.9 MMBoe, nominal MMBoe, and 18.0 MMBoe, respectively. (2)During the years ended December 31, 2022, 2021, and 2020, proved undeveloped reserves were reduced by 0.2 MMBoe, 24.1 MMBoe, and 22.9 MMBoe respectively, primarily due to the removal of proved undeveloped locations from our five-year drilling program. (3)As of December 31, 2022, the Company revised its proved reserves upward by 25.4 MMBoe. Price-related revisions of 11.8 MMBoe resulted from the increase to SEC prices of $27.11 to $93.67 per Bbl WTI for oil and $2.76 to $6.36 per MMBtu HH for natural gas. The remaining positive revisions of 13.6 MMBoe are primarily driven by updates to well performance forecasts and NGL yields. As of December 31, 2021, the Company revised its proved reserves downward by 20.0 MMBoe primarily driven by 13.1 MMBoe in negative revisions due to changes in well operating cost methodology, 6.9 MMBoe in negative engineering revisions, and 7.1 MMBoe in negative revisions for fuel gas, interest, shrink, and other minor revisions. The commodity prices at December 31, 2021 increased to $66.56 per Bbl WTI and $3.60 per MMBtu HH from $39.57 per Bbl WTI and $1.99 per MMBtu HH at December 31, 2020, resulting in a partially offsetting positive revision of 7.1 MMBoe. As of December 31, 2020, the Company revised its proved reserves upward by 7.5 MMBoe primarily driven by 12.3 MMBoe in positive engineering revisions. The commodity prices at December 31, 2020 decreased to $39.57 per Bbl WTI and $1.99 per MMBtu HH from $55.85 per Bbl WTI and $2.58 per MMBtu HH at December 31, 2019, resulting in a partially offsetting negative revision of 4.8 MMBoe. The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves were prepared in accordance with authoritative accounting guidance. Future cash inflows were computed by applying prices to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year-end, based on current costs and assuming continuation of existing economic conditions. Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows relating to proved oil and natural gas reserves. Future income tax expenses give effect to permanent differences, tax credits, and loss carryforwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value or the present value of the Company’s oil and natural gas properties. The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows (in thousands):
Future cash flows as shown above were reported without consideration for the effects of derivative transactions outstanding at period end. The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows (in thousands): The average wellhead prices used in determining future net revenues related to the standardized measure calculation as of December 31, 2022, 2021, and 2020 were calculated using the twelve-month arithmetic average of first-day-of-the-month prices inclusive of adjustments for quality and location.
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SUBSEQUENT EVENTS |
12 Months Ended |
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Dec. 31, 2022 | |
| Subsequent Events [Abstract] | |
| SUBSEQUENT EVENTS | SUBSEQUENT EVENTSOn January 24, 2023, the Company entered into a privately-negotiated share purchase agreement with CPPIB Crestone Peak Resources Canada Inc. for the purchase of approximately 4.9 million shares of the Company’s common stock at $61.00 per share for a total purchase price of approximately $300 million. The purchase closed on January 27, 2023 and was funded from the Company’s cash on hand. |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) |
12 Months Ended |
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Dec. 31, 2022 | |
| Accounting Policies [Abstract] | |
| Basis of Presentation | Basis of Presentation The accompanying consolidated financial statements include the accounts of the Company and have been prepared in accordance with GAAP, the instructions to Form 10-K, and Regulation S-X. All significant intercompany balances and transactions have been eliminated in consolidation. Additionally, certain prior period amounts have been reclassified to conform to current period presentation in the accompanying financial statements. During the current year, the Company is presenting inventory of oilfield equipment within prepaid expenses and other on the accompanying balance sheets. Accordingly, prior year amounts have been reclassified from inventory of oilfield equipment to prepaid expenses and other assets to conform to current year presentation. In connection with the preparation of the accompanying consolidated financial statements, the Company evaluated events subsequent to the balance sheet date of December 31, 2022, through the filing date of this report.
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| Use of Estimates | Use of EstimatesThe preparation of the consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities and commitments as of the date of our financial statements. Actual results could differ from those estimates. |
| Cash and Cash Equivalents | Cash and Cash Equivalents The Company considers all highly liquid investments with original maturity dates of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximate fair value due to the short-term nature of these instruments. The Company maintained cash balances in excess of federal deposit insurance limits as of December 31, 2022 and 2021, potentially subjecting the Company to a concentration of credit risk. To mitigate this risk, we maintain our cash and cash equivalents in the form of money market deposit and checking accounts with financial institutions that we believe are creditworthy and are also lenders under our Credit Facility.
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| Accounts Receivable | Accounts ReceivableThe Company’s accounts receivable primarily consists of receivables due from purchasers of the Company’s oil, natural gas, and NGL production and from joint interest owners on properties the Company operates. The Company is exposed to credit risk in the event of nonpayment by the purchasers of its production and joint interest owners, nearly all of which are concentrated in energy-related industries. The Company continuously evaluates the creditworthiness of its purchasers and joint interest owners. Generally, the Company’s oil, natural gas, and NGLs receivables are collected within to two months. For receivables due from joint interest owners, the Company generally has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. The Company has historically experienced minimal bad debts. |
| Property and Equipment | Property and Equipment Proved Properties. The Company accounts for its oil and natural gas properties under the successful efforts method of accounting. Under this method, the costs of development wells are capitalized to proved properties whether those wells are successful or unsuccessful. Capitalized drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities, are depleted using the units-of-production method based on estimated proved developed reserves. Proved leasehold costs are also depleted; however, the units-of-production method is based on estimated total proved reserves. The computation of depletion expense takes into consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging equipment. Because all of our proved properties are currently located in a single basin, we apply depletion on a single-basin basis. During the years ended December 31, 2022, 2021, and 2020, the Company incurred depletion expense of $773.5 million, $212.5 million, and $82.6 million, respectively. The Company assesses proved properties for impairment whenever events or circumstances indicate that their carrying value may not be recoverable. If carrying values exceed undiscounted future net cash flows, impairment is measured and recorded at fair value. Due to a lack of quoted market prices for proved properties, the Company estimates the fair value using valuation techniques that convert estimated future net cash flows to a single discounted amount. Significant inputs and assumptions to this estimation include, but are not limited to, reserves volumes, future operating and development costs, future commodity prices, inclusive of applicable differentials, and a market-based weighted average cost of capital rate. The expected future cash flows used for impairment reviews include future production volumes associated with proved developed producing reserves and risk-adjusted proved undeveloped reserves as well as risk-adjusted probable and possible reserves, as applicable. The partial sale of a proved property within an existing field is accounted for as a normal retirement and no net gain or loss on divestiture activity is recognized as long as such treatment does not significantly affect the units-of-production depletion rate. The sale of a partial interest in an individual proved property is accounted for as a recovery of cost. A net gain or loss on divestiture activity is recognized in the accompanying statements of operations for all other sales of proved properties. As of December 31, 2022 and 2021, the net book value of the Company’s midstream assets in the accompanying balance sheets was $326.8 million and $276.1 million, respectively. Depreciation on the Company’s midstream assets is calculated using the straight-line method over the estimated useful lives of the assets and properties they serve, which is approximately 30 years. Unproved Properties. Unproved properties consist of the costs to acquire undeveloped leases and are not subject to depletion until they are transferred to proved properties. Leasehold costs are transferred to proved properties on an ongoing basis as the properties to which they relate are evaluated and proved reserves established. Additional costs not subject to depletion include costs associated with development wells in progress or awaiting completion at year-end. These costs are transferred into costs subject to depletion on an ongoing basis as these wells are completed and proved reserves are established or confirmed. Unproved properties are routinely evaluated for continued capitalization or impairment. On a quarterly basis, management assesses undeveloped leasehold costs for impairment by considering, among other things, remaining lease terms, future drilling plans and capital availability to execute such plans, commodity price outlooks, recent operational results, reservoir performance and geology, and estimated acreage value based on prices received for similar, recent acreage transactions by the Company or other market participants. Changes in our assumptions of the estimated nonproductive portion of our undeveloped leases could result in additional impairment expense. The partial sale of unproved property is accounted for as a recovery of cost when there is uncertainty of the ultimate recovery of the cost applicable to the interest retained. Exploratory. Exploratory geological and geophysical, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage are expensed as incurred. Under the successful efforts method of accounting, exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are found, exploratory well costs will be capitalized as proved properties. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. The application of the successful efforts method of accounting requires judgment to determine the proper designation of wells as either development or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes. Once a well is drilled, the determination that economic proved reserves have been discovered may take considerable time and judgment. Exploratory dry hole costs are included in the cash flows from investing activities section as part of exploration and development of oil and natural gas properties within the accompanying statements of cash flows. Oil and Natural Gas Reserves. The successful efforts method of accounting inherently relies on the estimation of proved oil and natural gas reserves. Reserve quantities and the related estimates of future net cash flows are critical inputs in our calculation of units-of-production depletion and our evaluation of proved and unproved properties for impairment. The process of estimating and evaluating crude oil and natural gas reserves is complex, requiring the evaluation of available geological, geophysical, engineering, and economic data to estimate underground accumulations of oil and natural gas that cannot be precisely measured. Consequently, the Company engages third-party independent reserve engineers Ryder Scott to prepare our estimates of oil and natural gas reserves. Significant inputs and engineering assumptions used in developing the estimates of proved oil and natural gas reserves include reserves volumes, future operating and development costs, historical commodity prices, and the Company’s ability to convert proved undeveloped reserves to producing properties within five years of their initial proved booking. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history, and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur. We cannot predict the amounts or timing of such future revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in impairment of proved property.
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| Other Property and Equipment | Other Property and Equipment Other property and equipment such as office furniture and equipment, buildings, and computer hardware and software are recorded at cost. Cost of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed as incurred. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets, which range from to 25 years.
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| Leases | LeasesThe Company determines if an arrangement is representative of a lease at contract inception. Right-of-use assets represent our right to use the underlying assets for the lease term and the corresponding lease liabilities represent our obligations to make lease payments arising from the leases. Right-of-use assets and lease liabilities are recognized at the lease commencement date based on the present value of the lease payments over the lease term. When evaluating a contract, the Company applies certain judgments to determine, among other factors, lease classification as either operating or financing, lease term, and discount rate. The terms of certain of our leases include options to extend or terminate the lease, only when we can ascertain that it is reasonably certain we will exercise that option, as well as evergreen periods for which the penalties associated with termination are considered to be significant. Leases with an initial term of one year or less are not recorded on the accompanying balance sheets. As the Company does not have any leases with an implicit interest rate that can be readily determined, we utilize our incremental borrowing rate based on information available at the lease commencement date in determining the present value of lease payments. We determine our incremental borrowing rate at the lease commencement date using our Credit Facility benchmark rate and make adjustments for facility utilization and lease term. Subsequent measurement, as well as presentation of expenses and cash flows, is dependent upon the classification of the lease as either an operating or finance lease. |
| Carbon Offsets and Renewable Energy Credits | Carbon Offsets and Renewable Energy Credits The Company periodically purchases carbon offsets and renewable energy credits as a means to offset carbon emissions generated by its operations and purchased electricity that could not otherwise be reduced or eliminated. Commensurate with their use, purchased carbon offsets and renewable energy credits are initially capitalized at cost as an intangible asset within other noncurrent assets on the accompanying balance sheets. Subsequently, capitalized carbon offsets and renewable energy credits are expensed when applied to the Company’s carbon emissions through depletion, depreciation, and amortization expense on the accompanying statements of operations. Purchased carbon offsets and renewable energy credits expected to be utilized within the next 12 months are presented as short-term within prepaid expenses and other on the accompanying balance sheets.
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| Deferred Financing Costs | Deferred Financing Costs Deferred financing costs include origination, legal, and other fees incurred to issue debt or amend existing credit facilities. Deferred financing costs related to the Credit Facility are capitalized to prepaid expenses and other and other noncurrent assets on the accompanying balance sheets and amortized to interest expense, net on the accompanying statements of operations on a straight-line basis over the life of the Credit Facility. Deferred financing costs related to senior notes are capitalized within senior notes on the accompanying balance sheets and amortized to interest expense, net on the accompanying statements of operations using the effective interest method over the life of the respective borrowings.
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| Asset Retirement Obligations | Asset Retirement Obligations The Company recognizes an asset retirement obligation at fair value based on the present value of costs expected to be incurred in connection with the future abandonment of its oil and natural gas properties, including wells and facilities, in accordance with applicable regulatory requirements. This obligation, and the corresponding capitalized cost recorded to proved properties, is recorded at the time assets are acquired, a well is completed and begins production, or a facility is constructed. The Company recognizes a periodic expense in connection with the accretion of the discounted asset retirement obligation over the remaining estimated economic lives of the respective long-lived assets. The accretion expense is recorded as a component of depreciation, depletion, and amortization in our accompanying statements of operations. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the corresponding capitalized cost recorded to proved properties. The recognition of an asset retirement obligation requires management to make various assumptions informed by historical experience and applicable regulatory requirements including estimated plugging and abandonment costs, economic lives, inflation rates, and the Company’s credit-adjusted risk-free rate. Cash paid to settle asset retirement obligations is included in the cash flows from operating activities section of the accompanying statements of cash flows.
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| Derivatives | Derivatives The Company periodically enters into commodity price derivative instruments to mitigate a portion of its exposure to potentially adverse market changes in commodity prices for its expected future oil and natural gas production and the associated impact on cash flows. These instruments typically include commodity price swaps and collars. The oil instruments are indexed to NYMEX WTI prices, and natural gas instruments are indexed to NYMEX HH and CIG prices, all of which have a high degree of historical correlation with actual prices received by the Company, before differentials. As of December 31, 2022, all derivative counterparties were members of the Credit Facility lender group and all commodity derivative contracts are entered into for other-than-trading purposes. The Company does not designate its commodity derivative contracts as hedging instruments. Commodity price derivative instruments are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities, with the exception of derivative instruments that meet the “normal purchase normal sale” exclusion. The Company measures the fair value of its commodity price derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates, volatility factors, and nonperformance risk. Changes in the fair value of the Company’s commodity price derivative instruments are recorded in the accompanying statements of operations as they occur. As of December 31, 2022 and 2021, all derivative instruments held by the Company were subject to master netting arrangements with various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between it and the counterparty, at the election of both parties, for transactions that settle on the same date and in the same currency. The Company’s agreements also provide that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to not offset these positions in its accompanying balance sheets.Derivative (gain) loss as well as derivative cash settlement gain (loss) are included within the cash flows from operating activities section of the accompanying statements of cash flows.
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| Revenue Recognition | Revenue Recognition The Company recognizes revenue from the sale of produced oil, natural gas, and NGL at the point in time when control of produced oil, natural gas, or NGL volumes transfer to the purchaser, which may differ depending on the applicable contractual terms. The Company considers the transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the oil, natural gas, or NGL production. Transfer of control dictates the presentation of gathering, transportation, and processing expenses within the accompanying statements of operations. Gathering, transportation, and processing expenses incurred by the Company prior to the transfer of control are recorded gross within gathering, transportation, and processing in the accompanying statements of operations. Conversely, gathering, transportation, and processing expenses incurred by the Company subsequent to the transfer of control are recorded net within oil, natural gas, and NGL sales on the accompanying statements of operations. Oil sales. Under the Company’s crude purchase and marketing contracts, the Company typically delivers production at the wellhead, or other contractually agreed-upon delivery points, and collects an agreed-upon index price, net of pricing differentials. In this scenario, the Company recognizes revenue when control of its oil production transfers to the purchaser at the wellhead, or other contractually agreed-upon delivery point, at the net contracted price received. Natural gas and NGL sales. Under the Company’s natural gas processing contracts, the Company delivers natural gas to a midstream processing provider at the wellhead, inlet of the midstream processing provider’s system, or other contractually agreed-upon delivery points. The delivery points are specified within each contract, and the point at which control transfers varies between the inlet and tailgate of the midstream processing facility. The midstream processing provider gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs and residue gas. For the contracts where the Company maintains control through the tailgate of the midstream processing facility, the Company recognizes revenue on a gross basis, with gathering, transportation, and processing fees presented as an expense in the accompanying statements of operations. Alternatively, for those contracts where the Company relinquishes control at the inlet of the midstream processing facility, the Company recognizes natural gas and NGL revenues based on the contracted amount of the proceeds received from the midstream processing entity and, as a result, the Company recognizes revenue on a net basis. In certain natural gas processing agreements, the Company may elect to take its residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the Company delivers product to the third-party purchaser at a contractually agreed-upon delivery point and receives a specified index price from the third-party purchaser. In this scenario, the Company recognizes revenue when the control transfers to the third-party purchaser at the delivery point based on the index price received from the third-party purchaser. The gathering and processing expense attributable to the natural gas processing contracts, as well as any transportation expense incurred to deliver the product to the third-party purchaser, are presented as gathering, transportation, and processing expense in the consolidated statements of operations. The Company records revenue in the month production is delivered and control is transferred to the purchaser. However, settlement statements and payment may not be received for 30 to 60 days after the date production is delivered and control is transferred. Until such time settlement statements and payment are received, the Company records a revenue accrual based on, amongst other factors, an estimate of the volumes delivered at estimated prices as determined by the applicable contractual terms. The Company records the differences between its estimates and the actual amounts received for product sales in the month in which payment is received from the purchaser.
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| Stock-Based Compensation | Stock-Based CompensationThe Company recognizes stock-based compensation based on the grant-date fair value of the equity instruments awarded. Stock-based compensation expense is recognized in the financial statements on a straight-line basis over the requisite service period for the entire award. The Company accounts for forfeitures of stock-based compensation awards as they occur. |
| Income Taxes | Income Taxes The Company accounts for income taxes under the asset and liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the balance sheet or tax returns. Deferred income tax assets and liabilities are measured using enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. If we determine that it is more-likely-than-not that some portion or all of the deferred income tax assets will not be realized, a valuation allowance is recorded, thereby reducing the deferred income tax assets to what is considered to be realizable. The Company recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The Company’s policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. There were no uncertain tax positions during any period presented.
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| Earnings Per Share | Earnings Per ShareThe Company uses the treasury stock method to determine the effect of potentially dilutive instruments. |
| Acreage Exchanges | Acreage Exchanges From time to time, we enter into acreage exchanges in order to consolidate our core acreage positions, enabling us to have more control over the timing of development activities, achieve higher working interests and provide us the ability to drill longer lateral length wells within those core areas. We account for our nonmonetary acreage exchanges in accordance with the guidance prescribed by Accounting Standards Codification (“ASC”) 845, Nonmonetary Transactions. For those exchanges that lack commercial substance, we record the acreage received at the net carrying value of the acreage surrendered to obtain it. For those acreage exchanges that are deemed to have commercial substance, we record the acreage received at fair value, with a related gain or loss recognized within gain (loss) on property transactions, net in the accompanying statements of operations, in accordance with ASC 820, Fair Value Measurement.
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| Business Combinations | Business CombinationsAs part of our business strategy, we regularly pursue the acquisition of oil and natural gas properties. We utilize the acquisition method to account for acquisitions of businesses. Pursuant to this method, we allocate the cost of the acquisition, or purchase price, to assets acquired and liabilities assumed based on fair values as of the acquisition date. |
| Fair Value of Financial Instruments | Fair Value of Financial Instruments The Company’s financial instruments consist of cash and cash equivalents, accounts receivables, and accounts payable and are carried at cost, which approximates fair value due to the short-term maturity of these instruments. As discussed above, the Company’s commodity price derivative instruments are recorded at fair value. The Company’s Senior Notes, as defined in Note 5 – Long-Term Debt, are recorded at cost, net of any unamortized deferred financing costs, and their respective fair values are disclosed in Note 8 – Fair Value Measurements. The recorded value of the Company’s Credit Facility, as defined in Note 5 – Long-Term Debt, approximates its fair value as it bears interest at a floating rate that approximates a current market rate. The Company’s warrants were recorded at fair value upon issuance, with no recurring fair value measurement required. Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would realize upon the sale or refinancing of such instruments.
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| Recently Issued and Adopted Accounting Standards | Recently Issued and Adopted Accounting StandardsThere are no accounting standards applicable to the Company that would have a material effect on the Company’s financial statements and disclosures that have been issued but not yet adopted by the Company as of December 31, 2022, and through the filing date of this report. |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables) |
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| Accounting Policies [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedules of Concentrations of Credit Risk and Major Customers | For the periods presented below, the following purchasers of the Company’s production accounted for more than 10% of the Company’s revenue as follows:
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ACQUISITIONS AND DIVESTITURES (Tables) |
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| Business Combination and Asset Acquisition [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Merger Consideration and Purchase Price Allocation | The following tables present the merger consideration and final purchase price allocation of the assets acquired and the liabilities assumed in the HighPoint Merger:
_________________________ (1)Based on the number of shares of common stock of HighPoint issued and outstanding as of April 1, 2021 and the conversion ratio of 0.11464 per share of Civitas Common Stock. (2)Based on the closing stock price of Civitas Common Stock on April 1, 2021.
_________________________ (1)Based on the number of shares of common stock of Extraction issued and outstanding as of November 1, 2021 and the conversion ratio of 1.1711 per share of Civitas Common Stock. (2)Based on the closing stock price of Civitas Common Stock on November 1, 2021.
(1)Based on the closing stock price of Civitas Common Stock on November 1, 2021.
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| Schedule of Pro Forma Financial Information | The following unaudited pro forma financial information (in thousands, except per share amounts) represents a summary of the consolidated results of operations for the year ended December 31, 2021 and 2020, assuming the HighPoint, Extraction, and Crestone Peak mergers had been completed as of January 1, 2020. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the mergers had been effective as of this date, or of future results, and includes certain non-recurring pro forma adjustments that were directly attributable to the business combinations (in thousands, except per share amounts).
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REVENUE RECOGNITION (Tables) |
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| Schedule of Disaggregation of Revenue | Revenue attributable to each identified revenue stream is disaggregated below (in thousands):
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ACCOUNTS PAYABLE AND ACCRUED EXPENSES (Tables) |
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| Payables and Accruals [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Accounts Payable and Accrued Expenses | Accounts payable and accrued expenses contain the following (in thousands):
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LONG-TERM DEBT (Tables) |
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Dec. 31, 2022 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Debt Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Long-term Debt Instruments | The tables below present the related carrying values as of December 31, 2022 and December 31, 2021 (in thousands):
The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Credit Facility as of the dates indicated (in thousands):
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COMMITMENTS AND CONTINGENCIES (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2022 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Commitments and Contingencies Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Annual Minimum Commitment Payments | The minimum annual payments under the these agreements for the next five years as of December 31, 2022 are presented below (in thousands):
___________________________ (1)The above calculation is based on the minimum volume commitment schedule (as defined in the relevant agreement) and applicable differential fees.
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STOCK-BASED COMPENSATION (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2022 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Share-Based Payment Arrangement [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Summary of Share-Based Compensation Expense | The following table outlines the compensation expense recorded by type of award (in thousands):
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| Summary of Unrecognized Compensation Expense and Vesting Criterion | As of December 31, 2022, unrecognized compensation expense related to the awards granted under the LTIP will be amortized through the relevant periods as follows (in thousands):
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| Summary of the Status and Activity of Non-Vested RSUs, DSUs, and Options | A summary of the status and activity of non-vested RSUs and DSUs for the year ended December 31, 2022 is presented below:
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| Schedule of Assumptions | The following table presents the range of assumptions used to determine the fair value of the PSUs with market-based settlement criteria as granted under the LTIP throughout each of the periods presented:
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| Summary of the Status and Activity of PSUs | A summary of the status and activity of non-vested PSUs for the year ended December 31, 2022 is presented below:
___________________________ (1)The number of awards assumes that the associated performance condition is met at the target amount (multiplier of one). The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the performance condition.
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FAIR VALUE MEASUREMENTS (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2022 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Fair Value Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Financial Assets and Liabilities at Fair Value on Recurring Basis | The following tables present the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2022 and 2021 and their classification within the fair value hierarchy (in thousands):
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DERIVATIVES (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2022 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Commodity Derivatives | As of December 31, 2022, the Company had entered into the following commodity price derivative contracts:
Subsequent to December 31, 2022, the Company entered into a series of fixed price, natural gas basis protection swaps on all of its outstanding NYMEX HH positions through the third quarter of 2024 to mitigate exposure to adverse pricing differentials between NYMEX HH and CIG. The weighted-average contract price entered of $(0.13) per MMBtu represents the amount of reduction to the NYMEX HH natural gas price for the contracted volumes covered by the basis protection swaps.
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| Summary of all the Company's Derivative Positions | The following table contains a summary of all the Company’s derivative positions reported on the accompanying balance sheets as well as a reconciliation between the gross assets and liabilities and the potential effects of master netting arrangements on the fair value of the Company’s commodity derivative contracts as of December 31, 2022 and 2021 (in thousands):
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| Summary of the Components of the Derivative Gain (Loss) | The following table summarizes the components of the derivative gain (loss) presented on the accompanying statements of operations for the periods below (in thousands):
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ASSET RETIREMENT OBLIGATIONS (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2022 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Asset Retirement Obligation Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Asset Retirement Obligation Changes | A roll-forward of the Company’s asset retirement obligation is as follows (in thousands):
___________________________ (1)Revisions to estimates for the year ended December 31, 2022 and 2021 were primarily a result of increases in the Company’s estimated plugging and abandonment cost.
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EARNINGS PER SHARE (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2022 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Earnings Per Share [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Earnings Per Share | The following table sets forth the calculations of basic and diluted net income per common share (in thousands, except per share amounts):
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INCOME TAXES (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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| Income Tax Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Provision for Income Taxes | The provision for income taxes consists of the following (in thousands):
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| Schedule of Temporary Differences, Deferred Tax Assets and Liabilities | Temporary differences between the financial statement carrying amounts and tax basis of assets and liabilities that give rise to the net deferred tax liability and asset result from the following components (in thousands):
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| Schedule of Federal Net Operating Loss Carryforwards Acquired and Deferred Tax Assets and Liabilities from Mergers | The following table outlines the Federal net operating loss (“NOL”) carryforwards acquired and deferred tax assets and liabilities recorded as a result of the mergers that closed in 2021 (in millions):
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| Schedule of Amount of Effective Income Tax Rate Reconciliation | Recorded income tax expense or benefit differs from the amount that would be provided by applying the statutory United States federal income tax rate of 21% to income before income taxes. These differences primarily relate to the effect of state income taxes, excess tax benefits and deficiencies on stock-based compensation awards, tax limitations on compensation of covered individuals, changes in valuation allowances, and other permanent differences, as follows (in thousands):
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LEASES (Tables) |
12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2022 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Leases [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Balance Sheet Activity, Asset Classes | The Company’s right-of-use assets and lease liabilities are recognized on the accompanying balance sheets based on the present value of the expected lease payments over the lease term. As of December 31, 2022 and 2021, the Company did not have any agreements in place that were classified as finance leases. The following table summarizes the asset classes of the Company’s operating leases (in thousands):
____________________________ (1)Includes compressors, certain natural gas processing equipment, and other field equipment.
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| Summary of Operating Lease Costs and Summary of Supplemental Cash Flow Information | The following table summarizes the components of the Company’s gross lease costs incurred for the periods below (in thousands):
___________________________ (1)Includes office rent expense of $4.3 million, $2.2 million, and $1.1 million for the years ended December 31, 2022, 2021, and 2020, respectively. (2)Includes drilling rigs and other equipment. Short-term drilling rig costs include a non-lease labor component, which is treated as a single lease component. (3)The Company subleased a portion of one of its office spaces for the remainder of the office lease term (4)Variable lease costs represent differences between lease obligations and actual costs incurred for certain leases that do not have fixed payments related to both lease and non-lease components. Such incremental costs include lease payment increases or decreases driven by market price fluctuations and leased asset maintenance costs.Variable lease costs were not material for the years ended December 31, 2022, 2021, and 2020.
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| Schedule of Weighted-Average Information | The Company’s weighted-average remaining lease terms and discount rates as of December 31, 2022 are as follows:
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| Schedule of Future Minimum Commitments for Operating Leases | Future commitments by year for the Company’s leases with a lease term of one year or more as of December 31, 2022 are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the accompanying balance sheets as follows (in thousands):
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SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION (Tables) |
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Dec. 31, 2022 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Supplemental Cash Flow Information | Supplemental cash flow disclosures are presented below (in thousands):
(1)Includes $542.6 million, $2.1 billion, and $2.3 billion in non-cash property additions related to the HighPoint, Extraction, and Crestone Peak mergers, respectively, for the year ended December 31, 2021. (2)Includes $374.9 million, $1.8 billion, and $1.3 billion in non-cash consideration related to the HighPoint, Extraction, and Crestone Peak mergers, respectively, for the year ended December 31, 2021.
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DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Tables) |
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| Results of Operations, Revenue from Oil and Gas Producing Activities [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Schedule of Costs Incurred in Oil and Natural Gas Producing Activities | Costs incurred in the acquisition, development, and exploration of oil and natural gas properties, whether capitalized or expensed, are summarized below (in thousands):
(1)Acquisition costs for unproved properties for the years ended December 31, 2022, 2021, and 2020 were $16.8 million, $648.0 million, and $2.3 million, respectively. There were $420.3 million, $4.2 billion, and $9.0 million in acquisition costs for proved properties for the years ended December 31, 2022, 2021, and 2020, respectively. (2)Development costs include workover costs of $8.6 million, $2.2 million, and $1.2 million charged to lease operating expense for the years ended December 31, 2022, 2021, and 2020, respectively. (3)Includes amounts relating to asset retirement obligations of $64.7 million, $13.8 million, and $(1.0) million for the years ended December 31, 2022, 2021, and 2020, respectively.
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| Summary of BCEI's Changes in Quantities of Proved Oil, Natural Gas Liquids and Natural Gas Liquids Reserves | A summary of the Company’s changes in quantities of proved oil, natural gas, and natural gas liquids reserves for the years ended December 31, 2022, 2021, and 2020 are as follows:
________________________ (1)During the years ended December 31, 2022, 2021, and 2020, horizontal development resulted in extensions, discoveries, and other additions of 27.9 MMBoe, nominal MMBoe, and 18.0 MMBoe, respectively. (2)During the years ended December 31, 2022, 2021, and 2020, proved undeveloped reserves were reduced by 0.2 MMBoe, 24.1 MMBoe, and 22.9 MMBoe respectively, primarily due to the removal of proved undeveloped locations from our five-year drilling program. (3)As of December 31, 2022, the Company revised its proved reserves upward by 25.4 MMBoe. Price-related revisions of 11.8 MMBoe resulted from the increase to SEC prices of $27.11 to $93.67 per Bbl WTI for oil and $2.76 to $6.36 per MMBtu HH for natural gas. The remaining positive revisions of 13.6 MMBoe are primarily driven by updates to well performance forecasts and NGL yields. As of December 31, 2021, the Company revised its proved reserves downward by 20.0 MMBoe primarily driven by 13.1 MMBoe in negative revisions due to changes in well operating cost methodology, 6.9 MMBoe in negative engineering revisions, and 7.1 MMBoe in negative revisions for fuel gas, interest, shrink, and other minor revisions. The commodity prices at December 31, 2021 increased to $66.56 per Bbl WTI and $3.60 per MMBtu HH from $39.57 per Bbl WTI and $1.99 per MMBtu HH at December 31, 2020, resulting in a partially offsetting positive revision of 7.1 MMBoe. As of December 31, 2020, the Company revised its proved reserves upward by 7.5 MMBoe primarily driven by 12.3 MMBoe in positive engineering revisions. The commodity prices at December 31, 2020 decreased to $39.57 per Bbl WTI and $1.99 per MMBtu HH from $55.85 per Bbl WTI and $2.58 per MMBtu HH at December 31, 2019, resulting in a partially offsetting negative revision of 4.8 MMBoe.
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| Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves | The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows (in thousands):
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| Schedule of Changes in the Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves | The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows (in thousands):
|
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| Schedule of Average Wellhead Prices Used in Determining Future Net Revenues Related to Standardized Measure Calculation | The average wellhead prices used in determining future net revenues related to the standardized measure calculation as of December 31, 2022, 2021, and 2020 were calculated using the twelve-month arithmetic average of first-day-of-the-month prices inclusive of adjustments for quality and location.
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||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Narrative (Details) $ in Thousands |
12 Months Ended | ||
|---|---|---|---|
|
Dec. 31, 2022
USD ($)
segment
|
Dec. 31, 2021
USD ($)
|
Dec. 31, 2020
USD ($)
|
|
| Property, Plant and Equipment [Line Items] | |||
| Number of operating segments | segment | 1 | ||
| Depletion expense | $ 773,500 | $ 212,500 | $ 82,600 |
| Proved properties | $ 6,774,635 | 5,457,213 | |
| Minimum | |||
| Property, Plant and Equipment [Line Items] | |||
| Receivable collection period | 1 month | ||
| Maximum | |||
| Property, Plant and Equipment [Line Items] | |||
| Receivable collection period | 2 months | ||
| Midstream Assets | |||
| Property, Plant and Equipment [Line Items] | |||
| Proved properties | $ 326,800 | $ 276,100 | |
| PP&E useful life | 30 years | ||
| Property, Plant and Equipment, Other Types | Minimum | |||
| Property, Plant and Equipment [Line Items] | |||
| PP&E useful life | 3 years | ||
| Property, Plant and Equipment, Other Types | Maximum | |||
| Property, Plant and Equipment [Line Items] | |||
| PP&E useful life | 25 years | ||
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Concentrations of Credit Risk (Details) - Sales - Customer Concentration Risk |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2022 |
Dec. 31, 2021 |
Dec. 31, 2020 |
|
| Customer A | |||
| Concentration Risk [Line Items] | |||
| Percent of oil and natural gas sales | 50.00% | 43.00% | 77.00% |
| Customer B | |||
| Concentration Risk [Line Items] | |||
| Percent of oil and natural gas sales | 12.00% | 2.00% | 0.00% |
| Customer C | |||
| Concentration Risk [Line Items] | |||
| Percent of oil and natural gas sales | 10.00% | 13.00% | 9.00% |
| Customer D | |||
| Concentration Risk [Line Items] | |||
| Percent of oil and natural gas sales | 6.00% | 15.00% | 0.00% |
ACQUISITIONS AND DIVESTITURES - Narrative (Details) $ / shares in Units, shares in Thousands, $ in Thousands |
12 Months Ended | ||||||
|---|---|---|---|---|---|---|---|
|
Jul. 05, 2022
USD ($)
|
Mar. 01, 2022
USD ($)
|
Nov. 01, 2021
USD ($)
$ / shares
shares
|
Apr. 01, 2021
USD ($)
shares
|
Dec. 31, 2022
USD ($)
|
Dec. 31, 2021
USD ($)
|
Dec. 31, 2020
USD ($)
|
|
| Business Acquisition [Line Items] | |||||||
| Business combination, bargain purchase, gain recognized, statement of income or comprehensive income, extensible enumeration not disclosed flag | bargain purchase gain | ||||||
| Merger transaction costs | $ 24,683 | $ 43,555 | $ 6,676 | ||||
| Payments to acquire non-operated interests in operated wells | $ 80,700 | ||||||
| HighPoint | |||||||
| Business Acquisition [Line Items] | |||||||
| Exchange ratio | 0.11464 | ||||||
| Common stock, shares issued (in shares) | shares | 9,802 | ||||||
| Aggregate principal amount | $ 100,000 | ||||||
| Revenue, included in statement of operations | $ 244,700 | ||||||
| Consideration transferred | 474,933 | ||||||
| Net assets acquired | $ 474,933 | ||||||
| HighPoint | Measurement Input, Discount Rate | Valuation Technique, Discounted Cash Flow | |||||||
| Business Acquisition [Line Items] | |||||||
| Proved oil and gas properties, measurement input | 0.13 | ||||||
| HighPoint | Former HighPoint Stockholders | |||||||
| Business Acquisition [Line Items] | |||||||
| Common stock, shares issued (in shares) | shares | 488 | ||||||
| HighPoint | Holders of HighPoint Senior Notes | |||||||
| Business Acquisition [Line Items] | |||||||
| Common stock, shares issued (in shares) | shares | 9,314 | ||||||
| HighPoint | Senior Notes | Senior Notes Due 2026, 7.50% | |||||||
| Business Acquisition [Line Items] | |||||||
| Interest rate (as a percent) | 7.50% | 7.50% | |||||
| Extraction | |||||||
| Business Acquisition [Line Items] | |||||||
| Exchange ratio | 1.1711 | ||||||
| Revenue, included in statement of operations | $ 172,300 | ||||||
| Consideration transferred | $ 1,844,129 | ||||||
| Net assets acquired | $ 1,844,129 | ||||||
| Extraction | Measurement Input, Discount Rate | Valuation Technique, Discounted Cash Flow | |||||||
| Business Acquisition [Line Items] | |||||||
| Proved oil and gas properties, measurement input | 0.10 | ||||||
| Extraction | Former Extraction Stockholders | |||||||
| Business Acquisition [Line Items] | |||||||
| Common stock, shares issued (in shares) | shares | 31,100 | ||||||
| Extraction | Tranche A Warrants | |||||||
| Business Acquisition [Line Items] | |||||||
| Warrants issued (in shares) | shares | 3,400 | ||||||
| Price per warrant (in dollars per share) | $ / shares | $ 91.91 | ||||||
| Extraction | Tranche B Warrants | |||||||
| Business Acquisition [Line Items] | |||||||
| Warrants issued (in shares) | shares | 1,700 | ||||||
| Price per warrant (in dollars per share) | $ / shares | $ 104.45 | ||||||
| Crestone Peak | |||||||
| Business Acquisition [Line Items] | |||||||
| Exchange ratio, collective number of shares | shares | 22,500 | ||||||
| Revenue, included in statement of operations | $ 114,800 | ||||||
| Net assets acquired | $ 1,262,250 | ||||||
| Crestone Peak | Measurement Input, Discount Rate | Valuation Technique, Discounted Cash Flow | |||||||
| Business Acquisition [Line Items] | |||||||
| Proved oil and gas properties, measurement input | 0.10 | ||||||
| Bison | |||||||
| Business Acquisition [Line Items] | |||||||
| Consideration transferred | $ 280,400 | ||||||
| Net assets acquired | 294,000 | ||||||
| Bargain purchase gain | $ 13,600 | ||||||
ACQUISITIONS AND DIVESTITURES - Merger Consideration (Details) $ / shares in Units, shares in Thousands, $ in Thousands |
Nov. 01, 2021
USD ($)
$ / shares
shares
|
Apr. 01, 2021
USD ($)
$ / shares
shares
|
Dec. 31, 2021 |
|---|---|---|---|
| HighPoint | |||
| Business Acquisition [Line Items] | |||
| Common stock, shares issued (in shares) | shares | 9,802 | ||
| Closing price per share of Civitas Common Stock (in dollars per share) | $ / shares | $ 38.25 | ||
| Merger consideration paid in shares of Civitas Common Stock | $ 374,933 | ||
| Aggregate principal amount of the 7.5% Senior Notes | 100,000 | ||
| Total merger consideration | $ 474,933 | ||
| Exchange ratio | 0.11464 | ||
| HighPoint | Senior Notes Due 2026, 7.50% | Senior Notes | |||
| Business Acquisition [Line Items] | |||
| Interest rate (as a percent) | 7.50% | 7.50% | |
| HighPoint | Existing holders of HighPoint Common Stock | |||
| Business Acquisition [Line Items] | |||
| Common stock, shares issued (in shares) | shares | 488 | ||
| HighPoint | Existing holders of HighPoint Senior Notes | |||
| Business Acquisition [Line Items] | |||
| Common stock, shares issued (in shares) | shares | 9,314 | ||
| Extraction | |||
| Business Acquisition [Line Items] | |||
| Total merger consideration | $ 1,844,129 | ||
| Exchange ratio | 1.1711 | ||
| Extraction | Common Stock | |||
| Business Acquisition [Line Items] | |||
| Common stock, shares issued (in shares) | shares | 31,095 | ||
| Closing price per share of Civitas Common Stock (in dollars per share) | $ / shares | $ 56.10 | ||
| Merger consideration paid in shares of Civitas Common Stock | $ 1,744,431 | ||
| Extraction | Restricted Stock and Performance Restricted Stock as Share-Based Compensation, of Acquiree | |||
| Business Acquisition [Line Items] | |||
| Merger consideration paid in shares of Civitas Common Stock | 22,235 | ||
| Extraction | Restricted Stock as Share-Based Compensation, of Acquiree | |||
| Business Acquisition [Line Items] | |||
| Merger consideration paid in shares of Civitas Common Stock | 19,338 | ||
| Extraction | Performance Restricted Stock as Share-Based Compensation, of Acquiree | |||
| Business Acquisition [Line Items] | |||
| Merger consideration paid in shares of Civitas Common Stock | 2,897 | ||
| Extraction | Tranche A and Tranche B Warrants | |||
| Business Acquisition [Line Items] | |||
| Merger consideration paid in shares of Civitas Common Stock | 77,463 | ||
| Extraction | Tranche A Warrants | |||
| Business Acquisition [Line Items] | |||
| Merger consideration paid in shares of Civitas Common Stock | 52,164 | ||
| Extraction | Tranche B Warrants | |||
| Business Acquisition [Line Items] | |||
| Merger consideration paid in shares of Civitas Common Stock | $ 25,299 | ||
| Crestone Peak | Common Stock | |||
| Business Acquisition [Line Items] | |||
| Common stock, shares issued (in shares) | shares | 22,500 | ||
| Closing price per share of Civitas Common Stock (in dollars per share) | $ / shares | $ 56.10 | ||
| Merger consideration paid in shares of Civitas Common Stock | $ 1,262,250 |
ACQUISITIONS AND DIVESTITURES - Purchase Price Allocation (Details) - USD ($) $ in Thousands |
Dec. 31, 2021 |
Nov. 01, 2021 |
Apr. 01, 2021 |
|---|---|---|---|
| HighPoint | |||
| Assets Acquired | |||
| Cash and cash equivalents | $ 49,827 | ||
| Accounts receivable - oil, natural gas, and NGL sales | 26,343 | ||
| Accounts receivable - joint interest and other | 9,161 | ||
| Prepaid expenses and other | 3,608 | ||
| Inventory of oilfield equipment | 4,688 | ||
| Proved properties | 539,820 | ||
| Other property and equipment | 2,769 | ||
| Right-of-use assets | 4,010 | ||
| Deferred income tax assets | $ 110,500 | 110,513 | |
| Other noncurrent assets | 797 | ||
| Total assets acquired | 751,536 | ||
| Liabilities Assumed | |||
| Accounts payable and accrued expenses | 51,088 | ||
| Oil and natural gas revenue distribution payable | 20,786 | ||
| Lease liability | 4,010 | ||
| Derivative liability | 18,500 | ||
| Current portion of long-term debt | 154,000 | ||
| Ad valorem taxes | 3,746 | ||
| Asset retirement obligations | 24,473 | ||
| Total liabilities assumed | 276,603 | ||
| Net assets acquired | $ 474,933 | ||
| Extraction | |||
| Assets Acquired | |||
| Cash and cash equivalents | $ 106,360 | ||
| Accounts receivable - oil, natural gas, and NGL sales | 119,585 | ||
| Accounts receivable - joint interest and other | 33,054 | ||
| Prepaid expenses and other | 3,044 | ||
| Inventory of oilfield equipment | 9,291 | ||
| Derivative assets | 5,834 | ||
| Proved properties | 1,878,887 | ||
| Unproved properties | 193,400 | ||
| Other property and equipment | 40,068 | ||
| Right-of-use assets | 6,883 | ||
| Deferred income tax assets | 49,200 | 49,194 | |
| Other noncurrent assets | 4,248 | ||
| Total assets acquired | 2,449,848 | ||
| Liabilities Assumed | |||
| Accounts payable and accrued expenses | 90,353 | ||
| Production taxes payable | 63,572 | ||
| Oil and natural gas revenue distribution payable | 183,875 | ||
| Income tax payable | 14,000 | ||
| Lease liability | 6,883 | ||
| Derivative liability | 100,474 | ||
| Ad valorem taxes | 76,071 | ||
| Asset retirement obligations | 68,741 | ||
| Other noncurrent liabilities | 1,750 | ||
| Total liabilities assumed | 605,719 | ||
| Net assets acquired | 1,844,129 | ||
| Crestone Peak | |||
| Assets Acquired | |||
| Cash and cash equivalents | 67,505 | ||
| Accounts receivable - oil, natural gas, and NGL sales | 81,340 | ||
| Accounts receivable - joint interest and other | 9,917 | ||
| Prepaid expenses and other | 2,929 | ||
| Inventory of oilfield equipment | 11,951 | ||
| Proved properties | 1,797,814 | ||
| Unproved properties | 453,321 | ||
| Other property and equipment | 7,980 | ||
| Right-of-use assets | 7,934 | ||
| Total assets acquired | 2,440,691 | ||
| Liabilities Assumed | |||
| Accounts payable and accrued expenses | 134,791 | ||
| Production taxes payable | 52,435 | ||
| Oil and natural gas revenue distribution payable | 83,950 | ||
| Lease liability | 7,934 | ||
| Derivative liability | 338,383 | ||
| Credit facility | 280,000 | ||
| Ad valorem taxes | 66,913 | ||
| Deferred income tax liabilities | $ 125,100 | 125,086 | |
| Asset retirement obligations | 88,949 | ||
| Total liabilities assumed | 1,178,441 | ||
| Net assets acquired | $ 1,262,250 |
ACQUISITIONS AND DIVESTITURES - Pro Forma Information (Details) - USD ($) $ / shares in Units, $ in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2022 |
Dec. 31, 2021 |
Dec. 31, 2020 |
|
| As reported | |||
| Total revenue | $ 3,791,398 | $ 930,614 | $ 218,090 |
| Net income (loss) | $ 1,248,080 | $ 178,921 | $ 103,528 |
| Basic net income (loss) per common share (in dollars per share) | $ 14.68 | $ 4.82 | $ 4.98 |
| Diluted net income (loss) per common share (in dollars per share) | $ 14.58 | $ 4.74 | $ 4.95 |
| Total revenue | $ 2,392,926 | $ 1,311,767 | |
| Net income (loss) | $ 1,046,057 | $ (2,581,282) | |
| Net income (loss) per common share - basic (in dollars per share) | $ 12.61 | $ (28.83) | |
| Net income (loss) per common share - diluted (in dollars per share) | $ 12.52 | $ (28.83) | |
| HighPoint | |||
| As reported | |||
| Total revenue | $ 72,019 | $ 250,347 | |
| Net income (loss) | (46,434) | (1,081,347) | |
| Extraction | |||
| As reported | |||
| Total revenue | 882,255 | 557,904 | |
| Net income (loss) | 1,140,653 | (1,335,406) | |
| Crestone Peak | |||
| As reported | |||
| Total revenue | 508,038 | 285,426 | |
| Net income (loss) | $ (227,083) | $ (268,057) | |
REVENUE RECOGNITION - Schedule of Revenue by Revenue Stream (Details) - USD ($) $ in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2022 |
Dec. 31, 2021 |
Dec. 31, 2020 |
|
| Disaggregation of Revenue [Line Items] | |||
| Oil and natural gas sales | $ 3,791,398 | $ 930,614 | $ 218,090 |
| Oil sales | |||
| Disaggregation of Revenue [Line Items] | |||
| Oil and natural gas sales | 2,536,134 | 614,811 | 174,536 |
| Natural gas sales | |||
| Disaggregation of Revenue [Line Items] | |||
| Oil and natural gas sales | 695,079 | 144,708 | 24,243 |
| NGL sales | |||
| Disaggregation of Revenue [Line Items] | |||
| Oil and natural gas sales | $ 560,185 | $ 171,095 | $ 19,311 |
REVENUE RECOGNITION - Narrative (Details) - USD ($) $ in Thousands |
Dec. 31, 2022 |
Dec. 31, 2021 |
|---|---|---|
| Revenue from Contract with Customer [Abstract] | ||
| Receivable from contracts with customers | $ 343,500 | $ 362,262 |
ACCOUNTS PAYABLE AND ACCRUED EXPENSES - Accounts Payable and Accrued Expenses (Details) - USD ($) $ in Thousands |
Dec. 31, 2022 |
Dec. 31, 2021 |
|---|---|---|
| Payables and Accruals [Abstract] | ||
| Accounts payable trade | $ 31,783 | $ 19,623 |
| Accrued drilling and completion costs | 137,171 | 129,430 |
| Accrued lease operating expense and gathering, transportation, and processing | 77,507 | 19,077 |
| Accrued general and administrative expense | 20,054 | 21,163 |
| Accrued merger transaction costs | 0 | 1,475 |
| Accrued commodity derivative settlements | 12,514 | 26,601 |
| Accrued interest expense | 5,509 | 6,303 |
| Accrued settlement | 1,497 | 20,791 |
| Other accrued expenses | 9,262 | 1,725 |
| Total accounts payable and accrued expenses | $ 295,297 | $ 246,188 |
LONG-TERM DEBT - Narrative (Details) |
1 Months Ended | 12 Months Ended | |||||||
|---|---|---|---|---|---|---|---|---|---|
|
Apr. 20, 2022
USD ($)
|
Oct. 13, 2021
USD ($)
agency
|
Apr. 01, 2021
USD ($)
|
Dec. 31, 2018 |
Dec. 31, 2022
USD ($)
|
Dec. 31, 2021
USD ($)
|
Dec. 31, 2020
USD ($)
|
Oct. 27, 2022
USD ($)
|
Nov. 01, 2021
USD ($)
|
|
| LONG-TERM DEBT | |||||||||
| Interest expense | $ 32,200,000 | $ 16,000,000 | $ 3,800,000 | ||||||
| Capitalized interest | 0 | 6,300,000 | $ 1,800,000 | ||||||
| Revolving credit facility | |||||||||
| LONG-TERM DEBT | |||||||||
| Minimum current ratio covenant | 1.00 | ||||||||
| Amended Credit Agreement | Revolving credit facility | |||||||||
| LONG-TERM DEBT | |||||||||
| Maximum borrowing capacity | $ 2,000,000,000 | ||||||||
| Covenant, minimum percentage of mortgage on total value of certain proved oil and gas properties | 90.00% | ||||||||
| Maximum net leverage ratio | 3.00 | ||||||||
| Borrowing base amount | $ 1,700,000,000 | $ 1,850,000,000 | $ 1,000,000,000 | ||||||
| Elected commitments | $ 1,000,000,000 | $ 800,000,000 | |||||||
| Amended Credit Agreement | Revolving credit facility | Fed Funds Effective Rate Overnight Index Swap Rate | |||||||||
| LONG-TERM DEBT | |||||||||
| Basis spread on variable rate | 0.50% | ||||||||
| Amended Credit Agreement | Revolving credit facility | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate Plus Basis Spread One | |||||||||
| LONG-TERM DEBT | |||||||||
| Basis spread on variable rate, floor | 1.50% | ||||||||
| Amended Credit Agreement | Revolving credit facility | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate Plus Basis Spread One | Minimum | |||||||||
| LONG-TERM DEBT | |||||||||
| Basis spread on variable rate | 1.00% | ||||||||
| Amended Credit Agreement | Revolving credit facility | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate Plus Basis Spread One | Maximum | |||||||||
| LONG-TERM DEBT | |||||||||
| Basis spread on variable rate | 2.00% | ||||||||
| Amended Credit Agreement | Revolving credit facility | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | |||||||||
| LONG-TERM DEBT | |||||||||
| Basis spread on variable rate | 1.00% | ||||||||
| Basis spread on variable rate, floor | 0.50% | ||||||||
| Amended Credit Agreement | Revolving credit facility | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | Minimum | |||||||||
| LONG-TERM DEBT | |||||||||
| Basis spread on variable rate | 2.00% | ||||||||
| Amended Credit Agreement | Revolving credit facility | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | Maximum | |||||||||
| LONG-TERM DEBT | |||||||||
| Basis spread on variable rate | 3.00% | ||||||||
| Amended Credit Agreement | HighPoint | Revolving credit facility | |||||||||
| LONG-TERM DEBT | |||||||||
| Deferred financing costs, gross | 11,900,000 | ||||||||
| Deferred financing costs, net | 5,500,000 | 7,500,000 | |||||||
| Debt issuance costs | $ 3,000,000 | $ 2,700,000 | |||||||
| Senior Notes | Senior Notes Due 2026, 5.0% | |||||||||
| LONG-TERM DEBT | |||||||||
| Interest rate (as a percent) | 5.00% | 5.00% | 5.00% | ||||||
| Aggregate principal amount | $ 400,000,000 | ||||||||
| Covenant, investment-grade rating, number of ratings agencies (at least) | agency | 2 | ||||||||
| Debt issuance costs | $ 6,707,000 | $ 8,290,000 | |||||||
| Senior Notes | Senior Notes Due 2026, 5.0%, Indenture | |||||||||
| LONG-TERM DEBT | |||||||||
| Interest rate (as a percent) | 5.00% | 5.00% | |||||||
| Senior Notes | Senior Notes Due 2026, 7.50% | HighPoint | |||||||||
| LONG-TERM DEBT | |||||||||
| Interest rate (as a percent) | 7.50% | 7.50% | |||||||
| Aggregate principal amount | $ 100,000,000 | ||||||||
| Debt issuance costs | $ 0 | ||||||||
| Senior Notes | Debt Instrument, Redemption, Period One | Senior Notes Due 2026, 5.0% | |||||||||
| LONG-TERM DEBT | |||||||||
| Percentage of principal amount redeemed (up to) | 35.00% | ||||||||
| Redemption period, after date of closing of equity offering | 180 days | ||||||||
| Senior Notes | Debt Instrument, Redemption, Period Two | Senior Notes Due 2026, 5.0% | |||||||||
| LONG-TERM DEBT | |||||||||
| Redemption price, percentage | 102.50% | ||||||||
| Percentage of principal amount not redeemed | 65.00% | ||||||||
| Senior Notes | Debt Instrument, Redemption, Period Two | Senior Notes Due 2026, 7.50% | HighPoint | |||||||||
| LONG-TERM DEBT | |||||||||
| Redemption price, percentage | 100.00% | ||||||||
| Senior Notes | Debt Instrument, Redemption, Period Three | Senior Notes Due 2026, 5.0% | |||||||||
| LONG-TERM DEBT | |||||||||
| Redemption price, percentage | 101.25% | ||||||||
| Senior Notes | Debt Instrument, Redemption, Period Four | Senior Notes Due 2026, 5.0% | |||||||||
| LONG-TERM DEBT | |||||||||
| Redemption price, percentage | 100.00% | ||||||||
| Senior Notes | Debt Instrument, Redemption, Period Five | Senior Notes Due 2026, 5.0% | |||||||||
| LONG-TERM DEBT | |||||||||
| Redemption price, percentage | 105.00% | ||||||||
LONG-TERM DEBT - Schedule of Carrying Values (Details) - Senior Notes - USD ($) |
Dec. 31, 2022 |
Dec. 31, 2021 |
Oct. 13, 2021 |
Apr. 01, 2021 |
|---|---|---|---|---|
| Senior Notes Due 2026, 5.0% | ||||
| LONG-TERM DEBT | ||||
| Principal Amount | $ 400,000,000 | $ 400,000,000 | ||
| Unamortized Deferred Financing Costs | 6,707,000 | 8,290,000 | ||
| Net Amount | $ 393,293,000 | $ 391,710,000 | ||
| Interest rate (as a percent) | 5.00% | 5.00% | 5.00% | |
| Senior Notes Due 2026, 7.50% | HighPoint | ||||
| LONG-TERM DEBT | ||||
| Principal Amount | $ 100,000,000 | |||
| Unamortized Deferred Financing Costs | 0 | |||
| Net Amount | $ 100,000,000 | |||
| Interest rate (as a percent) | 7.50% | 7.50% |
LONG-TERM DEBT - Schedule of Debt Outstanding and Borrowing Capacity (Details) - Line of Credit - USD ($) $ in Thousands |
Feb. 22, 2023 |
Dec. 31, 2022 |
Dec. 31, 2021 |
|---|---|---|---|
| Revolving credit facility and Letters of credit | |||
| LONG-TERM DEBT | |||
| Available borrowing capacity | $ 987,900 | $ 778,344 | |
| Total aggregate elected commitments | 1,000,000 | 800,000 | |
| Revolving credit facility and Letters of credit | Subsequent Event | |||
| LONG-TERM DEBT | |||
| Available borrowing capacity | $ 987,900 | ||
| Total aggregate elected commitments | 1,000,000 | ||
| Revolving credit facility | |||
| LONG-TERM DEBT | |||
| Credit facility outstanding | 0 | 0 | |
| Revolving credit facility | Subsequent Event | |||
| LONG-TERM DEBT | |||
| Credit facility outstanding | 0 | ||
| Letters of credit | |||
| LONG-TERM DEBT | |||
| Credit facility outstanding | $ 12,100 | $ 21,656 | |
| Letters of credit | Subsequent Event | |||
| LONG-TERM DEBT | |||
| Credit facility outstanding | $ 12,100 |
COMMITMENTS AND CONTINGENCIES - Narrative (Details) $ in Thousands |
12 Months Ended | |
|---|---|---|
|
Dec. 31, 2022
USD ($)
plant
qualifying_well
bbl / d
Bcf
bbl
MMcf
|
Dec. 31, 2021
USD ($)
|
|
| Firm Transportation | ||
| Loss Contingencies [Line Items] | ||
| Financial commitment | $ 34,040 | |
| Natural Gas And Fresh Water | Natural Gas and Fresh Water Commitment | ||
| Loss Contingencies [Line Items] | ||
| Financial commitment | 0 | |
| NGL Crude Logistics | Crude Oil | Crude Oil Commitment | ||
| Loss Contingencies [Line Items] | ||
| Financial commitment | $ 47,300 | |
| Gross daily minimum volume requirement | bbl | 20,000 | |
| Third-Party Midstream Provider | ||
| Loss Contingencies [Line Items] | ||
| Well drilling, number of qualifying wells required to be drilled | qualifying_well | 106 | |
| Horizontal well drilling, minimum number of wells required to be drilled, period ending December 31, 2026 | 2 years | |
| Third-Party Midstream Provider | Gas contracts | Natural Gas Commitment and Take-In-Kind Natural Gas Liquids Commitment | ||
| Loss Contingencies [Line Items] | ||
| Financial commitment | $ 121,700 | |
| Expected shortfall payments | $ 52,600 | |
| Remaining term | 7 years | |
| Third-Party Midstream Provider | Gas contracts | Natural Gas Commitment | ||
| Loss Contingencies [Line Items] | ||
| Annual minimum volume requirement | Bcf | 13.0 | |
| Third-Party Midstream Provider | Gas contracts | Take-In-Kind Natural Gas Liquids Commitment | ||
| Loss Contingencies [Line Items] | ||
| Daily sales commitment requirement, through year seven | bbl | 7,500 | |
| Monthly roll forward shortfall requirement, percent (up to) | 10.00% | |
| Third-Party Producers And A Third-Party Midstream Provider | Gas contracts | Natural Gas Commitment | ||
| Loss Contingencies [Line Items] | ||
| Number of different plants | plant | 2 | |
| Daily baseline volume requirement | MMcf | 65 | |
| Daily baseline volume requirement, term | 7 years | |
| Third-Party Producers And A Third-Party Midstream Provider | Gas contracts | Natural Gas Commitment | Minimum | ||
| Loss Contingencies [Line Items] | ||
| Daily incremental volume requirement | MMcf | 51.5 | |
| Third-Party Producers And A Third-Party Midstream Provider | Gas contracts | Natural Gas Commitment | Maximum | ||
| Loss Contingencies [Line Items] | ||
| Daily incremental volume requirement | MMcf | 20.6 | |
| Water Suppliers | Natural Gas And Fresh Water | Natural Gas and Fresh Water Commitment | ||
| Loss Contingencies [Line Items] | ||
| Financial commitment | $ 8,300 | |
| HighPoint | Pipeline Transportation Commitment | ||
| Loss Contingencies [Line Items] | ||
| Minimum volume transportation charges, barrels per day requirement thereafter through April 2025 | bbl / d | 12,500 | |
| Financial commitment | $ 34,000 | |
| Sterling Energy Investments LLC Versus HighPoint Operating Corporation Litigation | Pending Litigation | HighPoint | ||
| Loss Contingencies [Line Items] | ||
| Accrued litigation liability | $ 700 | $ 1,000 |
COMMITMENTS AND CONTINGENCIES - Schedule of Purchase Obligations (Details) $ in Thousands |
Dec. 31, 2022
USD ($)
|
|---|---|
| Firm Transportation | |
| Long-term Purchase Commitment [Line Items] | |
| 2023 | $ 14,600 |
| 2024 | 14,640 |
| 2025 | 4,800 |
| 2026 | 0 |
| 2027 and thereafter | 0 |
| Total | 34,040 |
| Minimum Volume | |
| Long-term Purchase Commitment [Line Items] | |
| 2023 | 68,265 |
| 2024 | 20,604 |
| 2025 | 18,840 |
| 2026 | 17,728 |
| 2027 and thereafter | 51,870 |
| Total | $ 177,307 |
STOCK-BASED COMPENSATION - Narrative (Details) $ in Millions |
12 Months Ended | ||||
|---|---|---|---|---|---|
|
Dec. 31, 2022
USD ($)
performance_criteria
shares
|
Dec. 31, 2021 |
Nov. 01, 2021
shares
|
Jun. 30, 2021
shares
|
Apr. 30, 2017
shares
|
|
| LTIP | |||||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
| Aggregate intrinsic value, options exercised | $ | $ 0.2 | ||||
| LTIP | Restricted Stock Units (RSUs) and Deferred Stock Units (DSUs) | Non-executive Board Members | |||||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
| Fair value of units granted | $ | $ 29.4 | ||||
| LTIP | Restricted Stock Units (RSUs) | |||||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
| Number of shares released upon vesting (in shares) | 1 | ||||
| LTIP | Restricted Stock Units (RSUs) | Vesting Period One | |||||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
| Vesting period | 1 year | ||||
| LTIP | Restricted Stock Units (RSUs) | Vesting Period Two | |||||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
| Vesting period | 3 years | ||||
| LTIP | Restricted Stock Units (RSUs) | Vesting Period One, Anniversary One | |||||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
| Vesting percent of shares | 33.00% | ||||
| LTIP | Restricted Stock Units (RSUs) | Vesting Period Two, Anniversary Two | |||||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
| Vesting percent of shares | 33.00% | ||||
| LTIP | Restricted Stock Units (RSUs) | Vesting Period Three, Anniversary Three | |||||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
| Vesting percent of shares | 33.00% | ||||
| LTIP | Deferred Stock Units (DSUs) | |||||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
| Number of shares released upon vesting (in shares) | 1 | ||||
| LTIP | Deferred Stock Units (DSUs) | Vesting Period One | |||||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
| Vesting period | 1 year | ||||
| LTIP | Stock options | |||||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
| Expiration period | 10 years | ||||
| LTIP | Performance Stock Units (PSUs) | Minimum | |||||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
| Ratio at which award holders get common stock of the company | 0 | 0 | |||
| LTIP | Performance Stock Units (PSUs) | Maximum | |||||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
| Ratio at which award holders get common stock of the company | 2 | 2 | |||
| LTIP | Performance Stock Units (PSUs) | Officers | |||||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
| Vesting period | 3 years | ||||
| Fair value of units granted | $ | $ 18.5 | ||||
| Number of trading days | 30 days | ||||
| LTIP | Performance Stock Units (PSUs) | Officers | Minimum | |||||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
| Ratio at which award holders get common stock of the company | 0 | ||||
| Performance achievement, number of criteria | performance_criteria | 1 | ||||
| LTIP | Performance Stock Units (PSUs) | Officers | Maximum | |||||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
| Ratio at which award holders get common stock of the company | 2 | ||||
| Performance achievement, number of criteria | performance_criteria | 2 | ||||
| LTIP | TSR | Officers | |||||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
| Distribution of shares to recipients (as a percentage) | 200.00% | ||||
| LTIP | ROCE | Officers | |||||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
| Distribution of shares to recipients (as a percentage) | 92.00% | ||||
| 2017 LTIP | |||||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
| Shares reserved for future issuance (in shares) | 2,467,430 | ||||
| 2021 LTIP | |||||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
| Shares reserved for future issuance (in shares) | 700,000 | ||||
| Extraction Equity Plan | |||||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
| Shares reserved for future issuance (in shares) | 3,305,080 | ||||
STOCK-BASED COMPENSATION - Schedule of Expenses (Details) - LTIP - USD ($) $ in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2022 |
Dec. 31, 2021 |
Dec. 31, 2020 |
|
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
| Total stock-based compensation | $ 31,367 | $ 15,558 | $ 6,156 |
| Restricted and deferred stock units | |||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
| Total stock-based compensation | 19,401 | 11,895 | 5,283 |
| Performance stock units | |||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
| Total stock-based compensation | 11,966 | $ 3,663 | 748 |
| Stock options | |||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
| Total stock-based compensation | $ 0 | $ 125 | |
STOCK-BASED COMPENSATION - Unrecognized Compensation Expense (Details) - LTIP $ in Thousands |
Dec. 31, 2022
USD ($)
|
|---|---|
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
| Total unrecognized stock-based compensation | $ 32,141 |
| Restricted and deferred stock units | |
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
| Total unrecognized stock-based compensation | 16,801 |
| Performance stock units | |
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
| Total unrecognized stock-based compensation | $ 15,340 |
STOCK-BASED COMPENSATION - Activity of Non-Option Awards (Details) - LTIP |
12 Months Ended | |
|---|---|---|
|
Dec. 31, 2022
$ / shares
shares
|
Dec. 31, 2021
$ / shares
shares
|
|
| RSUs and DSUs | ||
| Stock Units | ||
| Non-vested, beginning of year (in shares) | shares | 815,062 | |
| Granted (in shares) | shares | 573,524 | |
| Vested (in shares) | shares | (647,178) | |
| Forfeited (in shares) | shares | (65,510) | |
| Non-vested, end of year (in shares) | shares | 675,898 | 815,062 |
| Weighted-Average Grant-Date Fair Value | ||
| Non-vested, beginning of year (in dollars per share) | $ / shares | $ 42.18 | |
| Granted (in dollars per share) | $ / shares | 51.34 | |
| Vested (in dollars per share) | $ / shares | 42.07 | |
| Forfeited (in dollars per share) | $ / shares | 39.96 | |
| Non-vested, end of year (in dollars per share) | $ / shares | $ 50.27 | $ 42.18 |
| PSUs | ||
| Stock Units | ||
| Non-vested, beginning of year (in shares) | shares | 345,999 | 319,367 |
| Granted (in shares) | shares | 282,224 | |
| Vested (in shares) | shares | (164,745) | |
| Forfeited (in shares) | shares | (48,892) | |
| Expired (in shares) | shares | (41,955) | |
| Non-vested, end of year (in shares) | shares | 345,999 | |
| Weighted-Average Grant-Date Fair Value | ||
| Non-vested, beginning of year (in dollars per share) | $ / shares | $ 77.42 | $ 57.58 |
| Granted (in dollars per share) | $ / shares | 65.65 | |
| Vested (in dollars per share) | $ / shares | 41.03 | |
| Forfeited (in dollars per share) | $ / shares | 49.39 | |
| Expired (in dollars per share) | $ / shares | $ 22.77 | |
| Non-vested, end of year (in dollars per share) | $ / shares | $ 77.42 | |
| Target amount multiplier | 1 | |
| PSUs | Minimum | ||
| Weighted-Average Grant-Date Fair Value | ||
| Ratio at which award holders get common stock of the company | 0 | 0 |
| PSUs | Maximum | ||
| Weighted-Average Grant-Date Fair Value | ||
| Ratio at which award holders get common stock of the company | 2 | 2 |
STOCK-BASED COMPENSATION - Other Than Options Split Criteria (Details) - LTIP - Officers |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2022 |
Dec. 31, 2021 |
Dec. 31, 2020 |
|
| TSR | 2022 | |||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
| Total number of dual-criteria PSUs granted, percent | 100.00% | ||
| TSR | 2021 | |||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
| Total number of dual-criteria PSUs granted, percent | 100.00% | ||
| TSR | 2020 | |||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
| Total number of dual-criteria PSUs granted, percent | 67.00% | ||
| ROCE | 2022 | |||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
| Total number of dual-criteria PSUs granted, percent | 0.00% | ||
| ROCE | 2021 | |||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
| Total number of dual-criteria PSUs granted, percent | 0.00% | ||
| ROCE | 2020 | |||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
| Total number of dual-criteria PSUs granted, percent | 33.00% | ||
STOCK-BASED COMPENSATION - Valuation Assumptions (Details) - LTIP - Officers - TSR |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2022 |
Dec. 31, 2021 |
Dec. 31, 2020 |
|
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
| Expected term (in years) | 3 years 2 months 12 days | 3 years | |
| Risk-free interest rate, minimum | 1.80% | 0.30% | |
| Risk-free interest rate, maximum | 3.20% | 0.60% | |
| Risk-free interest rate | 0.20% | ||
| Expected daily volatility, minimum | 4.00% | 3.80% | |
| Expected daily volatility, maximum | 4.70% | 4.70% | |
| Expected daily volatility | 3.50% | ||
| Minimum | |||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
| Expected term (in years) | 2 years 2 months 12 days | ||
| Maximum | |||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
| Expected term (in years) | 3 years | ||
STOCK-BASED COMPENSATION - Activity of Stock Options (Details) - LTIP |
12 Months Ended |
|---|---|
|
Dec. 31, 2022
USD ($)
$ / shares
shares
| |
| Stock Options | |
| Outstanding, beginning of year (shares) | shares | 25,549 |
| Exercised (shares) | shares | (9,161) |
| Forfeited (shares) | shares | (1,218) |
| Outstanding, end of year (shares) | shares | 15,170 |
| Options outstanding and exercisable (shares) | shares | 15,170 |
| Weighted- Average Exercise Price | |
| Outstanding, beginning of year (in dollars per share) | $ / shares | $ 34.36 |
| Exercised (in dollars per share) | $ / shares | 34.36 |
| Forfeited (in dollars per share) | $ / shares | 34.36 |
| Outstanding, end of year (in dollars per share) | $ / shares | 34.36 |
| Options outstanding and exercisable (in dollars per share) | $ / shares | $ 34.36 |
| Additional Information | |
| Weighted-Average Remaining Contractual Term (in years) | 1 year 3 months 18 days |
| Options outstanding and exercisable, Weighted-Average Remaining Contractual Term (in years) | 1 year 3 months 18 days |
| Aggregate Intrinsic Value (in thousands) | $ | $ 358,000 |
| Options outstanding and exercisable, Aggregate Intrinsic Value (in thousands) | $ | $ 358,000 |
FAIR VALUE MEASUREMENTS - Schedule of Non-financial Assets and Liabilities (Details) - Estimate of Fair Value Measurement - USD ($) $ in Thousands |
Dec. 31, 2022 |
Dec. 31, 2021 |
|---|---|---|
| Level 1 | ||
| Financial assets and liabilities accounted for at fair value | ||
| Derivative assets | $ 0 | $ 0 |
| Derivative liabilities | 0 | 0 |
| Level 2 | ||
| Financial assets and liabilities accounted for at fair value | ||
| Derivative assets | 3,284 | 3,393 |
| Derivative liabilities | 63,533 | 239,763 |
| Level 3 | ||
| Financial assets and liabilities accounted for at fair value | ||
| Derivative assets | 0 | 0 |
| Derivative liabilities | $ 0 | $ 0 |
FAIR VALUE MEASUREMENTS - Narrative (Details) - USD ($) |
12 Months Ended | ||||
|---|---|---|---|---|---|
Nov. 01, 2021 |
Dec. 31, 2022 |
Dec. 31, 2021 |
Dec. 31, 2020 |
Oct. 13, 2021 |
|
| Financial assets and liabilities accounted for at fair value | |||||
| Proved oil and gas property impairments | $ 0 | $ 0 | $ 0 | ||
| Abandonment and impairment of unproved properties | $ 17,975,000 | $ 57,260,000 | $ 37,343,000 | ||
| Extraction | Tranche A and Tranche B Warrants | |||||
| Financial assets and liabilities accounted for at fair value | |||||
| Fair value allocated to consideration transferred | $ 77,463,000 | ||||
| Senior Notes Due 2026, 5.0% | Senior Notes | |||||
| Financial assets and liabilities accounted for at fair value | |||||
| Interest rate (as a percent) | 5.00% | 5.00% | 5.00% | ||
| Long-term debt, fair value | $ 369,400,000 | ||||
DERIVATIVES - Commodity Derivatives (Details) - Subsequent Event - Scenario, Forecast |
3 Months Ended | 12 Months Ended | |||
|---|---|---|---|---|---|
|
Dec. 31, 2023
MMBTU
$ / MMBTU
$ / bbl
bbl
|
Sep. 30, 2023
MMBTU
$ / bbl
$ / MMBTU
bbl
|
Jun. 30, 2023
MMBTU
$ / MMBTU
$ / bbl
bbl
|
Mar. 31, 2023
MMBTU
$ / bbl
$ / MMBTU
bbl
|
Dec. 31, 2024
MMBTU
$ / MMBTU
$ / bbl
bbl
|
|
| Oil Derivatives (volumes in Bbl/day and prices in $/Bbls) | Swaps | |||||
| Derivative [Line Items] | |||||
| Notional amount (in unit per day) | bbl | 984 | 1,053 | 1,205 | 1,320 | 1,019 |
| Weighted-Average Contract Price (in dollars per unit) | $ / bbl | 70.61 | 70.92 | 73.49 | 74.29 | 66.78 |
| Oil Derivatives (volumes in Bbl/day and prices in $/Bbls) | Two-Way Collars | |||||
| Derivative [Line Items] | |||||
| Notional amount (in unit per day) | bbl | 1,054 | ||||
| Weighted-Average Ceiling Price (in dollars per unit) | $ / bbl | 72.70 | ||||
| Weighted-Average Floor Price (in dollars per unit) | $ / bbl | 40.00 | ||||
| Oil Derivatives (volumes in Bbl/day and prices in $/Bbls) | Three-Way Collars | |||||
| Derivative [Line Items] | |||||
| Notional amount (in unit per day) | bbl | 1,172 | 1,302 | 1,436 | 1,721 | 143 |
| Weighted-Average Ceiling Price (in dollars per unit) | $ / bbl | 56.49 | 57.48 | 57.69 | 58.75 | 56.25 |
| Weighted-Average Floor Price (in dollars per unit) | $ / bbl | 49.04 | 47.91 | 48.10 | 49.31 | 45.00 |
| Weighted-Average Sold Put Price (in dollars per unit) | $ / bbl | 39.04 | 37.41 | 37.70 | 39.25 | 35.00 |
| Natural Gas Derivatives (volumes in MMBtu/day and prices in $/MMBtu) | Swaps | |||||
| Derivative [Line Items] | |||||
| Weighted-Average Contract Price (in dollars per unit) | $ / MMBTU | 2.60 | 2.61 | 2.64 | 2.65 | 2.70 |
| Natural Gas, notional amount (in MMBtu per day) | MMBTU | 45,947 | 46,120 | 46,374 | 47,368 | 24,148 |
| Natural Gas Derivatives (volumes in MMBtu/day and prices in $/MMBtu) | Two-Way Collars | |||||
| Derivative [Line Items] | |||||
| Weighted-Average Ceiling Price (in dollars per unit) | $ / MMBTU | 2.96 | 2.96 | 2.78 | 3.23 | 3.05 |
| Weighted-Average Floor Price (in dollars per unit) | $ / MMBTU | 2.38 | 2.34 | 2.21 | 2.03 | 2.38 |
| Natural Gas, notional amount (in MMBtu per day) | MMBTU | 1,756 | 1,887 | 1,563 | 9,558 | 1,033 |
| Natural Gas Derivatives (volumes in MMBtu/day and prices in $/MMBtu) | Three-Way Collars | |||||
| Derivative [Line Items] | |||||
| Weighted-Average Ceiling Price (in dollars per unit) | $ / MMBTU | 3.33 | 3.19 | 3.49 | ||
| Weighted-Average Floor Price (in dollars per unit) | $ / MMBTU | 2.50 | 2.50 | 2.50 | ||
| Weighted-Average Sold Put Price (in dollars per unit) | $ / MMBTU | 2.00 | 2.00 | 2.00 | ||
| Natural Gas, notional amount (in MMBtu per day) | MMBTU | 505 | 899 | 303 | ||
DERIVATIVES - Narrative (Details) |
Sep. 30, 2024
$ / MMBTU
|
|---|---|
| Natural gas sales | Scenario, Forecast | Basis Swap | Subsequent Event | |
| Derivative [Line Items] | |
| Weighted-Average Contract Price (in dollars per unit) | (0.13) |
DERIVATIVES - Derivative Positions (Details) - Commodity - USD ($) $ in Thousands |
Dec. 31, 2022 |
Dec. 31, 2021 |
|---|---|---|
| Derivative Assets: | ||
| Total derivative assets | $ 3,284 | $ 3,393 |
| Amounts not offset in the accompanying balance sheets | 0 | (3,393) |
| Total derivative assets, net | 3,284 | 0 |
| Derivative Liabilities: | ||
| Total derivative liabilities | (63,533) | (239,763) |
| Amounts not offset in the accompanying balance sheets | 0 | 3,393 |
| Total derivative liabilities, net | (63,533) | (236,370) |
| Commodity contracts - current | ||
| Derivative Assets: | ||
| Total derivative assets | 2,490 | 3,393 |
| Commodity contracts - noncurrent | ||
| Derivative Assets: | ||
| Total derivative assets | 794 | 0 |
| Commodity contracts - current | ||
| Derivative Liabilities: | ||
| Total derivative liabilities | (46,334) | (219,804) |
| Commodity contracts - long-term | ||
| Derivative Liabilities: | ||
| Total derivative liabilities | $ (17,199) | $ (19,959) |
DERIVATIVES - Derivative Gain (Loss) (Details) - USD ($) $ in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2022 |
Dec. 31, 2021 |
Dec. 31, 2020 |
|
| Components of the derivative gain (loss) | |||
| Total derivative gain (loss) | $ (335,160) | $ (60,510) | $ 53,462 |
| Commodity derivative | |||
| Components of the derivative gain (loss) | |||
| Total derivative cash settlement gain (loss) | (576,802) | (275,914) | 49,406 |
| Change in fair value gain | 241,642 | 215,404 | 4,056 |
| Total derivative gain (loss) | (335,160) | (60,510) | 53,462 |
| Commodity derivative | Oil contracts | |||
| Components of the derivative gain (loss) | |||
| Total derivative cash settlement gain (loss) | (346,419) | (215,057) | 50,133 |
| Commodity derivative | Gas contracts | |||
| Components of the derivative gain (loss) | |||
| Total derivative cash settlement gain (loss) | (189,410) | (51,806) | (727) |
| Commodity derivative | NGL sales | |||
| Components of the derivative gain (loss) | |||
| Total derivative cash settlement gain (loss) | $ (40,973) | $ (9,051) | $ 0 |
ASSET RETIREMENT OBLIGATIONS - Schedule of Roll-Forward Activity (Details) - USD ($) $ in Thousands |
12 Months Ended | |
|---|---|---|
Dec. 31, 2022 |
Dec. 31, 2021 |
|
| Change in asset retirement obligations | ||
| Balance, beginning of year | $ 225,315 | $ 28,699 |
| Additional liabilities incurred | 3,031 | 183,758 |
| Liabilities settled | (15,902) | (4,221) |
| Accretion expense | 15,926 | 3,933 |
| Revisions to estimate | 62,656 | 13,146 |
| Balance, end of year | 291,026 | 225,315 |
| Current portion | 25,557 | 24,000 |
| Long-term portion | $ 265,469 | $ 201,315 |
EARNINGS PER SHARE - Narrative (Details) |
12 Months Ended | ||
|---|---|---|---|
|
Dec. 31, 2022
shares
|
Dec. 31, 2021
shares
|
Dec. 31, 2020
shares
|
|
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
| Antidilutive securities excluded from EPS calculation (in shares) | 20,699 | 178,051 | 248,744 |
| LTIP | Minimum | Performance stock units | |||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
| Ratio at which award holders get common stock of the company | 0 | 0 | |
| LTIP | Maximum | Performance stock units | |||
| Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
| Ratio at which award holders get common stock of the company | 2 | 2 | |
EARNINGS PER SHARE - Schedule of Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2022 |
Dec. 31, 2021 |
Dec. 31, 2020 |
|
| Earnings Per Share [Abstract] | |||
| Net income, basic | $ 1,248,080 | $ 178,921 | $ 103,528 |
| Net income, diluted | $ 1,248,080 | $ 178,921 | $ 103,528 |
| Basic net income per common share (in dollars per share) | $ 14.68 | $ 4.82 | $ 4.98 |
| Diluted net income per common share (in dollars per share) | $ 14.58 | $ 4.74 | $ 4.95 |
| Weighted-average shares outstanding - basic (in shares) | 85,005 | 37,155 | 20,774 |
| Add: dilutive effect of stock awards (in shares) | 599 | 591 | 138 |
| Weighted-average shares outstanding - diluted (in shares) | 85,604 | 37,746 | 20,912 |
INCOME TAXES - Provision For Income Taxes (Details) - USD ($) $ in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2022 |
Dec. 31, 2021 |
Dec. 31, 2020 |
|
| Current tax expense (benefit) | |||
| Federal | $ 51,246 | $ 0 | $ (27) |
| State | 16,950 | 0 | 0 |
| Total current tax expense (benefit) | 68,196 | 0 | (27) |
| Deferred tax expense (benefit) | |||
| Federal | 289,578 | 62,212 | (53,784) |
| State | 47,924 | 10,646 | (6,736) |
| Total deferred tax expense (benefit) | 337,502 | 72,858 | (60,520) |
| Total income tax expense (benefit) | $ 405,698 | $ 72,858 | $ (60,547) |
INCOME TAXES - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands |
Dec. 31, 2022 |
Dec. 31, 2021 |
|---|---|---|
| Deferred tax liabilities: | ||
| Oil and gas properties | $ 868,612 | $ 608,829 |
| Right-of-use assets | 5,915 | 8,292 |
| Total deferred tax liabilities | 874,527 | 617,121 |
| Deferred tax assets: | ||
| Federal and state tax net operating loss carryforward | 432,096 | 482,216 |
| Asset retirement obligations | 71,092 | 51,515 |
| Commodity derivative contracts | 37,293 | 86,958 |
| Inventory | 13,783 | 10,108 |
| Stock-based compensation | 5,974 | 7,622 |
| Lease liability | 6,067 | 8,187 |
| Property taxes | 0 | 19,458 |
| Transaction costs | 1,461 | 0 |
| Other long-term assets | 12,547 | 21,474 |
| Total deferred tax assets | 580,313 | 687,538 |
| Less: Valuation allowance | 25,404 | 48,133 |
| Total deferred tax assets after valuation allowance | 554,909 | 639,405 |
| Total non-current net deferred tax asset (liability) | $ (319,618) | |
| Total non-current net deferred tax asset (liability) | $ 22,284 |
INCOME TAXES - Net Operating Loss Carryforwards and Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands |
Dec. 31, 2022 |
Dec. 31, 2021 |
Nov. 01, 2021 |
Apr. 01, 2021 |
|---|---|---|---|---|
| Tax Credit Carryforward [Line Items] | ||||
| Valuation allowance | $ (25,404) | $ (48,133) | ||
| Total non-current net deferred tax asset (liability) | (319,618) | |||
| Total non-current net deferred tax asset (liability) | 22,284 | |||
| HighPoint Merger | ||||
| Tax Credit Carryforward [Line Items] | ||||
| Federal NOL carryforwards (1) | 219,000 | |||
| Deferred tax asset | 110,500 | $ 110,513 | ||
| Valuation allowance | $ (25,400) | (48,100) | ||
| Total non-current net deferred tax asset (liability) | 62,400 | |||
| Annual limitation, Section 382 | 5,600 | |||
| Extraction Merger | ||||
| Tax Credit Carryforward [Line Items] | ||||
| Federal NOL carryforwards (1) | 479,900 | |||
| Deferred tax asset | 49,200 | $ 49,194 | ||
| Valuation allowance | 0 | |||
| Total non-current net deferred tax asset (liability) | 49,200 | |||
| Annual limitation, Section 382 | 7,000 | |||
| Crestone Peak Merger | ||||
| Tax Credit Carryforward [Line Items] | ||||
| Federal NOL carryforwards (1) | 555,700 | |||
| Deferred tax liability | (125,100) | $ (125,086) | ||
| Valuation allowance | 0 | |||
| Total non-current net deferred tax asset (liability) | (125,100) | |||
| Annual limitation, Section 382 | $ 16,800 |
INCOME TAXES - Narrative (Details) - USD ($) |
Dec. 31, 2022 |
Dec. 31, 2021 |
Dec. 31, 2020 |
Jan. 01, 2018 |
Dec. 31, 2017 |
|---|---|---|---|---|---|
| Tax Credit Carryforward [Line Items] | |||||
| Net operating loss carryovers for federal income tax purposes | $ 1,800,000,000 | $ 2,000,000,000 | |||
| Net operating loss carryovers for federal income tax purposes, not benefited for financial statement purposes | $ 1,200,000,000 | $ 569,200,000 | |||
| Deferred tax assets, valuation allowance | 25,404,000 | 48,133,000 | |||
| Unrecognized tax benefits | 0 | 0 | $ 0 | ||
| HighPoint | |||||
| Tax Credit Carryforward [Line Items] | |||||
| Deferred tax assets, valuation allowance | $ 25,400,000 | $ 48,100,000 |
INCOME TAXES - Effective Income Tax Reconciliation (Details) - USD ($) $ in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2022 |
Dec. 31, 2021 |
Dec. 31, 2020 |
|
| Income Tax Disclosure [Abstract] | |||
| Federal statutory tax expense | $ 347,293 | $ 52,824 | $ 9,026 |
| Increase (decrease) in tax resulting from: | |||
| State tax expense, net of federal benefit | 58,658 | 10,646 | 1,694 |
| State tax rate change | 0 | 0 | 124 |
| Return to provision | 19,975 | 27 | 292 |
| Compensation of covered individuals | 6,138 | 1,793 | 144 |
| Stock-based compensation | (3,343) | (1,559) | 690 |
| Transaction costs | 0 | 9,043 | 0 |
| Bargain purchase gain | (2,852) | 0 | 0 |
| Tax credits | (1,405) | 0 | 0 |
| Change in valuation allowance | (19,302) | 0 | (72,553) |
| Other | 536 | 84 | 36 |
| Total income tax expense (benefit) | $ 405,698 | $ 72,858 | $ (60,547) |
LEASES - Assets and Liabilities (Details) - USD ($) $ in Thousands |
Dec. 31, 2022 |
Dec. 31, 2021 |
|---|---|---|
| Operating Leases | ||
| Total right-of-use asset | $ 24,125 | $ 39,885 |
| Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration] | Right-of-use assets | Right-of-use assets |
| Total lease liability | $ 24,788 | $ 40,271 |
| Field equipment | ||
| Operating Leases | ||
| Total right-of-use asset | 15,131 | 29,312 |
| Total lease liability | 15,131 | 29,312 |
| Corporate leases | ||
| Operating Leases | ||
| Total right-of-use asset | 8,235 | 9,484 |
| Total lease liability | 8,898 | 9,870 |
| Vehicles | ||
| Operating Leases | ||
| Total right-of-use asset | 759 | 1,089 |
| Total lease liability | $ 759 | $ 1,089 |
LEASES - Lease Cost (Details) $ in Thousands |
12 Months Ended | ||
|---|---|---|---|
|
Dec. 31, 2022
USD ($)
office_space
|
Dec. 31, 2021
USD ($)
|
Dec. 31, 2020
USD ($)
|
|
| Leases [Abstract] | |||
| Operating lease cost | $ 21,050 | $ 15,449 | $ 13,957 |
| Short-term lease cost | 55,059 | 3,662 | 2,058 |
| Sublease income | (63) | (367) | (358) |
| Total lease cost | 76,046 | 18,744 | 15,657 |
| Office rent expense | $ 4,300 | $ 2,200 | $ 1,100 |
| Number of office spaces subleased | office_space | 1 | ||
LEASES - Weighted-Average and Discount Rate Information (Details) |
Dec. 31, 2022 |
|---|---|
| Operating Leases | |
| Weighted-average lease term (years) | 2 years 7 months 6 days |
| Weighted-average discount rate | 4.00% |
LEASES - Lease Maturities (Details) - USD ($) $ in Thousands |
Dec. 31, 2022 |
Dec. 31, 2021 |
|---|---|---|
| Operating Leases | ||
| 2023 | $ 14,139 | |
| 2024 | 5,737 | |
| 2025 | 2,150 | |
| 2026 | 1,803 | |
| 2027 | 1,771 | |
| Thereafter | 598 | |
| Total lease payments | 26,198 | |
| Less: imputed interest | (1,410) | |
| Total lease liability | $ 24,788 | $ 40,271 |
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION - Schedule of Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2022 |
Dec. 31, 2021 |
Dec. 31, 2020 |
|
| Supplemental cash flow information: | |||
| Cash paid for income taxes | $ (97,800) | $ (14,000) | $ 0 |
| Cash paid for interest, net of capitalization | (28,528) | (1,829) | (1,546) |
| Supplemental non-cash investing and financing activities: | |||
| Non-cash investing activities | 0 | 4,911,186 | 0 |
| Non-cash financing activities | 0 | 3,481,312 | 0 |
| Changes in working capital related to capital expenditures | (7,679) | (128,977) | 2,795 |
| Receivables exchanged for additional interests in oil and natural gas properties | 0 | 0 | 8,299 |
| Supplemental cash flow information related to leases: | |||
| Cash paid for amounts included in the measurement of lease liabilities - operating cash flows from operating leases | 19,541 | 14,284 | 12,768 |
| Right-of-use assets obtained in exchange for new operating lease obligations | 4,874 | 25,469 | 8,306 |
| Supplemental Cash Flow Information [Line Items] | |||
| Non-cash investing activities | 0 | 4,911,186 | 0 |
| Non-cash financing activities | 0 | 3,481,312 | 0 |
| HighPoint | |||
| Supplemental non-cash investing and financing activities: | |||
| Non-cash investing activities | 542,600 | ||
| Non-cash financing activities | 374,900 | ||
| Supplemental Cash Flow Information [Line Items] | |||
| Non-cash investing activities | 542,600 | ||
| Non-cash financing activities | $ 374,900 | ||
| Extraction | |||
| Supplemental non-cash investing and financing activities: | |||
| Non-cash investing activities | 2,100,000 | ||
| Non-cash financing activities | 1,800,000 | ||
| Supplemental Cash Flow Information [Line Items] | |||
| Non-cash investing activities | 2,100,000 | ||
| Non-cash financing activities | $ 1,800,000 | ||
| Crestone Peak | |||
| Supplemental non-cash investing and financing activities: | |||
| Non-cash investing activities | 2,300,000 | ||
| Non-cash financing activities | 1,300,000 | ||
| Supplemental Cash Flow Information [Line Items] | |||
| Non-cash investing activities | 2,300,000 | ||
| Non-cash financing activities | $ 1,300,000 | ||
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) - Costs Incurred in Oil and Natural Gas Producing Activities (Details) - USD ($) $ in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2022 |
Dec. 31, 2021 |
Dec. 31, 2020 |
|
| Results of Operations, Revenue from Oil and Gas Producing Activities [Abstract] | |||
| Acquisition | $ 437,100 | $ 4,861,619 | $ 11,296 |
| Development | 1,044,392 | 315,746 | 55,934 |
| Exploration | 6,981 | 7,937 | 595 |
| Total | 1,488,473 | 5,185,302 | 67,825 |
| Acquisition costs for unproved properties | 16,800 | 648,000 | 2,300 |
| Proved property acquisitions | 420,300 | 4,200,000 | 9,000 |
| Workover costs charged to lease operating expense | 8,600 | 2,200 | 1,200 |
| Increase (decrease) in ARO | $ 64,700 | $ 13,800 | $ (1,000) |
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) - Change in Quantities of Proved Oil, Natural Gas Liquids, and Natural Gas Reserves (Details) bbl in Thousands, Mcf in Thousands, MBoe in Millions, Boe in Millions |
12 Months Ended | |||
|---|---|---|---|---|
|
Dec. 31, 2022
Boe
$ / bbl
$ / MMBTU
Mcf
bbl
|
Dec. 31, 2021
Boe
$ / MMBTU
$ / bbl
bbl
Mcf
|
Dec. 31, 2020
Boe
MBoe
$ / MMBTU
$ / bbl
bbl
Mcf
|
Dec. 31, 2019
MBoe
$ / MMBTU
$ / bbl
Mcf
bbl
|
|
| Proved reserves demoted to non-proved | ||||
| Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
| Proved developed and undeveloped reserve, revision upward (reduction) of previous estimate (energy) | Boe | (0.2) | (24.1) | (22.9) | |
| Proved developed and undeveloped reserve, drilling program, term | 5 years | |||
| Wattenberg Field, Rocky Mountain Region | ||||
| Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
| Proved developed and undeveloped reserve, revision upward (reduction) of previous estimate (energy) | Boe | 25.4 | (20.0) | 7.5 | |
| Wattenberg Field, Rocky Mountain Region | Price-Related Revisions | ||||
| Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
| Proved developed and undeveloped reserve, revision upward (reduction) of previous estimate (energy) | Boe | 11.8 | |||
| Wattenberg Field, Rocky Mountain Region | Well Performance Forecasts and NGL Yields | ||||
| Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
| Proved developed and undeveloped reserve, revision upward (reduction) of previous estimate (energy) | Boe | 13.6 | |||
| Wattenberg Field, Rocky Mountain Region | Changes in Well Operating Cost Methodology | ||||
| Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
| Proved developed and undeveloped reserve, revision upward (reduction) of previous estimate (energy) | Boe | (13.1) | |||
| Wattenberg Field, Rocky Mountain Region | Engineering Revisions | ||||
| Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
| Proved developed and undeveloped reserve, revision upward (reduction) of previous estimate (energy) | Boe | (6.9) | 12.3 | ||
| Revisions to previous estimates - increase (decrease) | MBoe | 7.1 | (4.8) | ||
| Wattenberg Field, Rocky Mountain Region | Fuel, Gas, Interest, and Other Negative Revisions | ||||
| Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
| Proved developed and undeveloped reserve, revision upward (reduction) of previous estimate (energy) | Boe | (7.1) | |||
| Horizontal development | Wattenberg Field, Rocky Mountain Region | ||||
| Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
| Extensions, discoveries, and other additions | Boe | 27.9 | 0.0 | 18.0 | |
| Oil contracts | ||||
| Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
| Balance at the beginning of the period | 143,579 | 52,793 | 64,413 | |
| Extensions, discoveries and other additions | 12,408 | 19 | 9,376 | |
| Production | (27,651) | (4,523) | (5,019) | |
| Removed from capital program | (105) | (12,249) | (14,120) | |
| Purchases of minerals in place | 17,479 | 114,379 | 1,430 | |
| Revisions to previous estimates | 6,892 | (6,840) | (3,287) | |
| Balance at the end of the period | 152,602 | 143,579 | 52,793 | 64,413 |
| Proved developed reserves | 117,768 | 104,078 | 24,320 | |
| Proved undeveloped reserves | 34,834 | 39,501 | 28,473 | |
| Oil contracts | Wattenberg Field, Rocky Mountain Region | ||||
| Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
| Oil and gas commodity, price increase (in dollars per share) | $ / bbl | 27.11 | |||
| Oil and gas commodity price (in dollars per share) | $ / bbl | 93.67 | 66.56 | 39.57 | 55.85 |
| Gas contracts | ||||
| Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
| Balance at the beginning of the period | Mcf | 888,499 | 235,728 | 212,200 | |
| Extensions, discoveries and other additions | Mcf | 51,358 | 103 | 32,172 | |
| Production | Mcf | (112,478) | (13,852) | (14,166) | |
| Removed from capital program | Mcf | (459) | (43,918) | (33,886) | |
| Purchases of minerals in place | Mcf | 31,872 | 767,504 | 5,457 | |
| Revisions to previous estimates | Mcf | 8,708 | (57,066) | 33,951 | |
| Balance at the end of the period | Mcf | 867,500 | 888,499 | 235,728 | 212,200 |
| Proved developed reserves | Mcf | 750,793 | 748,762 | 123,220 | |
| Proved undeveloped reserves | Mcf | 116,707 | 139,737 | 112,508 | |
| Gas contracts | Wattenberg Field, Rocky Mountain Region | ||||
| Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
| Oil and gas commodity, price increase (in dollars per share) | $ / MMBTU | 2.76 | |||
| Oil and gas commodity price (in dollars per share) | $ / MMBTU | 6.36 | 3.60 | 1.99 | 2.58 |
| Natural gas liquids (per Bbl) | ||||
| Changes in quantities of proved oil, natural gas liquids and natural gas reserves | ||||
| Balance at the beginning of the period | 106,028 | 26,111 | 22,161 | |
| Extensions, discoveries and other additions | 6,936 | 0 | 3,269 | |
| Production | (15,666) | (1,763) | (1,858) | |
| Removed from capital program | (46) | (4,485) | (3,141) | |
| Purchases of minerals in place | 4,478 | 89,797 | 570 | |
| Revisions to previous estimates | 17,104 | (3,632) | 5,110 | |
| Balance at the end of the period | 118,834 | 106,028 | 26,111 | 22,161 |
| Proved developed reserves | 102,004 | 88,967 | 14,315 | |
| Proved undeveloped reserves | 16,830 | 17,061 | 11,796 | |
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) - Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves (Details) - USD ($) $ in Thousands |
12 Months Ended | ||
|---|---|---|---|
Dec. 31, 2022 |
Dec. 31, 2021 |
Dec. 31, 2020 |
|
| Results of Operations, Revenue from Oil and Gas Producing Activities [Abstract] | |||
| Future net cash flow discount rate | 10.00% | ||
| Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves | |||
| Future cash flows | $ 23,225,188 | $ 14,401,814 | $ 2,230,012 |
| Future production costs | (6,490,522) | (5,054,695) | (675,755) |
| Future development costs | (1,337,494) | (1,107,576) | (530,970) |
| Future income tax expense | (2,870,178) | (1,465,949) | 0 |
| Future net cash flows | 12,526,994 | 6,773,594 | 1,023,287 |
| 10% annual discount for estimated timing of cash flows | (4,599,504) | (2,361,490) | (586,233) |
| Standardized measure of discounted future net cash flows | 7,927,490 | 4,412,104 | 437,054 |
| Changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves | |||
| Beginning of period | 4,412,104 | 437,054 | 858,147 |
| Sale of oil and gas produced, net of production costs | (2,980,527) | (773,711) | (160,466) |
| Net changes in prices and production costs | 5,016,678 | 874,155 | (641,137) |
| Net changes in extensions, discoveries, and other additions | 638,537 | 855 | (54,269) |
| Development costs incurred | 411,138 | 108,113 | 42,325 |
| Changes in estimated development cost | (87,466) | 106,788 | 220,964 |
| Purchases of minerals in place | 627,833 | 4,484,125 | 12,372 |
| Revisions of previous quantity estimates | 619,800 | (84,126) | 60,754 |
| Net change in income taxes | (991,734) | (915,053) | 0 |
| Accretion of discount | 532,716 | 43,705 | 85,815 |
| Changes in production rates and other | (271,589) | 130,199 | 12,549 |
| End of period | $ 7,927,490 | $ 4,412,104 | $ 437,054 |
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) - Average Wellhead Prices Used in Determining Future Net Revenues (Details) |
12 Months Ended | ||
|---|---|---|---|
|
Dec. 31, 2022
$ / bbl
$ / MMcf
|
Dec. 31, 2021
$ / bbl
$ / MMcf
|
Dec. 31, 2020
$ / bbl
$ / MMcf
|
|
| Oil contracts | |||
| Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items] | |||
| Average sales price (in dollars per Bbl for oil and dollars per Mcf for gas) | 90.28 | 61.60 | 34.96 |
| Gas contracts | |||
| Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items] | |||
| Average sales price (in dollars per Bbl for oil and dollars per Mcf for gas) | $ / MMcf | 5.54 | 2.60 | 0.95 |
| Natural gas liquids (per Bbl) | |||
| Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items] | |||
| Average sales price (in dollars per Bbl for oil and dollars per Mcf for gas) | 39.05 | 30.60 | 6.12 |
SUBSEQUENT EVENTS (Details) - Subsequent Event - 2023 Share Repurchase - CPPIB Crestone Peak Resources Canada Inc. - Common Stock $ / shares in Units, shares in Millions, $ in Millions |
Jan. 27, 2023
USD ($)
$ / shares
shares
|
|---|---|
| Subsequent Event [Line Items] | |
| Stock repurchased (in shares) | shares | 4.9 |
| Stock repurchased, per share (in dollars per share) | $ / shares | $ 61.00 |
| Stock repurchased, purchase price | $ | $ 300 |