PDC Energy (PDCE) 10-K 22 Feb 23 2022 FY Annual report Financial data

Cover Page

Cover Page - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2022	Feb. 14, 2023	Jun. 30, 2022
Cover [Abstract]
ICFR Auditor Attestation Flag	true
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2022
Document Transition Report	false
Entity File Number	001-37419
Entity Registrant Name	PDC ENERGY, INC.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	95-2636730
Entity Address, Address Line One	1775 Sherman Street,
Entity Address, Address Line Two	Suite 3000
Entity Address, City or Town	Denver
Entity Address, State or Province	CO
Entity Address, Postal Zip Code	80203
City Area Code	303
Local Phone Number	860-5800
Title of 12(b) Security	Common Stock, par value $0.01 per share
Trading Symbol	PDCE
Security Exchange Name	NASDAQ
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Smaller Reporting Company	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		88,389,372
Entity Public Float			$ 5.9
Entity Central Index Key	0000077877
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	FY
Amendment Flag	false
Current Fiscal Year End Date	--12-31

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2022
Auditor [Line Items]
Auditor Firm ID	238
Auditor Location	Denver, Colorado
Auditor Name	PricewaterhouseCoopers LLP

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Current assets:
Cash and cash equivalents	$ 6,494	$ 33,829
Accounts receivable, net	546,311	398,605
Fair value of derivatives	31,963	17,909
Prepaid expense and other assets	8,987	8,230
Total current assets	593,755	458,573
Properties and equipment, net	7,293,355	4,814,865
Fair value of derivatives	25,562	15,177
Other assets	70,093	48,051
Total Assets	7,982,765	5,336,666
Current liabilities:
Accounts payable	244,406	127,891
Production tax liability	244,737	99,583
Fair value of derivatives	274,218	304,870
Funds held for distribution	539,094	285,861
Interest payable	11,655	10,482
Other accrued liabilities	106,082	91,409
Liabilities, Current, Total	1,420,192	920,096
Long-term debt	1,314,010	942,084
Deferred income taxes	507,683	26,383
Asset retirement obligations	171,665	127,526
Fair value of derivatives	53,600	95,561
Other liabilities	532,870	314,769
Total Liabilities	4,000,020	2,426,419
Commitments and contingencies
Shareholders' Equity:
Common shares - par value $0.01 per share, 150,000,000 authorized, 89,224,353 and 96,468,071 issued as of December 31, 2022 and 2021, respectively	892	965
Additional Paid in Capital	2,823,364	3,161,941
Retained Earnings (Accumulated Deficit)	1,165,816	(249,954)
Treasury shares - at cost, 119,336 and 54,960 as of December 31, 2022 and 2021, respectively	(7,327)	(2,705)
Total Stockholders' Equity	3,982,745	2,910,247
Liabilities and Equity, Total	$ 7,982,765	$ 5,336,666

Balance Sheet Parentheticals (P

Balance Sheet Parentheticals (Parentheticals) - USD ($)	Dec. 31, 2022	Dec. 31, 2021
Commitments and contingencies
Common Stock, Par or Stated Value Per Share	89,224,353	96,468,071
Common Stock, Par or Stated Value Per Share	150,000,000	150,000,000
Common Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Common shares - par value $0.01 per share, 150,000,000 authorized, 89,224,353 and 96,468,071 issued as of December 31, 2022 and 2021, respectively	$ 892,000	$ 965,000
Treasury Stock, Value	7,327,000	2,705,000
Treasury Stock, Carrying Basis	$ 119,336	$ 54,960

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Revenues:
Crude oil, natural gas and NGLs sales	$ 4,296,681	$ 2,552,558	$ 1,152,555
Commodity price risk management gain (loss), net	(463,611)	(701,456)	180,270
Other Income	12,663	4,808	6,401
Revenues, Total	3,845,733	1,855,910	1,339,226
Costs, expenses and other:
Lease operating expenses	262,986	180,659	161,346
Production tax expense	311,778	165,209	59,368
Transportation, gathering and processing expenses	124,577	100,403	77,835
Exploration, geologic and geophysical expense	13,079	1,064	1,376
General and administrative expense	156,276	127,733	161,087
Depreciation, depletion and amortization	749,657	635,184	619,739
Accretion of asset retirement obligations	13,408	12,086	10,072
Impairment of properties and equipment	6,762	402	882,393
Loss (gain) on sale of properties and equipment	212	(912)	(724)
Other expenses	0	2,490	10,272
Total cost, expenses and other	1,638,735	1,224,318	1,982,764
Income (loss) from operations	2,206,998	631,592	(643,538)
Interest expense	(64,734)	(82,698)	(88,684)
Income (Loss) before income taxes	2,232,321	548,894	(732,222)
Income tax benefit (expense)	(454,200)	(26,583)	7,902
Net Income (loss)	$ 1,778,121	$ 522,311	$ (724,320)
Basic	$ 18.76	$ 5.30	$ (7.37)
Diluted	$ 18.49	$ 5.22	$ (7.37)
Weighted-average common shares outstanding:
Basic	94,796	98,546	98,251
Diluted	96,174	100,154	98,251
Business Combination, Bargain Purchase, Gain Recognized, Amount	$ 90,057	$ 0	$ 0

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Cash flows from operating activities:
Net income (loss)	$ 1,778,121	$ 522,311	$ (724,320)
Adjustments to net income (loss) to reconcile to net cash provided by operating activities:
Net change in fair value of unsettled commodity derivatives	(416,278)	291,268	99,001
Depreciation, depletion and amortization	749,657	635,184	619,739
Impairment of properties and equipment	6,762	402	882,393
Accretion of asset retirement obligations	13,408	12,086	10,072
Non-cash stock-based compensation	26,846	23,023	22,200
Loss (gain) on sale of properties and equipment	(212)	912	724
Amortization of Debt Issuance Costs and Discounts	5,436	13,468	16,772
Gain (Loss) on Extinguishment of Debt	0	6,927	0
Deferred income taxes	452,900	26,383	(6,530)
Other	(374)	1,539	2,280
Accounts receivable	19,228	(153,717)	139,664
Other assets	16,364	24,678	(5,341)
Production tax liability	191,175	41,381	(50,803)
Accounts payable and accrued expenses	(44,677)	40,183	(66,183)
Funds held for distribution	80,670	108,729	(23,621)
Asset retirement obligations	(19,880)	(28,595)	(27,491)
Other liabilities	(8,947)	(17,454)	(17,753)
Net cash from operating activities	2,772,324	1,547,796	870,079
Cash flows from investing activities:
Capital expenditures for development of crude oil and natural gas properties	(1,069,543)	(583,108)	(550,964)
Payments to Acquire Other Property, Plant, and Equipment	18,159	894	1,634
Proceeds from sale of properties and equipment	717	5,073	1,641
Proceeds from divestitures	15,779	125	3,610
Net cash from investing activities	(2,149,516)	(578,804)	(687,159)
Net Cash Provided by (Used in) Financing Activities [Abstract]
Proceeds from revolving credit facility and other borrowings	2,683,200	802,800	1,799,350
Repayment of revolving credit facility and other borrowings	(2,313,200)	(970,800)	(1,635,350)
Proceeds from senior notes	0	0	148,500
Payment of debt issuance costs	(101)	(13,066)	(6,538)
Purchase of treasury shares for employee stock-based compensation tax withholding obligations	(18,105)	(6,038)	(9,345)
Proceeds from (Repurchase of) Equity	(818,325)	(156,795)	(23,819)
Repayments of Convertible Debt	0	(200,000)	0
Redemption of senior notes	0	(308,584)	(452,153)
Finance Lease, Principal Payments	(2,039)	(1,688)	(1,905)
Payments of Dividends	(181,573)	(83,615)	0
Net cash from financing activities	(650,143)	(937,786)	(181,260)
Net change in cash and cash equivalents	(27,335)	31,206	1,660
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	6,494	33,829	2,623
Capitalized Exploratory Well Cost, Charged to Expense	11,970		0
Business Combination, Bargain Purchase, Gain Recognized, Amount	(90,057)	0	0
Payments To Explore And Develop Oil And Gas Properties, Midstream Assets	(10,069)	0	0
Amortization of Debt Issuance Costs and Discounts	$ 5,436	$ 13,468	$ 16,772

Consolidated Statement of Equit

Consolidated Statement of Equity - USD ($) $ in Thousands	Total	Parent [Member]	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Treasury Stock [Member]	Treasury Stock, Common [Member]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]
Shares, Issued			61,652,000			35,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stockholders' Equity Attributable to Parent		$ 2,335,507
Purchase of treasury shares						(457,000)
Issuance of treasury shares			0			115,000
Stockholders' Equity Beginning, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2019			$ 617	$ 2,384,309	$ (47,945)	$ (1,474)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Purchase of treasury shares		9,345				(9,345)
Share-based Compensation expense	$ 22,200			19,738
Issuance of treasury shares		0		0		0
Net income (Loss) attributable to shareholders	(724,320)	(724,320)			(724,320)
Stock Issued During Period, Shares, Restricted Stock Award, Gross			530,000
Shares Issued, Value, Share-based Payment Arrangement, after Forfeiture		22,200	$ 5			2,457
Stockholders' Equity Ending, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2020			$ 998	3,387,754	(772,265)	$ (949)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock Repurchased and Retired During Period, Shares			(1,266,000)				1,266,000
Stock Repurchased and Retired During Period, Value	(3)	0	$ (12)	(23,807)			$ 23,819
Stock Issued During Period, Shares, Acquisitions			39,182,000
Stock Issued During Period, Value, Acquisitions		1,015,312	$ 391	1,014,921
Treasury Stock, Shares, Retired			(339,000)			339,000
Treasury Stock, Retired, Cost Method, Amount		3		(7,407)		$ 7,413
Stock Repurchased During Period, Shares							1,266,000
Stock Repurchased During Period, Value		(23,819)					$ (23,819)
Shares, Issued			99,759,000			38,000
Stockholders' Equity Attributable to Parent		2,615,538
Purchase of treasury shares						(181,000)
Issuance of treasury shares			0			89,000
Purchase of treasury shares		6,038				$ (6,038)
Share-based Compensation expense	23,023			20,831
Issuance of treasury shares		0		0		0
Net income (Loss) attributable to shareholders	522,311	522,311			522,311
Stock Issued During Period, Shares, Restricted Stock Award, Gross			531,000
Shares Issued, Value, Share-based Payment Arrangement, after Forfeiture		23,023	$ 5			2,187
Stockholders' Equity Ending, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2021			$ 965	3,161,941	(249,954)	$ (2,705)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock Repurchased and Retired During Period, Shares			(3,705,000)				3,711,000
Stock Repurchased and Retired During Period, Value	(1)	306	$ (37)	(157,058)			$ 157,401
Treasury Stock, Shares, Retired			(117,000)			117,000
Treasury Stock, Retired, Cost Method, Amount		0		(4,156)		$ 4,157
Stock Repurchased During Period, Shares							(3,753,000)
Stock Repurchased During Period, Value		(159,463)					$ (159,463)
Dividends, Common Stock	$ 83,600	(85,430)
Stockholders' Equity, Other				85,430	0
Common Stock, Dividends, Per Share, Declared	$ 0.86
Shares, Issued			96,468,000			55,000
Stockholders' Equity Attributable to Parent	$ 2,910,247	2,910,247
Purchase of treasury shares							283,000
Issuance of treasury shares			0			75,000
Purchase of treasury shares		18,105				$ 18,105
Share-based Compensation expense	26,846			22,673
Issuance of treasury shares		0		0		0
Net income (Loss) attributable to shareholders	1,778,121	1,778,121			1,778,121
Stock Issued During Period, Shares, Restricted Stock Award, Gross			1,038,000
Shares Issued, Value, Share-based Payment Arrangement, after Forfeiture		26,846	$ 10			4,163
Stockholders' Equity Ending, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2022			$ 892	2,823,364	1,165,816	$ (7,327)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock Repurchased and Retired During Period, Shares			(12,119,000)				12,119,000
Stock Repurchased and Retired During Period, Value	(2)	0	$ (121)	(584,199)	236,673		$ 820,993
Stock Issued During Period, Shares, Acquisitions			4,007,000
Stock Issued During Period, Value, Acquisitions		293,314	$ 40	293,274
Treasury Stock, Shares, Retired			(170,000)			170,000
Treasury Stock, Retired, Cost Method, Amount		0		(11,199)	(483)	$ 11,684
Stock Repurchased During Period, Shares							(12,145,000)
Stock Repurchased During Period, Value		(823,357)					$ (823,357)
Dividends, Common Stock	$ (184,300)	(184,321)		$ (59,126)
Stockholders' Equity, Other					$ (125,195)
Common Stock, Dividends, Per Share, Declared	$ 1.95
Shares, Issued			89,224,000			(119,000)
Stockholders' Equity Attributable to Parent	$ 3,982,745	$ 3,982,745

NATURE OF OPERATIONS AND BASIS

NATURE OF OPERATIONS AND BASIS OF PRESENTATION	12 Months Ended
	Dec. 31, 2022
NATURE OF OPERATIONS AND BASIS OF PRESENTATION [Abstract]
Nature of Operations [Text Block]	NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION PDC Energy, Inc. is a domestic independent exploration and production company that acquires, explores and develops properties for the production of crude oil, natural gas and NGLs, with operations in the Wattenberg Field in Colorado and the Delaware Basin in west Texas. Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays and our Delaware Basin operations are primarily focused in the horizontal Wolfcamp zones. As of December 31, 2022, we owned an interest in approximately 4,100 gross productive wells. The accompanying audited consolidated financial statements include the accounts of PDC and our wholly-owned subsidiaries. Pursuant to the proportionate consolidation method, our accompanying consolidated financial statements include our pro rata share of assets, liabilities, revenues and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated in consolidation.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2022
Accounting Policies [Abstract]
Significant Accounting Policies [Text Block]	NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Use of Estimates in the Preparation of Financial Statements. The preparation of our consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) requires us to make estimates and assumptions that affect the amounts reported on our consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to our consolidated financial statements include estimates of proved oil and natural gas reserves used in calculating depletion; estimates of unpaid revenues and unbilled costs; future cash flows from proved oil and natural gas reserves on proved oil and natural gas properties used in impairment assessment; valuation of commodity derivative instruments; the estimation of future abandonment obligations used in asset retirement obligations; valuation of proved and unproved crude oil and natural gas properties from purchased and exchanged businesses and assets; and valuation of deferred income tax assets. Cash and Cash Equivalents. The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. Cash and cash equivalents potentially subject us to a concentration of credit risk as substantially all of our deposits held in financial institutions were in excess of federal deposit insurance limits as of December 31, 2022 and 2021. We maintain our cash and cash equivalents in the form of money market and checking accounts with financial institutions that we believe are creditworthy and are also lenders under our revolving credit facility. Commodity Derivative Financial Instruments. Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas and NGLs. To manage a portion of our exposure to price volatility from producing crude oil and natural gas we enter into commodity derivative contracts to protect against price declines in future periods. We have elected not to designate any of our commodity derivative instruments as cash flow hedges; therefore, these instruments do not qualify for hedge accounting. Accordingly, realized gains and losses from the settlement of commodity derivatives and unrealized gains and losses from changes in the fair value of remaining unsettled commodity derivatives are presented as a component of revenues in the consolidated statements of operations. Under applicable accounting standards, the fair value of each derivative instrument is recorded as either an asset or liability on the consolidated balance sheet. We measure the fair value of our commodity 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. Properties and Equipment. Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. Under this method, costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depleted by the unit-of-production method based on estimated proved developed producing reserves. We have determined that we have two unit-of-production fields: the Wattenberg Field and the Delaware Basin. In making these conclusions we consider the geographic concentration, operating similarities within the areas, geologic considerations and common cost environments in these areas. We calculate quarterly depletion expense by using our estimated prior period-end reserves as the denominator, adjusted as necessary, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted for fourth quarter production. The process of estimating and evaluating crude oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. 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. Capitalized development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized as a gain or loss on the consolidated statements of operations. Exploration costs, including geological and geophysical expenses, seismic costs on unproved leaseholds and delay rentals are expensed as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but charged to expense if the well is determined to be economically nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as we have identified a sufficient quantity of reserves to justify completion as a producing well, we are making sufficient progress assessing our reserves and economic and operating viability or we have not made sufficient progress to allow for final determination of productivity. If an in-progress exploratory well is found to be economically unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expen se. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as suspended well costs until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the resulting accounting treatment is recorded. Unproved property costs not subject to depletion primarily include leasehold costs, broker and legal expenses and capitalized internal costs associated with developing oil and natural gas prospects on these properties. Leasehold costs are transferred into costs subject to depletion on an ongoing basis as these properties are evaluated and proved reserves are 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. Proved Property Impairment. Upon a triggering event, we assess the valuation of our proved crude oil and natural gas properties for possible impairment by comparing the carrying value to estimated undiscounted future net cash flows on a field-by-field basis using estimated production and prices at which we estimate the commodity will be sold. If carrying values exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a discounted future cash flows analysis. The impairment recorded is the amount by which the carrying values exceed the fair value. In the impairment assessment we estimate the fair value of proved crude oil and natural gas properties using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserves volumes, future operating and development costs, future commodity prices, and a market based weighted average cost of capital rate. Certain events, including but not limited to downward revisions in estimates of our reserve quantities, expectations of falling commodity prices or rising capital and operating costs, could result in a triggering event, and may result to a possible impairment of our proved crude oil and natural gas properties. Unproved Property Impairment. Acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to impairment expense. Unproved crude oil and natural gas properties with individually significant acquisition costs are assessed for impairment periodically, or if a triggering event is identified. We evaluate significant unproved properties for impairment based on future drilling plans and expected future lease expirations, primarily in areas where we have no development plans. Other Property and Equipment. Other property and equipment such as vehicles, facilities, midstream pipeline, office furniture and equipment, buildings, computer hardware and software and leasehold improvements is carried at cost. Depreciation is provided principally on the straight-line method over the assets’ estimated useful lives, which range from two to 35 years. Leasehold improvements are depreciated over the lesser of their useful lives or the term of the lease . Total depreciation expense related to other property and equipment was $7.8 million, $7.7 million and $8.7 million for the years ended December 31, 2022, 2021 and 2020, respectively. We review other property and equipment for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying value of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying value of the asset exceeds the estimated future cash flows, an impairment charge is recognized for the amount by which the carrying value of the asset exceeds its fair value. Internal-Use Software. Internal-use software costs incurred during the development stage of our enterprise resource planning software are capitalized. The development stage generally includes software design, configuration, testing and installation activities. Training and maintenance costs are expensed as incurred, while upgrades and enhancements are capitalized if it is probable that such expenditures will result in additional functionality. Capitalized internal-use software costs are depreciated over the estimated useful life of the underlying project on a straight-line basis upon completion of the project. Capitalized Interest. We capitalize interest on expenditures made in connection with exploration and development projects that are not subject to current depletion. Interest is capitalized only for the period that activities are in progress to bring unevaluated properties to its intended use. Interest capitalized may not exceed gross interest expense for the period. Capitalized interest totaled $21.5 million, $17.8 million and $19.7 million during the year ended December 31, 2022, 2021 and 2020, respectively. Income Taxes. We account for income taxes under the asset and liability method. We recognize deferred income tax assets and liabilities for the future tax consequences attributable to operating loss and credit carryforwards and differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. 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. The effect on deferred income tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. 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, we record a valuation allowance, thereby reducing the deferred income tax assets to what we consider realizable. We recognize 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 tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. Our policy is to recognize interest and penalties related to uncertain tax positions in interest expense. Debt Issuance Costs and Discounts. Debt issuance costs and discounts are capitalized and amortized over the life of the respective borrowings using the effective interest method. Debt issuance costs for the Senior Notes are included in long-term debt and the debt issuance costs for the revolving credit facility are included in other assets. Asset Retirement Obligations. We recognize the estimated liability for future costs associated with the plugging and abandonment of our oil and gas properties resulting from acquisition, construction or normal operation. We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the related well is completed. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the associated long-lived asset by the same amount as the liability. Over time, the liability is accreted for the change in the present value and recognized as accretion expense. The initial capitalized cost, net of salvage value, is depleted over the useful life of the related asset through a charge to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost (presented as part of properties and equipment). Revisions in estimated liabilities can result from, among other things, changes in retirement costs or the estimated timing of settling asset retirement obligations. Treasury Shares. We record treasury share purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as a reduction in shareholders’ equity. When we retire treasury shares, we charge any excess of cost over the par value to additional paid-in-capital (“APIC”), to the extent we have amounts in APIC, with any remaining excess cost being charged to retained earnings. Revenue Recognition. Crude oil, natural gas and NGLs revenues are recognized when we have transferred control of our production to the purchaser. We consider 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 crude oil, natural gas or NGLs production. We record revenues based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes delivered and prices received. We receive payment for sales one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded one to two months later. Historically, these differences have not been material. We account for natural gas imbalances using the sales method. For the years ending December 31, 2022, 2021 and 2020, the impact of any natural gas imbalances was not significant. Our crude oil, natural gas and NGLs sales are recorded using either the “net-back” or “gross” method of accounting, depending upon the related agreement. We use the net-back method when control of our commodity product has been transferred to the purchasers that are providing transportation, gathering or processing services. In these situations, the purchaser pays us proceeds based on a percent of the proceeds or have fixed our sales price at index less specified deductions. The net-back method results in the recognition of a net sales price that is lower than the index for which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid. We use the gross method of accounting when control of the crude oil, natural gas or NGLs is not transferred to the purchaser and the purchaser does not provide transportation, gathering or processing services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable transport and processing on a per unit basis. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering and processing expenses. For our product sales that have a contract term greater than one year, we utilized the practical expedient in ASC Topic 606 which states that we are not required to disclose the transaction price allocated to the remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, monthly sales of a product generally represent a separate performance obligation; therefore, future commodity volumes to be delivered and sold are wholly unsatisfied and disclosure of the transaction price allocated to such unsatisfied performance obligations is not required. Business Combinations. We utilize the acquisition method to account for acquisitions of businesses. Pursuant to the acquisition method, we allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. The purchase price allocations are based upon appraisals, discounted cash flows and estimates by management, which are Level 3 inputs. When appropriate, we review recent comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties. In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped and unproved crude oil and natural gas properties. To estimate the fair value of these properties as part of acquisition accounting, we estimate the fair value of proved crude oil and natural gas properties using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserves volumes, future operating and development costs, future commodity prices, and a market based weighted average cost of capital rate. The market based weighted average cost of capital rate is subject to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. Additionally, for acquisitions with significant unproved properties, we complete an analysis of recent comparable purchased properties to determine an estimation of fair value. If applicable, we record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. 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 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 in earnings, in accordance with Accounting Standards Codification 820, Fair Value Measurement . Stock-Based Compensation. Stock-based compensation is recognized within our financial statements based on the grant-date fair value of the equity instrument 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 and we account for forfeitures of stock-based compensation awards as they occur. Fair Value of Assets and Liabilities. The Company follows the authoritative accounting guidance for measuring fair value of assets and liabilities in its financial statements. Fair value is defined 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. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as: Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets. Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means. Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity. Leases. We determine if an arrangement is representative of a lease at contract inception. Right-of-use (“ROU”) 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. Operating and finance lease ROU assets and liabilities are recognized at the commencement date based on the present value of the expected lease payments over the lease term. As most of our leases do not provide an implicit interest rate, we utilize our incremental borrowing rate based on information available at the commencement date in determining the present value of lease payments. Subsequent measurement, as well as presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. Terms 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. Leases with an initial term of one year or less are not recorded on the consolidated balance sheets. We apply the practical expedient that permits combining lease and non-lease components in a contract and accounting for the combination as a single lease component (applied by asset class).

Business Combinations and Asset

Business Combinations and Asset Acquisitions	12 Months Ended
	Dec. 31, 2022
Business Combination and Asset Acquisition [Abstract]
Mergers, Acquisitions and Dispositions Disclosures [Text Block]	NOTE 3 - BUSINESS COMBINATION On May 6, 2022, we completed the acquisition of Great Western Petroleum, LLC (“Great Western”) for approximately $1.4 billion, inclusive of Great Western’s net debt (the “Great Western Acquisition”). Great Western was an independent oil and gas company focused on the exploration, production and development of crude oil and natural gas in the Wattenberg Field of Colorado. The consideration paid included $542.5 million in cash and approximately 4.0 million shares of our common stock, valued at $293.3 million on the acquisition date. In addition, we paid off the Great Western secured credit facility totaling $235.8 million and irrevocably deposited $361.2 million on Great Western’s behalf to pay and discharge on May 20, 2022 Great Western’s 12 percent senior secured notes due 2025, inclusive of unpaid accrued interest and a premium for early termination. The cash portion of the purchase price and the termination of Great Western’s debt were funded through a combination of cash on hand and availability under our revolving credit facility. Purchase Price Allocation The Great Western Acquisition has been accounted for using the acquisition method under Accounting Standards Codification (“ASC”) 805, Business Combinations , with PDC being treated as the accounting acquirer. Accordingly, we conducted assessments of the net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated fair values, while transaction and integration costs associated with the acquisition were expensed as incurred. The following table details our final purchase price, valuation and allocation of the purchase price to the assets acquired and liabilities assumed as a result of the Great Western Acquisition: (in thousands, except share and per share data) Consideration: Cash $ 542,500 Retirement of Great Western’s credit facility 235,822 Extinguishment of Great Western’s secured senior notes 361,231 Total cash consideration $ 1,139,553 Common stock issued 4,007,018 Fair value of PDC common stock on May 6, 2022 $ 73.20 Total fair value of common stock issued 293,314 Total consideration $ 1,432,867 Assets acquired: Cash $ 63,183 Accounts receivable 164,026 Other current assets 3,129 Properties and equipment, net - proved 2,091,301 Properties and equipment, net - other 7,035 Other noncurrent assets 20,345 Total assets acquired $ 2,349,019 Liabilities assumed: Accounts payable $ (119,142) Production tax liability (110,940) Funds held for distribution (170,708) Other current liabilities (19,203) Fair value of derivatives (319,600) Asset retirement obligations (25,300) Deferred tax liabilities (28,400) Other liabilities (32,802) Total liabilities assumed $ (826,095) Total identifiable net assets acquired $ 1,522,924 Gain on bargain purchase 90,057 Purchase price consideration $ 1,432,867 Determining the fair values of the assets and liabilities of Great Western requires judgement and certain assumptions to be made, the most significant of these being related to the valuation of crude oil and natural gas properties. The majority of the measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market, and therefore represent Level 3 inputs. The fair values of crude 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 and assumptions to the valuation of proved and unproved crude oil and natural gas properties include estimates of reserve volumes, future operating and development costs, future commodity prices and a market-based weighted-average cost of capital rate of 14.25 percent. These inputs require significant judgments and estimates by management at the time of the valuation. The fair value of derivative instruments was based on observable inputs, including forward commodity-price curves which are considered Level 2 inputs, and based on volatility factors which are considered Level 3 inputs. We completed our purchase price allocation analysis as of December 31, 2022, with immaterial adjustments made to the previous allocation. ASC 805, Business Combinations , requires that any excess of purchase price over the fair value of assets acquired, including identifiable intangibles and liabilities assumed, be recognized as goodwill and any excess of fair value of acquired net assets, including identifiable intangible assets over the acquisition consideration, results in a gain from bargain purchase. Prior to recording a gain, the acquiring entity must reassess whether all assets acquired and assumed liabilities have been identified and recognized and perform re-measurements to verify that the consideration paid, assets acquired and liabilities assumed have been properly valued. The Great Western Acquisition resulted in a gain on bargain purchase due to the estimated fair value of the identifiable net assets acquired exceeding the purchase consideration transferred by $90.1 million and is shown as a gain on bargain purchase on our consolidated statement of operations, net of related income taxes of $28.4 million . Upon completion of our assessment, we concluded that recording a gain on bargain purchase was appropriate and required under ASC 805. The bargain purchase was primarily attributable to the increase in commodity price forecasts from the date we entered into the definitive purchase agreement with Great Western, February 26, 2022, to the closing date of the acquisition, May 6, 2022, when the fair value of crude oil and natural gas reserves acquired were determined. Additionally, the majority of the acquisition consideration was fixed and therefore did not fluctuate as a result of market increases or decreases between the date of entry into the agreement through the closing date. The results of operations for the Great Western Acquisition since the closing date have been included on our consolidated financial statements for the year ended December 31, 2022 and include approximately $631.0 million of total revenues and $387.8 million of income from operations, respectively. During the year ended December 31, 2022, we recognized total transaction costs of $11.7 million, which are included in general and administrative expense on the consolidated statement of operations. Pro Forma Information . The following unaudited pro forma financial information represents a summary of the condensed consolidated results of operations for the year ended December 31, 2022 and 2021, assuming the acquisition had been completed as of January 1, 2021. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the acquisition had been effective as of these dates, or of future results. The information below reflects certain nonrecurring pro forma adjustments that were directly related to the business combination based on available information and certain assumptions that we believe are reasonable, including (i) our common stock issued to the owners of Great Western, (ii) the increase in depletion reflecting the relative fair values and production volumes attributable to Great Western’s properties and the revision to the depletion rate reflecting the reserve volumes acquired, (iii) adjustments to interest expense as a result of payoff of Great Western’s credit facility and secured senior notes, (iv) the adjustment to reflect the gain on bargain purchase, and (v) the estimated tax impacts of the pro forma adjustments. In addition, pro forma earnings were adjusted to exclude acquisition-related costs incurred by us and Great Western totaling approximately $33.6 million for the year ended December 31, 2022, and included the total costs of $33.6 million for the year ended December 31, 2021. Year Ended December 31, 2022 2021 (in thousands, except per share data) Total revenue $ 3,897,361 $ 2,277,463 Net income (loss) 1,651,029 563,855 Earnings (loss) per share: Basic $ 17.42 $ 5.50 Diluted 17.17 5.41

BUSINESS COMBINATIONS (Notes)

BUSINESS COMBINATIONS (Notes)	12 Months Ended
	Dec. 31, 2022
Acquisition [Abstract]
Mergers, Acquisitions and Dispositions Disclosures [Text Block]	NOTE 3 - BUSINESS COMBINATION On May 6, 2022, we completed the acquisition of Great Western Petroleum, LLC (“Great Western”) for approximately $1.4 billion, inclusive of Great Western’s net debt (the “Great Western Acquisition”). Great Western was an independent oil and gas company focused on the exploration, production and development of crude oil and natural gas in the Wattenberg Field of Colorado. The consideration paid included $542.5 million in cash and approximately 4.0 million shares of our common stock, valued at $293.3 million on the acquisition date. In addition, we paid off the Great Western secured credit facility totaling $235.8 million and irrevocably deposited $361.2 million on Great Western’s behalf to pay and discharge on May 20, 2022 Great Western’s 12 percent senior secured notes due 2025, inclusive of unpaid accrued interest and a premium for early termination. The cash portion of the purchase price and the termination of Great Western’s debt were funded through a combination of cash on hand and availability under our revolving credit facility. Purchase Price Allocation The Great Western Acquisition has been accounted for using the acquisition method under Accounting Standards Codification (“ASC”) 805, Business Combinations , with PDC being treated as the accounting acquirer. Accordingly, we conducted assessments of the net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated fair values, while transaction and integration costs associated with the acquisition were expensed as incurred. The following table details our final purchase price, valuation and allocation of the purchase price to the assets acquired and liabilities assumed as a result of the Great Western Acquisition: (in thousands, except share and per share data) Consideration: Cash $ 542,500 Retirement of Great Western’s credit facility 235,822 Extinguishment of Great Western’s secured senior notes 361,231 Total cash consideration $ 1,139,553 Common stock issued 4,007,018 Fair value of PDC common stock on May 6, 2022 $ 73.20 Total fair value of common stock issued 293,314 Total consideration $ 1,432,867 Assets acquired: Cash $ 63,183 Accounts receivable 164,026 Other current assets 3,129 Properties and equipment, net - proved 2,091,301 Properties and equipment, net - other 7,035 Other noncurrent assets 20,345 Total assets acquired $ 2,349,019 Liabilities assumed: Accounts payable $ (119,142) Production tax liability (110,940) Funds held for distribution (170,708) Other current liabilities (19,203) Fair value of derivatives (319,600) Asset retirement obligations (25,300) Deferred tax liabilities (28,400) Other liabilities (32,802) Total liabilities assumed $ (826,095) Total identifiable net assets acquired $ 1,522,924 Gain on bargain purchase 90,057 Purchase price consideration $ 1,432,867 Determining the fair values of the assets and liabilities of Great Western requires judgement and certain assumptions to be made, the most significant of these being related to the valuation of crude oil and natural gas properties. The majority of the measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market, and therefore represent Level 3 inputs. The fair values of crude 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 and assumptions to the valuation of proved and unproved crude oil and natural gas properties include estimates of reserve volumes, future operating and development costs, future commodity prices and a market-based weighted-average cost of capital rate of 14.25 percent. These inputs require significant judgments and estimates by management at the time of the valuation. The fair value of derivative instruments was based on observable inputs, including forward commodity-price curves which are considered Level 2 inputs, and based on volatility factors which are considered Level 3 inputs. We completed our purchase price allocation analysis as of December 31, 2022, with immaterial adjustments made to the previous allocation. ASC 805, Business Combinations , requires that any excess of purchase price over the fair value of assets acquired, including identifiable intangibles and liabilities assumed, be recognized as goodwill and any excess of fair value of acquired net assets, including identifiable intangible assets over the acquisition consideration, results in a gain from bargain purchase. Prior to recording a gain, the acquiring entity must reassess whether all assets acquired and assumed liabilities have been identified and recognized and perform re-measurements to verify that the consideration paid, assets acquired and liabilities assumed have been properly valued. The Great Western Acquisition resulted in a gain on bargain purchase due to the estimated fair value of the identifiable net assets acquired exceeding the purchase consideration transferred by $90.1 million and is shown as a gain on bargain purchase on our consolidated statement of operations, net of related income taxes of $28.4 million . Upon completion of our assessment, we concluded that recording a gain on bargain purchase was appropriate and required under ASC 805. The bargain purchase was primarily attributable to the increase in commodity price forecasts from the date we entered into the definitive purchase agreement with Great Western, February 26, 2022, to the closing date of the acquisition, May 6, 2022, when the fair value of crude oil and natural gas reserves acquired were determined. Additionally, the majority of the acquisition consideration was fixed and therefore did not fluctuate as a result of market increases or decreases between the date of entry into the agreement through the closing date. The results of operations for the Great Western Acquisition since the closing date have been included on our consolidated financial statements for the year ended December 31, 2022 and include approximately $631.0 million of total revenues and $387.8 million of income from operations, respectively. During the year ended December 31, 2022, we recognized total transaction costs of $11.7 million, which are included in general and administrative expense on the consolidated statement of operations. Pro Forma Information . The following unaudited pro forma financial information represents a summary of the condensed consolidated results of operations for the year ended December 31, 2022 and 2021, assuming the acquisition had been completed as of January 1, 2021. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the acquisition had been effective as of these dates, or of future results. The information below reflects certain nonrecurring pro forma adjustments that were directly related to the business combination based on available information and certain assumptions that we believe are reasonable, including (i) our common stock issued to the owners of Great Western, (ii) the increase in depletion reflecting the relative fair values and production volumes attributable to Great Western’s properties and the revision to the depletion rate reflecting the reserve volumes acquired, (iii) adjustments to interest expense as a result of payoff of Great Western’s credit facility and secured senior notes, (iv) the adjustment to reflect the gain on bargain purchase, and (v) the estimated tax impacts of the pro forma adjustments. In addition, pro forma earnings were adjusted to exclude acquisition-related costs incurred by us and Great Western totaling approximately $33.6 million for the year ended December 31, 2022, and included the total costs of $33.6 million for the year ended December 31, 2021. Year Ended December 31, 2022 2021 (in thousands, except per share data) Total revenue $ 3,897,361 $ 2,277,463 Net income (loss) 1,651,029 563,855 Earnings (loss) per share: Basic $ 17.42 $ 5.50 Diluted 17.17 5.41

Revenue Recognition Revenue Rec

Revenue Recognition Revenue Recognition (Notes)	12 Months Ended
	Dec. 31, 2022
Revenue from Contract with Customer [Abstract]
Revenue from Contract with Customer [Text Block]	NOTE 4 - REVENUE RECOGNITION Disaggregated Revenue. The following table presents crude oil, natural gas and NGLs sales disaggregated by commodity and operating region for the periods presented: Year Ended December 31, Revenue by Commodity and Operating Region 2022 2021 2020 (in thousands) Crude oil Wattenberg Field $ 2,154,435 $ 1,275,666 $ 668,948 Delaware Basin 423,784 255,135 147,902 Total 2,578,219 1,530,801 816,850 Natural gas Wattenberg Field 870,560 458,870 171,755 Delaware Basin 113,909 60,733 6,997 Total 984,469 519,603 178,752 NGLs Wattenberg Field 614,260 428,570 128,126 Delaware Basin 119,733 73,584 28,827 Total 733,993 502,154 156,953 Crude oil, natural gas and NGLs Wattenberg Field 3,639,255 2,163,106 968,829 Delaware Basin 657,426 389,452 183,726 Total $ 4,296,681 $ 2,552,558 $ 1,152,555

FAIR VALUE MEASUREMENTS AND DIS

FAIR VALUE MEASUREMENTS AND DISCLOSURES	12 Months Ended
	Dec. 31, 2022
Fair Value Disclosures [Abstract]
Fair Value Measurement and Measurement Inputs, Recurring and Nonrecurring [Text Block]	NOTE 5 - FAIR VALUE MEASUREMENTS Recurring Fair Value Measurements Derivative Financial Instruments. We measure the fair value of our commodity derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, interest rates, volatility factors and nonperformance risk. Non-performance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties’ credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default exchange rates and the duration of each outstanding derivative position. We use our counterparties’ valuations to assess reasonableness of our fair value measurement. Our crude oil and natural gas fixed-price exchanges and basis exchanges are included in Level 2. Our collars are included in Level 3. The following table presents, for each applicable level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis as of the dates indicated: December 31, 2022 December 31, 2021 Consolidated Balance Sheet Line Item Significant Other Significant Total Significant Other Significant Total (in thousands) Derivative assets Current Fair value of derivatives $ 9,178 $ 22,785 $ 31,963 $ — $ 17,909 $ 17,909 Non-current Fair value of derivatives 20,439 5,123 25,562 605 14,572 15,177 Total $ 29,617 $ 27,908 $ 57,525 $ 605 $ 32,481 $ 33,086 Derivative liabilities Current Fair value of derivatives $ (214,171) $ (60,047) $ (274,218) $ (230,695) $ (74,175) $ (304,870) Non-current Fair value of derivatives (49,749) (3,851) (53,600) (74,715) (20,846) (95,561) Total $ (263,920) $ (63,898) $ (327,818) $ (305,410) $ (95,021) $ (400,431) The following table presents a reconciliation of our Level 3 commodity derivative assets and liabilities measured at fair value for the periods presented: Year Ended December 31, 2022 2021 2020 (in thousands) Fair value of Level 3 instruments, net asset (liability) beginning of period $ (62,540) $ (8,427) $ 8,414 Commodity derivatives acquired from acquisition of business (22,716) — — Changes in fair value included in consolidated statements of operations line item: Commodity price risk management gain (loss), net (192,694) (206,109) 37,821 Settlements included in consolidated statements of operations line items: Commodity price risk management gain (loss), net 241,960 151,996 (54,662) Fair value of Level 3 instruments, net asset (liability) end of period $ (35,990) $ (62,540) $ (8,427) Net change in fair value of Level 3 unsettled derivatives included in consolidated statements of operations line item: Commodity price risk management gain (loss), net $ (31,367) $ (35,108) $ — Total $ (31,367) $ (35,108) $ — The significant unobservable input used in the fair value measurement of our derivative contracts is the implied volatility curve. A significant increase or decrease in the implied volatility, in isolation, would have a directionally similar effect resulting in a significantly higher or lower fair value measurement of our Level 3 derivative contracts. There has been no change in the methodology we apply to measure the fair value of our Level 3 derivative contracts during the periods covered by the financial statements. Nonrecurring Fair Value Measurements Acquisitions and Impairment of Long-lived Assets. We measure fair value using inputs that are not observable in the market, and are therefore designated as Level 3 within the valuation hierarchy, on a nonrecurring basis for any acquired assets or businesses and to review our proved and unproved crude oil and natural gas properties for possible impairment. The most significant fair value determinations for non-financial assets and liabilities are related to crude oil and gas properties acquired. See Note 3 - Business Combination for additional information . Asset Retirement Obligations. We measure the fair value of asset retirement obligations as of the date a well begins drilling or when production equipment and facilities are installed using a discounted cash flow model based on inputs that are not observable in the market and therefore are designated as Level 3 within the valuation hierarchy. Other Financial Instruments The carrying value of the financial instruments included in current assets and current liabilities approximates fair value due to the short-term maturities of these instruments. Long-term Debt. The portion of our long-term debt related to our revolving credit facility approximates fair value, as the applicable interest rates are variable and reflective of market rates. We have elected not to account for the portion of our debt related to our senior notes under the fair value option; however, we have determined an estimate of the fair values based on measurements of trading activity and broker or dealer quotes, which are published market prices, and therefore are Level 2 inputs. The table below presents these estimates of the fair value of the portion of our long-term debt related to our senior notes as of the dates indicated: December 31, 2022 2021 Nominal Interest Estimated Fair Value Percent of Par Estimated Fair Value Percent of Par (in millions) (in millions) 2024 Senior Notes 6.125 % 198.4 99.2 % 202.8 101.4 % 2026 Senior Notes 5.75 % 716.0 95.5 % 775.5 103.4 %

DERIVATIVE FINANCIAL INSTRUMENT

DERIVATIVE FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities Disclosure [Text Block]	NOTE 6 - COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS Objective and Strategy. Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas and NGLs. To manage a portion of our exposure to price volatility from producing crude oil and natural gas we enter into commodity derivative contracts such as collars, fixed-price exchanges and basis protection exchanges, to protect against price declines in future periods. We do not enter into derivative contracts for speculative or trading purposes. We believe our commodity derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. Depending on changes in crude oil and natural gas futures markets and management’s view of underlying supply and demand trends, we may increase or decrease our derivative positions from current levels. As of December 31, 2022, we had derivative instruments in place for a portion of our anticipated production in 2023 through 2025. Our commodity derivative contracts have been entered into at no upfront cost to us as we hedge our anticipated production at the then-prevailing commodity market prices, without adjustment for premium or discount. As of December 31, 2022 and 2021, our derivative instruments were comprised of fixed-price swaps, collars and basis protection swaps. • Fixed-price swaps are arrangements that guarantee a fixed price. If the index price is below the fixed contract price, we receive the market price from the purchaser and receive the difference between the index price and the fixed contract price from the counterparty. If the index price is above the fixed contract price, we receive the market price from the purchaser and pay the difference between the index price and the fixed contract price to the counterparty. • Collars contain a fixed floor price (put) and ceiling price (call). If the index price falls below the fixed put strike price, we receive the market price from the purchaser and receive the difference between the put strike price and index price from the counterparty. If the index price exceeds the fixed call strike price, we receive the market price from the purchaser and pay the difference between the call strike price and index price to the counterparty. If the index price is between the put and call strike price, no payments are due to or from the counterparty. • Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For basis protection swaps, we receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract. Effect of Derivative Instruments on the Consolidated Statements of Operations. The following table presents the impact of our derivative instruments on our consolidated statements of operations for the periods presented: Year Ended December 31, Consolidated Statements of Operations Line Item 2022 2021 2020 (in thousands) Commodity price risk management gain (loss), net Net settlements $ (879,889) $ (410,188) $ 279,271 Net change in fair value of unsettled derivatives 416,278 (291,268) (99,001) Total commodity price risk management gain (loss), net $ (463,611) $ (701,456) $ 180,270 Commodity Derivative Contracts. As of December 31, 2022, we had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is presented: Collars Fixed-Price Swaps Commodity/ Index/ Quantity (Crude oil - MBbls Natural Gas - BBtu) Weighted Average Contract Price Quantity (Crude Oil - MBbls Gas and Basis- BBtu) Weighted Average Contract Price Fair Value December 31, 2022 (in thousands) Floors Ceilings Crude Oil NYMEX 2023 5,937 $ 61.27 $ 83.11 9,804 $ 66.42 $ (156,820) 2024 825 65.91 89.58 6,126 70.59 (17,042) 2025 — — — 2,640 75.10 12,262 Total Crude Oil 6,762 18,570 (161,600) Natural Gas NYMEX 2023 26,864 3.48 6.03 41,825 3.05 (51,443) 2024 — — — 26,160 3.54 (17,511) 2025 — — — 6,225 4.87 2,640 26,864 74,210 (66,314) CIG 2023 — — — 8,760 3.39 (7,657) 2025 — — — 4,800 3.10 (4,370) — 13,560 (12,027) Total Natural Gas 26,864 87,770 (78,341) Basis Protection - Natural Gas CIG 2023 — — — 67,742 (0.26) (26,335) 2024 — — — 26,160 (0.39) (3,329) 2025 — — — 6,225 (0.37) (688) Total Basis Protection - Natural Gas — 100,127 (30,352) Commodity Derivatives Fair Value $ (270,293) Effect of Derivative Instruments on the Consolidated Balance Sheet. The balance sheet line items and fair value amounts of our derivative instruments are disclosed in Note 5 - Fair Value Measurements . Our financial derivative agreements contain master netting provisions that provide for the net settlement of contracts through a single payment in the event of early termination. We have elected not to offset the fair value positions recorded on our consolidated balance sheets. The following table reflects the impact of netting agreements on gross derivative assets and liabilities: Total Gross Amount Presented on the Balance Sheet Effect of Master Netting Agreements Total Net Amount As of December 31, 2022 (in thousands) Derivative asset instruments, at fair value $ 57,525 $ (57,525) $ — Derivative liability instruments, at fair value $ 327,818 $ (57,525) $ 270,293 As of December 31, 2021 Derivative asset instruments, at fair value $ 33,086 $ (33,086) $ — Derivative liability instruments, at fair value $ 400,431 $ (33,086) $ 367,345 Derivative Counterparties. Our commodity derivative instruments expose us to the risk of non-performance by our counterparties. We use financial institutions who are also lenders under our revolving credit facility as counterparties to our commodity derivative contracts. To date, we have had no derivative counterparty default losses. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of non-performance of our current counterparties on the fair value of our derivative instruments is not significant at December 31, 2022; however, this determination may change.

Accounts Receivable, Other Accr

Accounts Receivable, Other Accrued Expenses and Other Liabilities	12 Months Ended
	Dec. 31, 2022
Concentration Risks, Types, No Concentration Percentage [Abstract]
Accounts Receivable, Other Accrued Expenses and Other Liabilities	NOTE 8 - ACCOUNTS RECEIVABLE, OTHER ACCRUED EXPENSES AND OTHER LIABILITIES Accounts Receivable. The following table presents the components of accounts receivable, net of allowance for doubtful accounts as of the dates indicated: December 31, 2022 2021 (in thousands) Crude oil, natural gas and NGLs sales $ 491,327 $ 368,991 Joint interest billings 46,633 24,860 Other 13,796 10,809 Allowance for doubtful accounts (5,445) (6,055) Accounts receivable, net $ 546,311 $ 398,605 The Company’s accounts receivable consist mainly of receivables from (i) crude oil, natural gas and NGLs purchasers, (ii) joint interest owners in the properties we operate and (iii) derivative counterparties. Most payments for production are received within two months after the production date. For receivables from joint interest owners, we typically have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Credit and Concentration Risk. Inherent to our industry is the concentration of crude oil, natural gas and NGLs sales to a limited number of customers. This concentration has the potential to impact our overall exposure to credit risk in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. Given the liquidity in the market for the sale of hydrocarbons, we believe that the loss of any single purchaser, or the aggregate loss of several purchasers, could be managed by selling to alternative purchasers in our operating areas. The following major customers accounted for 10 percent or more of our total crude oil, natural gas, and NGLs sales for at least one of the periods presented: Year Ended December 31, 2022 2021 2020 Major customer #1 27 % 32 % 31 % Major customer #2 9 % 9 % 16 % Major customer #3 7 % 11 % 13 % Major customer #4 5 % 10 % 17 % Other Accrued Expenses. The following table presents the components of other accrued expenses as of the dates indicated: December 31, 2022 2021 (in thousands) Employee benefits $ 29,288 $ 29,319 Asset retirement obligations 25,986 32,146 Environmental expenses 25,666 11,942 Operating and finance leases 5,987 7,197 Other 19,155 10,805 Other accrued expenses $ 106,082 $ 91,409 Other Liabilities. The following table presents the components of other liabilities as of the dates indicated: December 31, 2022 2021 (in thousands) Deferred midstream gathering credits $ 145,937 $ 159,788 Production taxes 315,758 131,865 Operating and finance leases 41,815 6,274 Other 29,360 16,842 Other liabilities $ 532,870 $ 314,769 Deferred Midstream Gathering Credits. In 2019, we entered into agreements pursuant to which we dedicated the gathering of some of our production and all water gathering and disposal volumes in the Delaware Basin. The terms of these agreements range from 15 to 22 years. The acreage dedication agreements resulted in initial cash receipts and are being amortized on a units-of-production basis. The amortization rates are assessed on an annual basis for changes in estimated future production. The following table presents the amortization charges related to our deferred credits recognized on the consolidated statements of operations for the periods indicated: Year Ended December 31, 2022 2021 (in thousands) Transportation, gathering and processing expense $ 11,037 $ 7,317 Lease operating expense 3,753 2,422

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2022
Debt Disclosure [Abstract]
Long-term Debt [Text Block]	NOTE 9 - LONG-TERM DEBT Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $6.0 million and $7.9 million as of December 31, 2022 and December 31, 2021, respectively, consists of the following: December 31, 2022 2021 (in thousands) Revolving credit facility due November 2026 $ 370,000 $ — 6.125% Senior Notes due September 2024 199,163 198,674 5.75% Senior Notes due May 2026 744,847 743,410 Total debt, net of unamortized discount, premium and debt issuance costs $ 1,314,010 $ 942,084 Revolving Credit Facility In November 2021, we entered into a Fifth Amended and Restated Credit Agreement (the “Restated Credit Agreement”), which provides for a maximum credit amount of $2.5 billion , subject to certain limitations, an initial borrowing base of $2.4 billion and an elected commitment of $1.5 billion . The Restated Credit Agreement matures on the earlier to occur of (i) the end of the five year term on November 2, 2026 or (ii) the date that is 91 days prior to the scheduled maturity of the 2026 Senior Notes if the aggregate outstanding principal amount of those notes exceeds $500 million and our commitment utilization exceeds 50%. In the semi-annual redetermination that occurred in 2022, the borrowing base increased from $3.0 billion to $3.5 billion as a result of the reserves acquired in the Great Western Acquisition; however, we maintained our elected commitment amount of $1.5 billion . The revolving credit facility is available for working capital requirements, capital investments, acquisitions, to support letters of credit and for general business purposes. The borrowing base is based on, among other things, the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests. The borrowing base is subject to a semi-annual redetermination on November 1 and May 1 based upon quantification of our reserves at June 30 and December 31, and is also subject to a redetermination upon the occurrence of certain events. Substantially all of our crude oil and natural gas properties have been mortgaged or pledged as security for our revolving credit facility. The Restated Credit Agreement includes an investment grade period election pursuant to which we have an option to remove our borrowing base limitations and terminate the liens securing the Restated Credit Agreement when certain debt ratings are achieved. As of December 31, 2022, we had a borrowing base of $3.5 billion, an elected commitment of $1.5 billion and availability under our revolving credit facility of $1.1 billion, net of $20.4 million of letters of credit outstanding. The outstanding principal amount under the revolving credit facility accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greatest of the administrative agent's prime rate, the federal funds rate plus a premium and the rate for dollar deposits in the Secured Overnight Financing Rate (“SOFR”) for one month, plus a premium) or, at our election, a rate equal to SOFR for certain time periods. Additionally, commitment fees, interest margin and other bank fees, charged as a component of interest, vary with our utilization of the facility. As of December 31, 2022, the applicable interest margin is 0.75 percent for the alternate base rate option or 1.75 percent for the SOFR option, and the unused commitment fee is 0.375 percent. Principal payments are generally not required until the maturity date of the revolving credit facility, unless the borrowing base falls below the outstanding balance. The Restated Credit Agreement also includes the ability to add certain sustainability-linked key performance indicators to be agreed upon between us, the administrative agent and a majority of the lenders and that may impact the applicable margin and commitment fee rate. The revolving credit facility contains various restrictive covenants and compliance requirements, which include, among other things: (i) maintenance of certain financial ratios, as defined per the revolving credit facility, including a minimum current ratio of 1.0:1.0 and a maximum leverage ratio of 3.5:1.0; (ii) restrictions on the payment of cash dividends; (iii) limits on the incurrence of additional indebtedness; (iv) prohibition on the entry into commodity hedges exceeding a specified percentage of our expected production; and (v) restrictions on mergers and dispositions of assets. As of December 31, 2022, we were in compliance with all covenants related to our revolving credit facility. As of December 31, 2022 and 2021, debt issuance costs related to our revolving credit facility were $13.5 million and $16.9 million, respectively, and are included in other assets on our consolidated balance sheets. Senior Notes The following table summarizes the face values, interest rates, maturity dates, semi-annual interest payment dates, and optional redemption periods related to our outstanding senior note obligations as of December 31, 2022: 2024 Senior Notes 2026 Senior Notes Outstanding principal amounts (in thousands) $ 200,000 $ 750,000 Interest rate 6.125 % 5.75 % Maturity date September 15, 2024 May 15, 2026 Interest payment dates March 15, September 15 May 15, November 15 Redemption periods (1) September 15, 2022 May 15, 2024 _____________ (1) At any time prior to the indicated dates, we have the option to redeem all or a portion of our senior notes of the applicable series at the redemption amounts specified in the respective senior note indenture plus accrued and unpaid interest to the date of redemption. On or after the indicated dates, we may redeem all or a portion of the senior notes at a redemption amount equal to 100% of the principal amount of the senior notes being redeemed plus accrued and unpaid interest to the date of redemption. The 2024 Senior Notes and the 2026 Senior Notes (collectively, the “Senior Notes”) are senior unsecured obligations and rank senior in right of payment to our future indebtedness that is expressly subordinated to the notes; equal in right of payment to our existing and future indebtedness that is not so subordinated; effectively junior in right of payment to all of our secured indebtedness to the extent of the value of the assets securing such indebtedness; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our non-guarantor subsidiaries. Upon the occurrence of a “change of control”, as defined in the indentures for the Senior Notes, holders will have the right to require us to repurchase all or a portion of the notes at a price equal to 101 percent of the aggregate principal amount of the notes repurchased, together with accrued and unpaid interest to the date of purchase. In connection with certain asset sales, we may, under certain circumstances, be required to use the net cash proceeds of such asset sale to make an offer to purchase the notes at 100 percent of the principal amount, together with accrued and unpaid interest to the date of purchase.

Leases Operating and Financing

Leases Operating and Financing Leases (Notes)	12 Months Ended
	Dec. 31, 2022
Leases [Abstract]
Leases	NOTE 10 - LEASES We have operating leases for office space and well equipment, and finance leases for vehicles. Our leases have remaining lease terms ranging from one month to ten years. The vehicle leases include an option to renew on a month-to-month basis after the primary term. Lease payments associated with vehicle leases also include a contractually stated residual value guarantee. The following table presents the components of lease costs for the periods presented: Year Ended December 31, 2022 2021 (in thousands) Operating lease costs (1) $ 6,743 $ 6,125 Finance lease costs: Amortization of ROU assets 2,100 1,752 Interest on lease liabilities 270 164 Total finance lease costs 2,370 1,916 Short-term lease costs (1) 338,404 203,361 Total lease costs $ 347,517 $ 211,402 _______________ (1) The lease costs presented in the table above represent the total gross costs we incur, which are not comparable to our net costs recorded to the consolidated statements of operations, consolidated statements of cash flows or capitalized in the consolidated balance sheets, as amounts therein are reflected net of amounts billed to working interest partners. Our operating lease costs are recorded in lease operating expenses or general and administrative expense and our finance lease costs are recorded in DD&A expense and interest expense. Our short-term lease costs include amounts that are capitalized as part of the cost of assets and are recorded as properties and equipment or recognized as expense. The following table presents the balance sheet classification and other information regarding our leases as of the dates indicated: December 31, Leases Consolidated Balance Sheet Line Item 2022 2021 (in thousands) Operating lease ROU assets Other assets $ 19,577 $ 7,630 Finance lease ROU assets Properties and equipment, net 6,184 3,483 Total ROU assets $ 25,761 $ 11,113 Operating lease obligation - short-term Other accrued expenses $ 3,825 $ 5,937 Operating lease obligation - long-term Other liabilities 37,720 4,044 Finance lease obligation - short-term Other accrued expenses 2,162 1,260 Finance lease obligation - long-term Other liabilities 4,095 2,230 Total lease liabilities $ 47,802 $ 13,471 December 31, Leases Consolidated Balance Sheet Line Item 2022 2021 (in thousands) Weighted average remaining lease term (years) 7.9 2.8 Weighted average discount rate 5.1 % 4.8 % Maturity of lease liabilities by year and in the aggregate, under operating and financing leases with terms of one year or more, as of December 31, 2022 consist of the following: Operating Leases Finance Leases Total (in thousands) 2023 $ 4,063 $ 2,404 $ 6,467 2024 3,101 1,891 4,992 2025 6,682 1,698 8,380 2026 6,754 649 7,403 2027 5,821 73 5,894 Thereafter 27,512 — 27,512 Total lease payments 53,933 6,715 60,648 Less: Interest and discount (12,388) (458) (12,846) Present value of lease liabilities $ 41,545 $ 6,257 $ 47,802
Leases	NOTE 10 - LEASES We have operating leases for office space and well equipment, and finance leases for vehicles. Our leases have remaining lease terms ranging from one month to ten years. The vehicle leases include an option to renew on a month-to-month basis after the primary term. Lease payments associated with vehicle leases also include a contractually stated residual value guarantee. The following table presents the components of lease costs for the periods presented: Year Ended December 31, 2022 2021 (in thousands) Operating lease costs (1) $ 6,743 $ 6,125 Finance lease costs: Amortization of ROU assets 2,100 1,752 Interest on lease liabilities 270 164 Total finance lease costs 2,370 1,916 Short-term lease costs (1) 338,404 203,361 Total lease costs $ 347,517 $ 211,402 _______________ (1) The lease costs presented in the table above represent the total gross costs we incur, which are not comparable to our net costs recorded to the consolidated statements of operations, consolidated statements of cash flows or capitalized in the consolidated balance sheets, as amounts therein are reflected net of amounts billed to working interest partners. Our operating lease costs are recorded in lease operating expenses or general and administrative expense and our finance lease costs are recorded in DD&A expense and interest expense. Our short-term lease costs include amounts that are capitalized as part of the cost of assets and are recorded as properties and equipment or recognized as expense. The following table presents the balance sheet classification and other information regarding our leases as of the dates indicated: December 31, Leases Consolidated Balance Sheet Line Item 2022 2021 (in thousands) Operating lease ROU assets Other assets $ 19,577 $ 7,630 Finance lease ROU assets Properties and equipment, net 6,184 3,483 Total ROU assets $ 25,761 $ 11,113 Operating lease obligation - short-term Other accrued expenses $ 3,825 $ 5,937 Operating lease obligation - long-term Other liabilities 37,720 4,044 Finance lease obligation - short-term Other accrued expenses 2,162 1,260 Finance lease obligation - long-term Other liabilities 4,095 2,230 Total lease liabilities $ 47,802 $ 13,471 December 31, Leases Consolidated Balance Sheet Line Item 2022 2021 (in thousands) Weighted average remaining lease term (years) 7.9 2.8 Weighted average discount rate 5.1 % 4.8 % Maturity of lease liabilities by year and in the aggregate, under operating and financing leases with terms of one year or more, as of December 31, 2022 consist of the following: Operating Leases Finance Leases Total (in thousands) 2023 $ 4,063 $ 2,404 $ 6,467 2024 3,101 1,891 4,992 2025 6,682 1,698 8,380 2026 6,754 649 7,403 2027 5,821 73 5,894 Thereafter 27,512 — 27,512 Total lease payments 53,933 6,715 60,648 Less: Interest and discount (12,388) (458) (12,846) Present value of lease liabilities $ 41,545 $ 6,257 $ 47,802

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2022
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation Disclosure [Text Block]	NOTE 11 - ASSET RETIREMENT OBLIGATIONS The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interests in crude oil and natural gas properties for the periods presented: Year Ended December 31, 2022 2021 (in thousands) Beginning balance $ 159,672 $ 166,570 Obligations incurred with development activities and other 5,332 4,750 Obligations incurred with acquisition 25,300 — Accretion expense 13,408 12,086 Revisions in estimated cash flows 19,606 10,609 Obligations discharged with asset retirements and divestitures (25,667) (34,343) Asset retirement obligations at end of period 197,651 159,672 Current portion (1) (25,986) (32,146) Long-term portion $ 171,665 $ 127,526 _______________ (1) The current portion of the asset retirement obligation is included in other accrued expenses on our consolidated balance sheets.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2022
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies Disclosure	NOTE 12 - COMMITMENTS AND CONTINGENCIES The following table presents our firm transportation, sales and processing, water delivery and disposal and purchase commitments: Year Ending December 31, (in thousands) 2023 2024 2025 2026 2027 Thereafter Total Firm transportation $ 96,567 $ 64,403 $ 49,187 $ 36,692 $ 10,388 $ 28,364 $ 285,601 Gas gathering and processing agreements 117,828 117,509 101,553 61,633 35,608 43,801 477,932 $ 214,395 $ 181,912 $ 150,740 $ 98,325 $ 45,996 $ 72,165 $ 763,533 Firm Transportation and Processing Agreements. We enter into certain contracts that provide firm transportation and processing on pipeline systems through which we transport or sell crude oil and natural gas. Under certain of these agreements, we are obligated to ship minimum daily quantities of crude oil or natural gas or pay for any deficiencies at a specified rate or incremental charges. Satisfaction of the volume requirements includes volumes produced by us and purchased from third parties and produced by other third-party working, royalty and overriding royalty interest owners, whose volumes we market on their behalf. We may from time to time find ourselves unable to market our commodities at prices acceptable to us, or at all, which could cause us to be unable to meet these obligations. In such cases, we may be subject to fees, minimum margins or other payments. Our consolidated statements of operations reflect our share of these firm transportation and processing costs. Payments related to our long-term transportation and processing agreements, net of interests, were $64.1 million, $31.3 million, and $21.4 million for the years ended December 31, 2022, 2021, and 2020, respectively. For the years ended December 31, 2022 and 2021, we did not incur material transportation reservation charges under these agreements. Gas Gathering and Processing Agreements. We entered into certain long-term gas gathering and processing agreements pursuant to which we are obligated to deliver minimum daily quantities of natural gas to certain gas gathering and processing plants for processing or pay for any deficiencies at a specified rate or margin. If we ceased operations in the areas subject to these agreements at December 31, 2022, the total deficiencies required to be paid by the Company under these agreements are reflected in the table presented above. Our consolidated statements of operations reflect our share of these processing costs. Firm sales agreement . As of December 31, 2022 we had a firm sales agreement with an integrated marketing company for our crude oil production in the Delaware Basin through 2023. This agreement is expected to provide price diversification through realization of export market pricing via a Corpus Christi terminal and exposure to Brent-weighted prices. This agreement does not require physical delivery of the minimum volumes of crude oil over the contractual term. However, if we do not sell and deliver at least the minimum contract volume pursuant to the agreement, we are required to pay transportation reservation charges related to the undelivered volume. For the years ended December 31, 2022 and 2021, we did not incur material transportation reservation charges under this agreement. Litigation and Legal Items. We are involved in various legal proceedings. We review the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in our best interests. We have provided the necessary estimated accruals in the accompanying consolidated balance sheets where deemed appropriate for litigation and legal related items that are ongoing and not yet concluded. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations or liquidity.

COMMON STOCK

COMMON STOCK	12 Months Ended
	Dec. 31, 2022
Equity [Abstract]
Common Stock	NOTE 13 - COMMON STOCK Stock-Based Compensation Plans 2018 Equity Incentive Plan . In 2020, our stockholders approved an amendment to increase the number of shares of our common stock reserved for issuance pursuant to our long-term equity compensation plan for employees and non-employee directors (the “2018 Plan”) to 7,050,000 shares. The 2018 Plan expires in March 2028. The capital stock available for issuance under the 2018 Plan consists of shares of the Company’s authorized but unissued common stock or previously issued common stock that has been reacquired by the Company. Additionally, to the extent that an award under the 2018 Plan, in whole or in part, is canceled, expired, forfeited, settled in cash or otherwise terminated without delivery of shares, such shares remain available for issuance. Any shares withheld for taxes cannot be recycled under this plan. Awards may be issued in the form of stock options, stock appreciation rights (“SARs”), restricted stock, restricted stock units (“RSUs”), performance stock units (“PSUs”) and other stock-based awards. Awards may vest over periods of continued service or upon the satisfaction of performance conditions set at the discretion of the Compensation Committee of our board of directors (the “Compensation Committee”), with a minimum one-year vesting period applicable to most awards. With regard to SARs and stock options, awards have a maximum exercisable period of ten years. As of December 31, 2022, there were 3,840,404 shares available for grant under the 2018 Plan. 2010 Long-Term Equity Compensation Plan . Our Amended and Restated 2010 Long-Term Equity Compensation Plan, approved in 2013 (the “2010 Plan”), remains outstanding and we may continue to use the 2010 Plan to grant awards. No awards may be granted under the 2010 Plan on or after June 5, 2023. As of December 31, 2022, there were 245,156 shares available for grant under the 2010 Plan. 2015 SRC Equity Incentive Plan . Pursuant to the closing of the SRC Acquisition, SRC granted PSUs to certain SRC executives (the “SRC PSUs”) under the 2015 SRC Equity Incentive Plan (the “2015 SRC Plan”). The SRC PSUs were converted into 155,928 PDC PSUs and remained subject to the same terms and conditions (including performance-vesting terms) that applied immediately prior to the closing of the SRC Acquisition. As of December 31, 2021, all converted SRC PSUs vested and in 2022, the 2015 SRC Plan was closed and retired. The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented: Year Ended December 31, 2022 2021 2020 (in thousands) General and administrative expense $ 25,257 $ 21,830 $ 21,182 Lease operating expense 1,589 1,193 1,018 Total stock-based compensation expense $ 26,846 $ 23,023 $ 22,200 Restricted Stock Units The Company grants to executive officers and employees time-based RSUs, which vest ratably over a three-year service period. The fair value of these time-based RSUs is based on the closing market price of our common stock on the grant date and is recognized ratably over the requisite service period. The time-based RSUs generally vest ratably on each anniversary following the grant date provided that a participant is continuously employed. The following table presents the changes in non-vested time-based RSUs to eligible employees, including executive officers, during the year ended December 31, 2022: Shares Weighted Average Grant-Date Fair Value per Share Non-vested at beginning of period 1,165,187 $ 25.33 Granted 363,395 70.01 Vested (581,343) 26.15 Forfeited (50,728) 40.58 Non-vested at end of period 896,511 42.05 The weighted average grant-date fair value of restricted stock units was $70.01, $33.64 and $11.98 for the years ended December 31, 2022, 2021 and 2020, respectively. The total grant-date fair value of restricted stock units that vested for the years ended December 31, 2022, 2021 and 2020 was $15.2 million, $13.6 million and $20.4 million, respectively. Total compensation cost related to non-vested time-based awards and not yet recognized on the consolidated statements of operations as of December 31, 2022 was $24.7 million. This cost is expected to be recognized over a weighted average period of 1.3 years. Performance Stock Units The Company grants to certain executive officers PSUs, which are subject to market-based vesting criteria as well as a three-year service period. The market-based shares vest if the participant is continuously employed throughout the performance period and the market-based performance measure is achieved. The fair value of the market-based PSUs is amortized ratably over the requisite service period. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. The Compensation Committee awarded a total of 102,098 market-based PSUs to our executive officers during 2022. In addition to continuous employment, the vesting of these PSUs is contingent on a combination of absolute stock performance and our total stockholder return (“TSR”), which is essentially our stock price change including any dividends over a three-year period ending on December 31, 2024, as compared to the TSR of a group of peer companies over the same period. The PSUs will result in a payout between zero and 250 percent of the target PSUs awarded. The grant-date fair value was estimated using a Monte Carlo valuation model. The Monte Carlo valuation model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. The expected term of the awards was based on the requisite service period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant and extrapolated to approximate the life of the award. The expected volatility was based on our common stock historical volatility, as well as that of our peer group. The following table summarizes the key assumptions and related information used to determine the grant-date fair value of performance stock units awarded during the periods presented: Year Ended December 31, 2022 2021 2020 Expected term of award (in years) 2.9 3.0 3.0 Risk-free interest rate 1.7% 0.2% 1.4% Expected volatility 86.3% 84.6% 46.6% Weighted average grant-date fair value per share $107.85 $54.01 $33.52 The expected term of the awards is based on the number of years from the grant date through the end of the performance period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant, extrapolated to approximate the life of the awards. The expected volatility was based on our common stock historical volatility, as well as that of our peer group. The following table presents the change in non-vested market-based awards during the year ended December 31, 2022: Shares Weighted Average Grant-Date Fair Value per Share Non-vested at December 31, 2021 439,229 $ 43.21 Granted 102,098 107.85 Granted for performance multiple (1) 347,363 33.52 Vested (578,937) 33.52 Non-vested at December 31, 2022 309,753 71.76 _______________ (1) Upon completion of the performance period for the PSUs granted in 2020, a performance multiple of 250% was applied to each of the grants resulting in additional grants of PSUs in December 2022. The total grant-date fair value of performance stock units that vested in the years ended December 31, 2022, 2021 and 2020 was $19.4 million, $11.6 million and $4.7 million, respectively. Total compensation cost related to non-vested market-based awards not yet recognized on the consolidated statements of operations as of December 31, 2022 was $11.6 million. This cost is expected to be recognized over a weighted average period of 1.3 years. Preferred Stock We are authorized to issue 50,000,000 shares of preferred stock, par value $0.01 per share, which may be issued in one or more series, with such rights, preferences, privileges and restrictions as shall be fixed by our board of directors from time to time. Through December 31, 2022, no shares of preferred stock have been issued. Stock Repurchase Program In 2019, our board of directors approved a program pursuant to which we may acquire shares of our common stock from time to time. At December 31, 2021, $187.3 million of the approved $525.0 million remained available for repurchase under the stock repurchase program. In February 2022, our board of directors approved a new stock repurchase program that reset the total repurchase value to $1.25 billion. The stock repurchase program does not require any specific number of shares to be acquired and can be modified or discontinued by our board of directors at any time. Repurchases under the program can be made in open markets at our discretion and in compliance with safe harbor provisions, or in privately negotiated transactions. Pursuant to the program, we repurchased 12.1 million and 3.8 million shares of outstanding common stock at a cost of $823.4 million and $159.5 million during the years ended December 31, 2022 and 2021, respectively. As of December 31, 2022, $454.7 million remained available under the program for repurchases of our outstanding common stock. In February 2023, our board of directors approved a $750 million increase in the size of our stock repurchase program. Dividends In the second quarter of 2021, our board of directors approved the declaration and payment of quarterly cash dividends of common stock. For the years ended December 31, 2022 and 2021, our dividends declared totaled $1.95 per share of outstanding common stock or $184.3 million and $0.86 per share of outstanding common stock or $83.6 million, respectively. All RSUs and PSUs receive a dividend equivalent per unit, recognized as a liability included in other liabilities on our consolidated balance sheets, until the recipients receive the equivalents upon vesting. Dividends declared were recorded as a reduction of retained earnings, however, if there were no retained earnings as of the date of declaration, dividends declared were recorded as a reduction of additional paid-in capital. Future dividend payments must be approved by our board of directors and will depend on our liquidity, financial requirements, and other factors considered relevant by our board. In February 2023, our board of directors approved an increase in the quarterly base dividend from $0.35 to $0.40 per share.

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Income Tax Disclosure [Text Block]	NOTE 14 - INCOME TAXES The table below presents the components of our provision for income tax (expense) benefit for the periods presented: Year Ended December 31, 2022 2021 2020 (in thousands) Current: Federal $ (400) $ — $ 1,592 State (900) (200) (220) Total current income tax benefit (1,300) (200) 1,372 Deferred: Federal (385,300) (23,790) 5,460 State (67,600) (2,593) 1,070 Total deferred income tax (expense) benefit (452,900) (26,383) 6,530 Income tax (expense) benefit $ (454,200) $ (26,583) $ 7,902 The following table presents a reconciliation of the federal statutory rate to the effective tax rate related to our (expense) benefit for income taxes for the periods presented: Year Ended December 31, 2022 2021 2020 Federal statutory tax rate 21.0 % 21.0 % 21.0 % State income tax, net 2.4 3.2 3.0 Change in valuation allowance (2.0) (19.8) (22.1) Other (1.1) 0.4 (0.8) Effective tax rate 20.3 % 4.8 % 1.1 % The effective income tax rates for 2022, 2021 and 2020 were 20.3 percent, 4.8 percent and 1.1 percent on the respective pre-tax income or loss. The effective tax rates differ from the amount that would be provided by applying the statutory U.S. federal income tax rate of 21 percent to the pre-tax income or loss due to state income taxes and changes in the valuation allowance against our deferred income tax asset. Tax effects of temporary differences that give rise to significant portions of deferred tax assets and deferred tax liabilities as of the dates indicated: December 31, 2022 2021 (in thousands) Deferred tax assets: Fair value of unsettled commodity derivatives $ 64,622 $ 88,053 Asset retirement obligations 47,919 38,274 Federal NOL carryforward 84,323 97,555 State NOL and tax credit carryforwards, net 16,190 20,266 Federal tax - credit carryforwards 3,555 3,059 Deferred compensation 7,985 9,949 Other 8,407 8,308 Valuation allowance — (56,634) Total gross deferred tax assets 233,001 208,830 Deferred tax liabilities: Properties and equipment 740,684 235,213 Net deferred tax liability $ 507,683 $ 26,383 We consider whether a portion, or all, of our deferred tax assets (“DTAs”) will be realized based on a more likely than not standard of judgment. The ultimate realization of DTAs is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. At each reporting period, management considers the available taxes in carryback periods, the future reversals of existing taxable temporary differences, tax planning strategies and projected future taxable income in making this assessment. The oil and gas property impairments and cumulative pre-tax losses were key considerations that led us to provide a valuation allowance against our DTAs beginning January 1, 2020 since we previously could not conclude that it is more likely than not that our DTAs will be fully realized in future periods. As we previously disclosed, we maintained a valuation allowance on our federal deferred tax assets and continued to do so until sufficient positive evidence existed to support a reversal of the allowance. In 2022, continued higher commodity prices increased our income, resulting in the reversal of objective negative evidence of cumulative loss in recent years, and we determined that we had sufficient positive evidence to release the valuation allowance. As a result, we released in full the valuation allowance against our deferred income tax assets of $56.6 million and recognized a corresponding decrease to income tax expense. As of December 31, 2022, we have estimated net operating loss carryforwards (“NOLs”) for federal income tax purposes of $401.5 million, of which $201.3 million was generated before January 1, 2018 and will begin to expire in 2037. In 2020, we acquired a federal NOL of $232.5 million as a component of the SRC Acquisition. This NOL is subject to an annual limitation of $16.1 million, as the acquisition constituted a change of ownership for SRC as defined under Internal Revenue Service (“IRS”) Code Section 382. As of December 31, 2022, we have state NOL carryforwards of $331.2 million that begin to expire in 2029 and state credit carryforwards of $4.5 million that begin to expire in 2023. Unrecognized tax benefits and related accrued interest and penalties were immaterial for the three-year period ended December 31, 2022. As of December 31, 2022, there is no liability for unrecognized income tax benefits. We are subject to the following material taxing jurisdictions: U.S., Colorado and Texas. As of December 31, 2022, we are current with our income tax filings in all applicable state jurisdictions and are not currently under any state income tax examinations. We are open to federal and state tax audits until the applicable statutes of limitations expire, however, the ability for the tax authority to adjust the NOL will continue until three years after the NOL is utilized. The statute of limitations has expired for all federal and state returns filed for periods ending before 2017. The IRS has accepted our 2020 and 2021 federal income tax returns with no tax adjustments. We continue to voluntarily participate in the IRS CAP Program. For 2022, we are in the Bridge Phase of the CAP, which means that the IRS will not be examining the 2022 tax year. Participation in the IRS CAP Program has enabled us to have minimal uncertain tax benefits associated with our federal tax return filings. The statutes of limitations for most of our state tax jurisdictions are open for tax years after 2017. In August 2022, the Inflation Reduction Act (“IRA”) was signed into law. The IRA includes implementation of a new alternative minimum tax, an excise tax on stock buybacks, and significant tax incentives for energy and climate initiatives, among other provisions. The alternative minimum tax and excise tax on stock buyback provisions are effective for tax years beginning after December 31, 2022. We continue to monitor updates to the IRA and the impact to our financial position, results of operations and liquidity. We do not believe it will have a material impact on our stock buyback program or our financial position in 2023, however, we are still assessing the impact for subsequent years.

Earnings per share

Earnings per share	12 Months Ended
	Dec. 31, 2022
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Earnings Per Share [Text Block]	NOTE 15 - EARNINGS PER SHARE Basic earnings per share is computed by dividing net earnings by the weighted average number of common shares outstanding for the period. Diluted earnings per share is similarly computed except that the denominator includes the effect, using the treasury stock method, of unvested stock-based employee awards, convertible notes (if applicable) and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive. The following table presents our weighted average basic and diluted shares outstanding for the periods presented: Year Ended December 31, 2022 2021 2020 (in thousands) Weighted average common shares outstanding - basic 94,796 98,546 98,251 Dilutive effect of: RSUs and PSUs 1,352 1,596 — Other equity-based awards 26 12 — Weighted average common shares and equivalents outstanding - diluted 96,174 100,154 98,251 We reported a net loss for the year ended December 31, 2020, and as a result, our basic and diluted weighted average common shares outstanding were the same for the period because the effect of the common share equivalents were anti-dilutive. The following table presents the weighted average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect for the periods presented: Year Ended December 31, 2022 2021 2020 (in thousands) Weighted average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect: RSUs and PSUs 144 28 1,707 Other equity-based awards 32 116 229 Total anti-dilutive common share equivalents 176 144 1,936

Supplemental Cash Flow Suppleme

Supplemental Cash Flow Supplemental Cash Flow (Notes)	12 Months Ended
	Dec. 31, 2022
Supplemental Cash Flow Elements [Abstract]
Cash Flow, Supplemental Disclosures [Text Block]	NOTE 16 - SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION Year Ended December 31, 2022 2021 2020 (in thousands) Supplemental cash flow information Cash payments (receipts) for Interest, net of capitalized interest $ 58,143 $ 66,647 $ 75,506 Income taxes 58 (1,057) 9 Non-cash investing and financing activities Change in accounts payable related to capital expenditures 38,384 519 (28,676) Change in asset retirement obligations, with a corresponding change to crude oil and natural gas properties, net of disposals 21,778 11,673 54,984 Issuance of common stock for acquisition of an exploration and production business 293,314 — 1,009,015 Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from operating leases $ 7,230 $ 7,603 $ 9,246 Operating cash flows from finance leases 254 117 156 Right-of-use assets recognized (derecognized) with offsetting lease liabilities Operating leases (1) $ 17,247 $ 1,457 $ 4,305 Finance leases 4,919 2,109 703

Organization, Consolidation and

Organization, Consolidation and Presentation of Financial Statements (Policies)	12 Months Ended
	Dec. 31, 2022
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Consolidation, Policy [Policy Text Block]	The accompanying audited consolidated financial statements include the accounts of PDC and our wholly-owned subsidiaries. Pursuant to the proportionate consolidation method, our accompanying consolidated financial statements include our pro rata share of assets, liabilities, revenues and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated in consolidation.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2022
Accounting Policies [Abstract]
Use of Estimates, Policy [Policy Text Block]	Use of Estimates in the Preparation of Financial Statements. The preparation of our consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) requires us to make estimates and assumptions that affect the amounts reported on our consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to our consolidated financial statements include estimates of proved oil and natural gas reserves used in calculating depletion; estimates of unpaid revenues and unbilled costs; future cash flows from proved oil and natural gas reserves on proved oil and natural gas properties used in impairment assessment; valuation of commodity derivative instruments; the estimation of future abandonment obligations used in asset retirement obligations; valuation of proved and unproved crude oil and natural gas properties from purchased and exchanged businesses and assets; and valuation of deferred income tax assets.
Cash and Cash Equivalents, Policy [Policy Text Block]	Cash and Cash Equivalents. The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. Cash and cash equivalents potentially subject us to a concentration of credit risk as substantially all of our deposits held in financial institutions were in excess of federal deposit insurance limits as of December 31, 2022 and 2021. We maintain our cash and cash equivalents in the form of money market and checking accounts with financial institutions that we believe are creditworthy and are also lenders under our revolving credit facility.
Derivative Financial Instruments, Policy [Policy Text Block]	Commodity Derivative Financial Instruments. Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas and NGLs. To manage a portion of our exposure to price volatility from producing crude oil and natural gas we enter into commodity derivative contracts to protect against price declines in future periods. We have elected not to designate any of our commodity derivative instruments as cash flow hedges; therefore, these instruments do not qualify for hedge accounting. Accordingly, realized gains and losses from the settlement of commodity derivatives and unrealized gains and losses from changes in the fair value of remaining unsettled commodity derivatives are presented as a component of revenues in the consolidated statements of operations. Under applicable accounting standards, the fair value of each derivative instrument is recorded as either an asset or liability on the consolidated balance sheet. We measure the fair value of our commodity 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.
Natugal Gas and Crude Oil Properties, Policy [Policy Text Block]	Properties and Equipment. Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. Under this method, costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depleted by the unit-of-production method based on estimated proved developed producing reserves. We have determined that we have two unit-of-production fields: the Wattenberg Field and the Delaware Basin. In making these conclusions we consider the geographic concentration, operating similarities within the areas, geologic considerations and common cost environments in these areas. We calculate quarterly depletion expense by using our estimated prior period-end reserves as the denominator, adjusted as necessary, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted for fourth quarter production. The process of estimating and evaluating crude oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. 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. Capitalized development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized as a gain or loss on the consolidated statements of operations. Exploration costs, including geological and geophysical expenses, seismic costs on unproved leaseholds and delay rentals are expensed as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but charged to expense if the well is determined to be economically nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as we have identified a sufficient quantity of reserves to justify completion as a producing well, we are making sufficient progress assessing our reserves and economic and operating viability or we have not made sufficient progress to allow for final determination of productivity. If an in-progress exploratory well is found to be economically unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expen se. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as suspended well costs until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the resulting accounting treatment is recorded. Unproved property costs not subject to depletion primarily include leasehold costs, broker and legal expenses and capitalized internal costs associated with developing oil and natural gas prospects on these properties. Leasehold costs are transferred into costs subject to depletion on an ongoing basis as these properties are evaluated and proved reserves are 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.
Proved and Unproved Property, Impairment [Policy Text Block]	Proved Property Impairment. Upon a triggering event, we assess the valuation of our proved crude oil and natural gas properties for possible impairment by comparing the carrying value to estimated undiscounted future net cash flows on a field-by-field basis using estimated production and prices at which we estimate the commodity will be sold. If carrying values exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a discounted future cash flows analysis. The impairment recorded is the amount by which the carrying values exceed the fair value. In the impairment assessment we estimate the fair value of proved crude oil and natural gas properties using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserves volumes, future operating and development costs, future commodity prices, and a market based weighted average cost of capital rate. Certain events, including but not limited to downward revisions in estimates of our reserve quantities, expectations of falling commodity prices or rising capital and operating costs, could result in a triggering event, and may result to a possible impairment of our proved crude oil and natural gas properties.
Property, Plant and Equipment, Policy [Policy Text Block]	Other Property and Equipment. Other property and equipment such as vehicles, facilities, midstream pipeline, office furniture and equipment, buildings, computer hardware and software and leasehold improvements is carried at cost. Depreciation is provided principally on the straight-line method over the assets’ estimated useful lives, which range from two to 35 years. Leasehold improvements are depreciated over the lesser of their useful lives or the term of the lease . Total depreciation expense related to other property and equipment was $7.8 million, $7.7 million and $8.7 million for the years ended December 31, 2022, 2021 and 2020, respectively. We review other property and equipment for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying value of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying value of the asset exceeds the estimated future cash flows, an impairment charge is recognized for the amount by which the carrying value of the asset exceeds its fair value.
Internal Use Software, Policy [Policy Text Block]	Internal-Use Software. Internal-use software costs incurred during the development stage of our enterprise resource planning software are capitalized. The development stage generally includes software design, configuration, testing and installation activities. Training and maintenance costs are expensed as incurred, while upgrades and enhancements are capitalized if it is probable that such expenditures will result in additional functionality. Capitalized internal-use software costs are depreciated over the estimated useful life of the underlying project on a straight-line basis upon completion of the project.
Interest Capitalization, Policy [Policy Text Block]	Capitalized Interest. We capitalize interest on expenditures made in connection with exploration and development projects that are not subject to current depletion. Interest is capitalized only for the period that activities are in progress to bring unevaluated properties to its intended use. Interest capitalized may not exceed gross interest expense for the period. Capitalized interest totaled $21.5 million, $17.8 million and $19.7 million during the year ended December 31, 2022, 2021 and 2020, respectively.
Assets Held For Sale, Policy [Policy Text Block]
Income Tax, Policy [Policy Text Block]	Income Taxes. We account for income taxes under the asset and liability method. We recognize deferred income tax assets and liabilities for the future tax consequences attributable to operating loss and credit carryforwards and differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. 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. The effect on deferred income tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. 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, we record a valuation allowance, thereby reducing the deferred income tax assets to what we consider realizable. We recognize 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 tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. Our policy is to recognize interest and penalties related to uncertain tax positions in interest expense.
Debt Issuance Costs, Policy [Policy Text Block]	Debt Issuance Costs and Discounts. Debt issuance costs and discounts are capitalized and amortized over the life of the respective borrowings using the effective interest method. Debt issuance costs for the Senior Notes are included in long-term debt and the debt issuance costs for the revolving credit facility are included in other assets.
Asset Retirement Obligation [Policy Text Block]	Asset Retirement Obligations. We recognize the estimated liability for future costs associated with the plugging and abandonment of our oil and gas properties resulting from acquisition, construction or normal operation. We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the related well is completed. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the associated long-lived asset by the same amount as the liability. Over time, the liability is accreted for the change in the present value and recognized as accretion expense. The initial capitalized cost, net of salvage value, is depleted over the useful life of the related asset through a charge to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost (presented as part of properties and equipment). Revisions in estimated liabilities can result from, among other things, changes in retirement costs or the estimated timing of settling asset retirement obligations.
Treasury Shares, Policy [Policy Text Block]	Treasury Shares. We record treasury share purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as a reduction in shareholders’ equity. When we retire treasury shares, we charge any excess of cost over the par value to additional paid-in-capital (“APIC”), to the extent we have amounts in APIC, with any remaining excess cost being charged to retained earnings.
Revenue [Policy Text Block]	Revenue Recognition. Crude oil, natural gas and NGLs revenues are recognized when we have transferred control of our production to the purchaser. We consider 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 crude oil, natural gas or NGLs production. We record revenues based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes delivered and prices received. We receive payment for sales one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded one to two months later. Historically, these differences have not been material. We account for natural gas imbalances using the sales method. For the years ending December 31, 2022, 2021 and 2020, the impact of any natural gas imbalances was not significant. Our crude oil, natural gas and NGLs sales are recorded using either the “net-back” or “gross” method of accounting, depending upon the related agreement. We use the net-back method when control of our commodity product has been transferred to the purchasers that are providing transportation, gathering or processing services. In these situations, the purchaser pays us proceeds based on a percent of the proceeds or have fixed our sales price at index less specified deductions. The net-back method results in the recognition of a net sales price that is lower than the index for which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid. We use the gross method of accounting when control of the crude oil, natural gas or NGLs is not transferred to the purchaser and the purchaser does not provide transportation, gathering or processing services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable transport and processing on a per unit basis. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering and processing expenses. For our product sales that have a contract term greater than one year, we utilized the practical expedient in ASC Topic 606 which states that we are not required to disclose the transaction price allocated to the remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, monthly sales of a product generally represent a separate performance obligation; therefore, future commodity volumes to be delivered and sold are wholly unsatisfied and disclosure of the transaction price allocated to such unsatisfied performance obligations is not required.
Accounting for Acquisitions using Purchase Accounting [Policy Text Block]	Business Combinations. We utilize the acquisition method to account for acquisitions of businesses. Pursuant to the acquisition method, we allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. The purchase price allocations are based upon appraisals, discounted cash flows and estimates by management, which are Level 3 inputs. When appropriate, we review recent comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties. In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped and unproved crude oil and natural gas properties. To estimate the fair value of these properties as part of acquisition accounting, we estimate the fair value of proved crude oil and natural gas properties using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserves volumes, future operating and development costs, future commodity prices, and a market based weighted average cost of capital rate. The market based weighted average cost of capital rate is subject to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. Additionally, for acquisitions with significant unproved properties, we complete an analysis of recent comparable purchased properties to determine an estimation of fair value. If applicable, we record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.
Asset Exchange [Policy Text Block]	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 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 in earnings, in accordance with Accounting Standards Codification 820, Fair Value Measurement
Stock-Based Compensation, Policy [Policy Text Block]	Stock-Based Compensation. Stock-based compensation is recognized within our financial statements based on the grant-date fair value of the equity instrument 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 and we account for forfeitures of stock-based compensation awards as they occur.
Fair Value Measurement, Policy	Fair Value of Assets and Liabilities. The Company follows the authoritative accounting guidance for measuring fair value of assets and liabilities in its financial statements. Fair value is defined 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. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as: Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets. Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means.
Lessee, Leases	Leases. We determine if an arrangement is representative of a lease at contract inception. Right-of-use (“ROU”) 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. Operating and finance lease ROU assets and liabilities are recognized at the commencement date based on the present value of the expected lease payments over the lease term. As most of our leases do not provide an implicit interest rate, we utilize our incremental borrowing rate based on information available at the commencement date in determining the present value of lease payments. Subsequent measurement, as well as presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. Terms 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. Leases with an initial term of one year or less are not recorded on the consolidated balance sheets. We apply the practical expedient that permits combining lease and non-lease components in a contract and accounting for the combination as a single lease component (applied by asset class).
Earnings Per Share, Policy [Policy Text Block]	Basic earnings per share is computed by dividing net earnings by the weighted average number of common shares outstanding for the period. Diluted earnings per share is similarly computed except that the denominator includes the effect, using the treasury stock method, of unvested stock-based employee awards, convertible notes (if applicable) and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive.

Business Combination Purchase P

Business Combination Purchase Price Transaction Details (Tables)	12 Months Ended
	Dec. 31, 2022
Business Combination, Separately Recognized Transactions [Line Items]
Business Acquisition, Pro Forma Information	Year Ended December 31, 2022 2021 (in thousands, except per share data) Total revenue $ 3,897,361 $ 2,277,463 Net income (loss) 1,651,029 563,855 Earnings (loss) per share: Basic $ 17.42 $ 5.50 Diluted 17.17 5.41

Revenue Recognition Revenue R_2

Revenue Recognition Revenue Recognition (Tables)	12 Months Ended
	Dec. 31, 2022
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue [Table Text Block]	Disaggregated Revenue. The following table presents crude oil, natural gas and NGLs sales disaggregated by commodity and operating region for the periods presented: Year Ended December 31, Revenue by Commodity and Operating Region 2022 2021 2020 (in thousands) Crude oil Wattenberg Field $ 2,154,435 $ 1,275,666 $ 668,948 Delaware Basin 423,784 255,135 147,902 Total 2,578,219 1,530,801 816,850 Natural gas Wattenberg Field 870,560 458,870 171,755 Delaware Basin 113,909 60,733 6,997 Total 984,469 519,603 178,752 NGLs Wattenberg Field 614,260 428,570 128,126 Delaware Basin 119,733 73,584 28,827 Total 733,993 502,154 156,953 Crude oil, natural gas and NGLs Wattenberg Field 3,639,255 2,163,106 968,829 Delaware Basin 657,426 389,452 183,726 Total $ 4,296,681 $ 2,552,558 $ 1,152,555
Contract with Customer, Asset and Liability

Fair Value of Financial Instrum

Fair Value of Financial Instruments Fair Value Measurements and Disclosures (Tables)	12 Months Ended
	Dec. 31, 2022
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	The following table presents, for each applicable level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis as of the dates indicated: December 31, 2022 December 31, 2021 Consolidated Balance Sheet Line Item Significant Other Significant Total Significant Other Significant Total (in thousands) Derivative assets Current Fair value of derivatives $ 9,178 $ 22,785 $ 31,963 $ — $ 17,909 $ 17,909 Non-current Fair value of derivatives 20,439 5,123 25,562 605 14,572 15,177 Total $ 29,617 $ 27,908 $ 57,525 $ 605 $ 32,481 $ 33,086 Derivative liabilities Current Fair value of derivatives $ (214,171) $ (60,047) $ (274,218) $ (230,695) $ (74,175) $ (304,870) Non-current Fair value of derivatives (49,749) (3,851) (53,600) (74,715) (20,846) (95,561) Total $ (263,920) $ (63,898) $ (327,818) $ (305,410) $ (95,021) $ (400,431)
Fair Value Assets and Liabilities Unobservable Input Reconciliation [Table Text Block]	The following table presents a reconciliation of our Level 3 commodity derivative assets and liabilities measured at fair value for the periods presented: Year Ended December 31, 2022 2021 2020 (in thousands) Fair value of Level 3 instruments, net asset (liability) beginning of period $ (62,540) $ (8,427) $ 8,414 Commodity derivatives acquired from acquisition of business (22,716) — — Changes in fair value included in consolidated statements of operations line item: Commodity price risk management gain (loss), net (192,694) (206,109) 37,821 Settlements included in consolidated statements of operations line items: Commodity price risk management gain (loss), net 241,960 151,996 (54,662) Fair value of Level 3 instruments, net asset (liability) end of period $ (35,990) $ (62,540) $ (8,427) Net change in fair value of Level 3 unsettled derivatives included in consolidated statements of operations line item: Commodity price risk management gain (loss), net $ (31,367) $ (35,108) $ — Total $ (31,367) $ (35,108) $ —
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments [Table Text Block]	The portion of our long-term debt related to our revolving credit facility approximates fair value, as the applicable interest rates are variable and reflective of market rates. We have elected not to account for the portion of our debt related to our senior notes under the fair value option; however, we have determined an estimate of the fair values based on measurements of trading activity and broker or dealer quotes, which are published market prices, and therefore are Level 2 inputs. The table below presents these estimates of the fair value of the portion of our long-term debt related to our senior notes as of the dates indicated: December 31, 2022 2021 Nominal Interest Estimated Fair Value Percent of Par Estimated Fair Value Percent of Par (in millions) (in millions) 2024 Senior Notes 6.125 % 198.4 99.2 % 202.8 101.4 % 2026 Senior Notes 5.75 % 716.0 95.5 % 775.5 103.4 %

Derivative Financial Instrume_2

Derivative Financial Instruments Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2022
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Schedule of Derivative Instruments, Effect on Other Comprehensive Income (Loss) [Table Text Block]	The following table presents the impact of our derivative instruments on our consolidated statements of operations for the periods presented: Year Ended December 31, Consolidated Statements of Operations Line Item 2022 2021 2020 (in thousands) Commodity price risk management gain (loss), net Net settlements $ (879,889) $ (410,188) $ 279,271 Net change in fair value of unsettled derivatives 416,278 (291,268) (99,001) Total commodity price risk management gain (loss), net $ (463,611) $ (701,456) $ 180,270
Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block]	As of December 31, 2022, we had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is presented: Collars Fixed-Price Swaps Commodity/ Index/ Quantity (Crude oil - MBbls Natural Gas - BBtu) Weighted Average Contract Price Quantity (Crude Oil - MBbls Gas and Basis- BBtu) Weighted Average Contract Price Fair Value December 31, 2022 (in thousands) Floors Ceilings Crude Oil NYMEX 2023 5,937 $ 61.27 $ 83.11 9,804 $ 66.42 $ (156,820) 2024 825 65.91 89.58 6,126 70.59 (17,042) 2025 — — — 2,640 75.10 12,262 Total Crude Oil 6,762 18,570 (161,600) Natural Gas NYMEX 2023 26,864 3.48 6.03 41,825 3.05 (51,443) 2024 — — — 26,160 3.54 (17,511) 2025 — — — 6,225 4.87 2,640 26,864 74,210 (66,314) CIG 2023 — — — 8,760 3.39 (7,657) 2025 — — — 4,800 3.10 (4,370) — 13,560 (12,027) Total Natural Gas 26,864 87,770 (78,341) Basis Protection - Natural Gas CIG 2023 — — — 67,742 (0.26) (26,335) 2024 — — — 26,160 (0.39) (3,329) 2025 — — — 6,225 (0.37) (688) Total Basis Protection - Natural Gas — 100,127 (30,352) Commodity Derivatives Fair Value $ (270,293)

Properties and Equipment (Table

Properties and Equipment (Tables)	12 Months Ended
	Dec. 31, 2022
Oil and Gas Property [Abstract]
Property, Plant and Equipment [Table Text Block]	The following table presents the components of properties and equipment, net of accumulated depreciation, depletion and amortization (“DD&A”), as of the dates indicated: December 31, 2022 2021 (in thousands) Properties and equipment, net: Crude oil and natural gas properties Proved $ 11,324,756 $ 8,310,018 Unproved 156,418 306,181 Total crude oil and natural gas properties 11,481,174 8,616,199 Equipment and other 72,151 63,099 Land and buildings 25,406 19,928 Construction in progress 716,302 371,968 Properties and equipment, at cost 12,295,033 9,071,194 Accumulated DD&A (5,001,678) (4,256,329) Properties and equipment, net $ 7,293,355 $ 4,814,865
Impairment of natural gas and crude oil properties [Table Text Block]	The following table presents impairment charges recorded for properties and equipment for the periods presented: Year Ended December 31, 2022 2021 2020 (in thousands) Impairment of proved and unproved properties $ 6,762 $ 402 $ 881,238 Impairment of infrastructure and other — — 1,155 Total impairment of properties and equipment $ 6,762 $ 402 $ 882,393

Accounts Receivable, Other Ac_2

Accounts Receivable, Other Accrued Expenses and Other Liabilities (Tables)	12 Months Ended
	Dec. 31, 2022
Concentration Risks, Types, No Concentration Percentage [Abstract]
Accounts Receivable [Table Text Block]	Accounts Receivable. The following table presents the components of accounts receivable, net of allowance for doubtful accounts as of the dates indicated: December 31, 2022 2021 (in thousands) Crude oil, natural gas and NGLs sales $ 491,327 $ 368,991 Joint interest billings 46,633 24,860 Other 13,796 10,809 Allowance for doubtful accounts (5,445) (6,055) Accounts receivable, net $ 546,311 $ 398,605
Accounts Payable, Accrued Liabilities, and Other Liabilities Disclosure, Current [Text Block]	Other Accrued Expenses. The following table presents the components of other accrued expenses as of the dates indicated: December 31, 2022 2021 (in thousands) Employee benefits $ 29,288 $ 29,319 Asset retirement obligations 25,986 32,146 Environmental expenses 25,666 11,942 Operating and finance leases 5,987 7,197 Other 19,155 10,805 Other accrued expenses $ 106,082 $ 91,409 Other Liabilities. The following table presents the components of other liabilities as of the dates indicated: December 31, 2022 2021 (in thousands) Deferred midstream gathering credits $ 145,937 $ 159,788 Production taxes 315,758 131,865 Operating and finance leases 41,815 6,274 Other 29,360 16,842 Other liabilities $ 532,870 $ 314,769 Deferred Midstream Gathering Credits. In 2019, we entered into agreements pursuant to which we dedicated the gathering of some of our production and all water gathering and disposal volumes in the Delaware Basin. The terms of these agreements range from 15 to 22 years. The acreage dedication agreements resulted in initial cash receipts and are being amortized on a units-of-production basis. The amortization rates are assessed on an annual basis for changes in estimated future production. The following table presents the amortization charges related to our deferred credits recognized on the consolidated statements of operations for the periods indicated: Year Ended December 31, 2022 2021 (in thousands) Transportation, gathering and processing expense $ 11,037 $ 7,317 Lease operating expense 3,753 2,422
Deferred Midstream Gathering Credits	following table presents the amortization charges related to our deferred credits recognized on the consolidated statements of operations for the periods indicated: Year Ended December 31, 2022 2021 (in thousands) Transportation, gathering and processing expense $ 11,037 $ 7,317 Lease operating expense 3,753 2,422

Long-Term Debt LONG-TERM DEBT (

Long-Term Debt LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2022
Debt Disclosure [Abstract]
Schedule of Long-term Debt Instruments [Table Text Block]	Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $6.0 million and $7.9 million as of December 31, 2022 and December 31, 2021, respectively, consists of the following: December 31, 2022 2021 (in thousands) Revolving credit facility due November 2026 $ 370,000 $ — 6.125% Senior Notes due September 2024 199,163 198,674 5.75% Senior Notes due May 2026 744,847 743,410 Total debt, net of unamortized discount, premium and debt issuance costs $ 1,314,010 $ 942,084

Leases Operating and Financin_2

Leases Operating and Financing Leases (Tables)	12 Months Ended
	Dec. 31, 2022
Leases [Abstract]
Lease, Cost [Table Text Block]	The following table presents the components of lease costs for the periods presented: Year Ended December 31, 2022 2021 (in thousands) Operating lease costs (1) $ 6,743 $ 6,125 Finance lease costs: Amortization of ROU assets 2,100 1,752 Interest on lease liabilities 270 164 Total finance lease costs 2,370 1,916 Short-term lease costs (1) 338,404 203,361 Total lease costs $ 347,517 $ 211,402
Operating and Financing Leases Financial Statement Location [Table Text Block]	The following table presents the balance sheet classification and other information regarding our leases as of the dates indicated: December 31, Leases Consolidated Balance Sheet Line Item 2022 2021 (in thousands) Operating lease ROU assets Other assets $ 19,577 $ 7,630 Finance lease ROU assets Properties and equipment, net 6,184 3,483 Total ROU assets $ 25,761 $ 11,113 Operating lease obligation - short-term Other accrued expenses $ 3,825 $ 5,937 Operating lease obligation - long-term Other liabilities 37,720 4,044 Finance lease obligation - short-term Other accrued expenses 2,162 1,260 Finance lease obligation - long-term Other liabilities 4,095 2,230 Total lease liabilities $ 47,802 $ 13,471 December 31, Leases Consolidated Balance Sheet Line Item 2022 2021 (in thousands) Weighted average remaining lease term (years) 7.9 2.8 Weighted average discount rate 5.1 % 4.8 %
Operating and Financing Lease, Liability, Maturity	Maturity of lease liabilities by year and in the aggregate, under operating and financing leases with terms of one year or more, as of December 31, 2022 consist of the following: Operating Leases Finance Leases Total (in thousands) 2023 $ 4,063 $ 2,404 $ 6,467 2024 3,101 1,891 4,992 2025 6,682 1,698 8,380 2026 6,754 649 7,403 2027 5,821 73 5,894 Thereafter 27,512 — 27,512 Total lease payments 53,933 6,715 60,648 Less: Interest and discount (12,388) (458) (12,846) Present value of lease liabilities $ 41,545 $ 6,257 $ 47,802

Asset Retirement Obligations As

Asset Retirement Obligations Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2022
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Change in Asset Retirement Obligation [Table Text Block]	The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interests in crude oil and natural gas properties for the periods presented: Year Ended December 31, 2022 2021 (in thousands) Beginning balance $ 159,672 $ 166,570 Obligations incurred with development activities and other 5,332 4,750 Obligations incurred with acquisition 25,300 — Accretion expense 13,408 12,086 Revisions in estimated cash flows 19,606 10,609 Obligations discharged with asset retirements and divestitures (25,667) (34,343) Asset retirement obligations at end of period 197,651 159,672 Current portion (1) (25,986) (32,146) Long-term portion $ 171,665 $ 127,526

Commitments and Contingencies C

Commitments and Contingencies Commitments and Contigencies (Tables)	12 Months Ended
	Dec. 31, 2022
Commitments and Contingencies Disclosure [Abstract]
Supply Commitment	The following table presents our firm transportation, sales and processing, water delivery and disposal and purchase commitments: Year Ending December 31, (in thousands) 2023 2024 2025 2026 2027 Thereafter Total Firm transportation $ 96,567 $ 64,403 $ 49,187 $ 36,692 $ 10,388 $ 28,364 $ 285,601 Gas gathering and processing agreements 117,828 117,509 101,553 61,633 35,608 43,801 477,932 $ 214,395 $ 181,912 $ 150,740 $ 98,325 $ 45,996 $ 72,165 $ 763,533

Common Stock Common Stock (Tabl

Common Stock Common Stock (Tables)	12 Months Ended
	Dec. 31, 2022
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Payment Arrangement, Cost by Plan [Table Text Block]	The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented: Year Ended December 31, 2022 2021 2020 (in thousands) General and administrative expense $ 25,257 $ 21,830 $ 21,182 Lease operating expense 1,589 1,193 1,018 Total stock-based compensation expense $ 26,846 $ 23,023 $ 22,200
Share-based Payment Arrangement, Restricted Stock and Restricted Stock Unit, Activity [Table Text Block]	The following table presents the changes in non-vested time-based RSUs to eligible employees, including executive officers, during the year ended December 31, 2022: Shares Weighted Average Grant-Date Fair Value per Share Non-vested at beginning of period 1,165,187 $ 25.33 Granted 363,395 70.01 Vested (581,343) 26.15 Forfeited (50,728) 40.58 Non-vested at end of period 896,511 42.05
Restricted Stock Awards, Market-Based, Valuation assumptions [Table Text Block]	Year Ended December 31, 2022 2021 2020 Expected term of award (in years) 2.9 3.0 3.0 Risk-free interest rate 1.7% 0.2% 1.4% Expected volatility 86.3% 84.6% 46.6% Weighted average grant-date fair value per share $107.85 $54.01 $33.52
Schedule of Nonvested Performance-based Units Activity [Table Text Block]	The following table presents the change in non-vested market-based awards during the year ended December 31, 2022: Shares Weighted Average Grant-Date Fair Value per Share Non-vested at December 31, 2021 439,229 $ 43.21 Granted 102,098 107.85 Granted for performance multiple (1) 347,363 33.52 Vested (578,937) 33.52 Non-vested at December 31, 2022 309,753 71.76 _______________

Income Taxes Income Taxes (Tabl

Income Taxes Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	The table below presents the components of our provision for income tax (expense) benefit for the periods presented: Year Ended December 31, 2022 2021 2020 (in thousands) Current: Federal $ (400) $ — $ 1,592 State (900) (200) (220) Total current income tax benefit (1,300) (200) 1,372 Deferred: Federal (385,300) (23,790) 5,460 State (67,600) (2,593) 1,070 Total deferred income tax (expense) benefit (452,900) (26,383) 6,530 Income tax (expense) benefit $ (454,200) $ (26,583) $ 7,902
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	The following table presents a reconciliation of the federal statutory rate to the effective tax rate related to our (expense) benefit for income taxes for the periods presented: Year Ended December 31, 2022 2021 2020 Federal statutory tax rate 21.0 % 21.0 % 21.0 % State income tax, net 2.4 3.2 3.0 Change in valuation allowance (2.0) (19.8) (22.1) Other (1.1) 0.4 (0.8) Effective tax rate 20.3 % 4.8 % 1.1 %
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	Tax effects of temporary differences that give rise to significant portions of deferred tax assets and deferred tax liabilities as of the dates indicated: December 31, 2022 2021 (in thousands) Deferred tax assets: Fair value of unsettled commodity derivatives $ 64,622 $ 88,053 Asset retirement obligations 47,919 38,274 Federal NOL carryforward 84,323 97,555 State NOL and tax credit carryforwards, net 16,190 20,266 Federal tax - credit carryforwards 3,555 3,059 Deferred compensation 7,985 9,949 Other 8,407 8,308 Valuation allowance — (56,634) Total gross deferred tax assets 233,001 208,830 Deferred tax liabilities: Properties and equipment 740,684 235,213 Net deferred tax liability $ 507,683 $ 26,383

Earnings per share (Tables)

Earnings per share (Tables)	12 Months Ended
	Dec. 31, 2022
Earnings Per Share [Abstract]
Schedule of Earnings Per Share Reconciliation [Table Text Block]	The following table presents our weighted average basic and diluted shares outstanding for the periods presented: Year Ended December 31, 2022 2021 2020 (in thousands) Weighted average common shares outstanding - basic 94,796 98,546 98,251 Dilutive effect of: RSUs and PSUs 1,352 1,596 — Other equity-based awards 26 12 — Weighted average common shares and equivalents outstanding - diluted 96,174 100,154 98,251
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share [Table Text Block]	The following table presents the weighted average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect for the periods presented: Year Ended December 31, 2022 2021 2020 (in thousands) Weighted average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect: RSUs and PSUs 144 28 1,707 Other equity-based awards 32 116 229 Total anti-dilutive common share equivalents 176 144 1,936

Supplemental Cash Flow Supple_2

Supplemental Cash Flow Supplemental Cash Flow (Tables)	12 Months Ended
	Dec. 31, 2022
Supplemental Cash Flow Elements [Abstract]
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]	Year Ended December 31, 2022 2021 2020 (in thousands) Supplemental cash flow information Cash payments (receipts) for Interest, net of capitalized interest $ 58,143 $ 66,647 $ 75,506 Income taxes 58 (1,057) 9 Non-cash investing and financing activities Change in accounts payable related to capital expenditures 38,384 519 (28,676) Change in asset retirement obligations, with a corresponding change to crude oil and natural gas properties, net of disposals 21,778 11,673 54,984 Issuance of common stock for acquisition of an exploration and production business 293,314 — 1,009,015 Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from operating leases $ 7,230 $ 7,603 $ 9,246 Operating cash flows from finance leases 254 117 156 Right-of-use assets recognized (derecognized) with offsetting lease liabilities Operating leases (1) $ 17,247 $ 1,457 $ 4,305 Finance leases 4,919 2,109 703

Nature of Operations and Basi_2

Nature of Operations and Basis of Presentation Additional Information (Details)	Dec. 31, 2022 Wells
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Oil and gas producing wells, gross	4,100

Summary of Significant Accoun_3

Summary of Significant Accounting Policies Detail (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Significant Accounting Policies [Line Items]
Property, Plant and Equipment, Useful Life	35 years
Non-Oil and gas Depreciation, Depletion and Amortization	$ 7.8	$ 7.7	$ 8.7
Capitalized Interest	$ 21.5	$ 17.8	$ 19.7

Business Combinations and Ass_2

Business Combinations and Asset Acquisitions (Details) - USD ($)		12 Months Ended
	May 06, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Business Acquisition [Line Items]
Payments to Acquire Businesses, Net of Cash Acquired		$ 1,068,241,000	$ 0	$ 139,812,000
Great Western Petroleum, LLC
Business Acquisition [Line Items]
Business Combination, Consideration Transferred	$ 1,432,867,000
Business Combination, Consideration Transferred, Equity Interest Issued, Shares	4,007,018
Payments to Acquire Businesses, Net of Cash Acquired	$ 542,500,000

BUSINESS COMBINATIONS (Details)

BUSINESS COMBINATIONS (Details) - USD ($)		12 Months Ended
	May 06, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Jan. 14, 2020
Business Acquisition [Line Items]
Stock Repurchase Program, Authorized Amount					$ 525,000,000
Business Acquisition, Pro Forma Revenue		$ 3,897,361,000	$ 2,277,463,000
Business Acquisition, Pro Forma Net Income (Loss)		$ 1,651,029,000	$ 563,855,000
Business Acquisition, Pro Forma Earnings Per Share, Basic		$ 17.42	$ 5.50
Business Acquisition, Pro Forma Earnings Per Share, Diluted		$ 17.17	$ 5.41
Purch Price Adj Disc Cash Flow	14.25%
Business Combination, Bargain Purchase, Gain Recognized, Amount		$ (90,057,000)	$ 0	$ 0
Net income (loss)		1,778,121,000	522,311,000	(724,320,000)
Revenues, Total		3,845,733,000	1,855,910,000	1,339,226,000
Payments to Acquire Businesses, Net of Cash Acquired		1,068,241,000	$ 0	$ 139,812,000
PDC and GW
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs		33,600,000
GW Acquisition
Business Acquisition [Line Items]
Net income (loss)		387,800,000
Revenues, Total		631,000,000
Great Western Petroleum, LLC
Business Acquisition [Line Items]
Business Combination, Consideration Transferred	$ 1,432,867,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment		7,035,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Assets		20,345,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets		2,349,019,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities		(110,940,000)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other		(25,300,000)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities		(32,802,000)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities		(826,095,000)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net		1,522,924,000
Business Acquisition, Share Price	$ 73.20
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents		63,183,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Receivables		164,026,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Other		3,129,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Accounts Payable		(119,142,000)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Other		(19,203,000)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities		(28,400,000)
Business Combination, Bargain Purchase, Gain Recognized, Amount		90,057,000
Equity Issued in Business Combination, Fair Value Disclosure	$ 293,314,000
Business Combination, Consideration Transferred, Liabilities Incurred	$ 235,822,000
Business Combination, Consideration Transferred, Equity Interest Issued, Shares	4,007,018
Payments to Acquire Businesses, Net of Cash Acquired	$ 542,500,000
Great Western Petroleum, LLC | Great Western Petroleum, LLC
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities		(170,708,000)
Great Western Petroleum, LLC | 12% GW Senior note
Business Acquisition [Line Items]
Business Combination, Consideration Transferred	361,231,000
Great Western Petroleum, LLC | Derivative Financial Instrument Net Assets [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities		(319,600,000)
GW Acquisition
Business Acquisition [Line Items]
Business Combination, Consideration Transferred	1,400,000,000
Business Combination, Acquisition Related Costs		11,700,000
Business Combination, Bargain Purchase, Gain Recognized, Amount		90,100,000
Equity Issued in Business Combination, Fair Value Disclosure	293,300,000
Business Combination, Consideration Transferred, Liabilities Incurred	$ 235,800,000
Business Combination, Consideration Transferred, Equity Interest Issued, Shares	4,000,000
GW Acquisition | 12% GW Senior note
Business Acquisition [Line Items]
Business Combination, Consideration Transferred	$ 361,200,000
Proved [Member] | Great Western Petroleum, LLC
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment		$ 2,091,301,000
Cash and Cash Equivalents | Great Western Petroleum, LLC
Business Acquisition [Line Items]
Business Combination, Consideration Transferred	$ 1,139,553,000

Revenue Recognition Revenue fro

Revenue Recognition Revenue from Contract with Customer (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Revenue from Contract with Customer [Abstract]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 4,296,681	$ 2,552,558	$ 1,152,555

Revenue Recognition Revenue by

Revenue Recognition Revenue by Commodity and Location (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Revenue from Contract with Customer, Excluding Assessed Tax	$ 4,296,681	$ 2,552,558	$ 1,152,555
Natural Gas Liquids
Revenue from Contract with Customer, Excluding Assessed Tax	733,993	502,154	156,953
Natural Gas [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	984,469	519,603	178,752
Crude Oil [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	2,578,219	1,530,801	816,850
Delaware Basin [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	657,426	389,452	183,726
Wattenberg Field
Revenue from Contract with Customer, Excluding Assessed Tax	3,639,255	2,163,106	968,829
Crude Oil [Member] | Wattenberg Field
Revenue from Contract with Customer, Excluding Assessed Tax	2,154,435	1,275,666	668,948
Crude Oil [Member] | Delaware Basin [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	423,784	255,135	147,902
Natural Gas [Member] | Wattenberg Field
Revenue from Contract with Customer, Excluding Assessed Tax	870,560	458,870	171,755
Natural Gas [Member] | Delaware Basin [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	113,909	60,733	6,997
Natural Gas Liquids | Wattenberg Field
Revenue from Contract with Customer, Excluding Assessed Tax	614,260	428,570	128,126
Natural Gas Liquids | Delaware Basin [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 119,733	$ 73,584	$ 28,827

Fair Value of Financial Instr_2

Fair Value of Financial Instruments Fair Value Measurements and Disclosures (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 57,525	$ 33,086
Derivative Liability, Fair Value, Gross Liability	327,818	400,431
Derivative, Fair Value, Net	(270,293)
Derivative Financial Instrument Net Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Changes in unrealized gains (losses) relating to assets (liabilities) still held as of period end, included in statement of operations line item;	(31,367)	(35,108)	$ 0
Fair Value, Measured With Unobservable Input Reconcilition, Recurring Basis, Net Asset Value	(35,990)	(62,540)	(8,427)
Derivative Financial Instruments, Assets
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured With Unobservable Input Reconcilition, Recurring Basis, Net Asset Value		(62,540)	(8,427)	$ 8,414
Commodity Price Risk Management, net | Derivative Financial Instrument Net Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Changes in unrealized gains (losses) relating to assets (liabilities) still held as of period end, included in statement of operations line item;	(31,367)	(35,108)	0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Assets, Gain (Loss) Included in Earnings	(192,694)	(206,109)	37,821
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Asset, Purchases, Sales, Issues, Settlements	241,960	151,996	$ (54,662)
Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	57,525	33,086
Derivative Liability, Fair Value, Gross Liability	(327,818)	(400,431)
Fair Value | Non Current Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Fair Value, Gross Liability	(53,600)	(95,561)
Fair Value | Non Current Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	25,562	15,177
Fair Value | Current Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	31,963	17,909
Fair Value | Current Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Fair Value, Gross Liability	(274,218)	(304,870)
Fair Value | Significant Other Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	29,617	605
Derivative Liability, Fair Value, Gross Liability	(263,920)	(305,410)
Fair Value | Significant Other Observable Inputs (Level 2) | Non Current Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Fair Value, Gross Liability	(49,749)	(74,715)
Fair Value | Significant Other Observable Inputs (Level 2) | Non Current Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	20,439	605
Fair Value | Significant Other Observable Inputs (Level 2) | Current Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	9,178	0
Fair Value | Significant Other Observable Inputs (Level 2) | Current Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Fair Value, Gross Liability	(214,171)	(230,695)
Fair Value | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	27,908	32,481
Derivative Liability, Fair Value, Gross Liability	(63,898)	(95,021)
Fair Value | Significant Unobservable Inputs (Level 3) | Non Current Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Fair Value, Gross Liability	(3,851)	(20,846)
Fair Value | Significant Unobservable Inputs (Level 3) | Non Current Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	5,123	14,572
Fair Value | Significant Unobservable Inputs (Level 3) | Current Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	22,785	17,909
Fair Value | Significant Unobservable Inputs (Level 3) | Current Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Fair Value, Gross Liability	(60,047)	(74,175)
6.125% Senior Notes due 2024 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Notes fair value	$ 198,400	$ 202,800
Senior Notes Percent of Par	99.20%	101.40%
5.75% Senior Notes due 2026 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Notes fair value	$ 716,000	$ 775,500
Senior Notes Percent of Par	95.50%	103.40%

Fair Value of Financial Instr_3

Fair Value of Financial Instruments Reconciliation of Level 3 Fair Value Measurements (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Derivative Financial Instrument Net Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured With Unobservable Input Reconcilition, Recurring Basis, Net Asset Value	$ (35,990)	$ (62,540)	$ (8,427)
Changes in unrealized gains (losses) relating to assets (liabilities) still held as of period end, included in statement of operations line item;	(31,367)	(35,108)	0
Derivative Financial Instrument Net Assets [Member] | Commodity Price Risk Management, net
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Assets, Gain (Loss) Included in Earnings	(192,694)	(206,109)	37,821
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Asset, Purchases, Sales, Issues, Settlements	241,960	151,996	(54,662)
Fair Value of Assets Acquired	(22,716)	0	0
Changes in unrealized gains (losses) relating to assets (liabilities) still held as of period end, included in statement of operations line item;	$ (31,367)	(35,108)	0
Derivative Financial Instruments, Assets
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measured With Unobservable Input Reconcilition, Recurring Basis, Net Asset Value		$ (62,540)	$ (8,427)	$ 8,414

Derivative Financial Instrume_3

Derivative Financial Instruments Outstanding Derivative Contracts (Details) MMBTU in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2022 USD ($) MMBTU $ / Unit MBbls
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ (270,293)
Natural Gas [Member] | Fixed Price Swaps [Member]
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ (78,341)
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	87,770
Natural Gas [Member] | Collars [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	26,864
Natural Gas [Member] | CME SWAPS MARKETS (NYMEX) [Member] | Fixed Price Swaps [Member]
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ (66,314)
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	74,210
Natural Gas [Member] | CME SWAPS MARKETS (NYMEX) [Member] | Collars [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	26,864
Natural Gas [Member] | Basis Protection Contracts Related to Natural Gas Marketing [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	100,127
Natural Gas [Member] | Basis Protection Contracts Related to Natural Gas Marketing [Member] | Fixed Price Swaps [Member]
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ (30,352)
Natural Gas [Member] | CIG [Member] | Fixed Price Swaps [Member]
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ (12,027)
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	13,560
Crude Oil [Member]
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ (161,600)
Crude Oil [Member] | Fixed Price Swaps [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MBbls	18,570,000
Crude Oil [Member] | Collars [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MBbls	6,762,000
2024 | Basis Protection - CIG [Member] | Natural Gas [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	(0.39)
2024 | Fixed Price Swaps [Member] | CME SWAPS MARKETS (NYMEX) [Member] | Crude Oil [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	(70.59)
2024 | Collars [Member] | CME SWAPS MARKETS (NYMEX) [Member] | Crude Oil [Member]
Derivative [Line Items]
Derivative, Floor Price	65.91
Derivative, Cap Price	89.58
2024 | CME SWAPS MARKETS (NYMEX) [Member] | Fixed Price Swaps [Member] | CME SWAPS MARKETS (NYMEX) [Member] | Natural Gas [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	(3.54)
2024 | CME SWAPS MARKETS (NYMEX) [Member] | Collars [Member] | CME SWAPS MARKETS (NYMEX) [Member] | Natural Gas [Member]
Derivative [Line Items]
Derivative, Floor Price	0
Derivative, Cap Price	0
2024 | Natural Gas [Member] | CME SWAPS MARKETS (NYMEX) [Member] | Fixed Price Swaps [Member]
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ (17,511)
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	26,160
2024 | Natural Gas [Member] | CME SWAPS MARKETS (NYMEX) [Member] | Collars [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	0
2024 | Natural Gas [Member] | Basis Protection - CIG [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	26,160
2024 | Natural Gas [Member] | Basis Protection - CIG [Member] | Fixed Price Swaps [Member]
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ (3,329)
2024 | Crude Oil [Member]
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ (17,042)
2024 | Crude Oil [Member] | Fixed Price Swaps [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MBbls	6,126,000
2024 | Crude Oil [Member] | Collars [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MBbls	825,000
2023 | Basis Protection - CIG [Member] | Natural Gas [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	(0.26)
2023 | Fixed Price Swaps [Member] | CME SWAPS MARKETS (NYMEX) [Member] | Crude Oil [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	(66.42)
2023 | Fixed Price Swaps [Member] | CIG [Member] | Natural Gas [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	(3.39)
2023 | Collars [Member] | CME SWAPS MARKETS (NYMEX) [Member] | Crude Oil [Member]
Derivative [Line Items]
Derivative, Floor Price	61.27
Derivative, Cap Price	83.11
2023 | CME SWAPS MARKETS (NYMEX) [Member] | Fixed Price Swaps [Member] | CME SWAPS MARKETS (NYMEX) [Member] | Natural Gas [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	(3.05)
2023 | CME SWAPS MARKETS (NYMEX) [Member] | Collars [Member] | CME SWAPS MARKETS (NYMEX) [Member] | Natural Gas [Member]
Derivative [Line Items]
Derivative, Floor Price	3.48
Derivative, Cap Price	6.03
2023 | Natural Gas [Member] | CME SWAPS MARKETS (NYMEX) [Member] | Fixed Price Swaps [Member]
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ (51,443)
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	41,825
2023 | Natural Gas [Member] | CME SWAPS MARKETS (NYMEX) [Member] | Collars [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	26,864
2023 | Natural Gas [Member] | Basis Protection - CIG [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	67,742
2023 | Natural Gas [Member] | Basis Protection - CIG [Member] | Fixed Price Swaps [Member]
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ (26,335)
2023 | Natural Gas [Member] | CIG [Member] | Fixed Price Swaps [Member]
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ (7,657)
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	8,760
2023 | Crude Oil [Member]
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ (156,820)
2023 | Crude Oil [Member] | Fixed Price Swaps [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MBbls	9,804,000
2023 | Crude Oil [Member] | Collars [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MBbls	5,937,000
2025 | Basis Protection - CIG [Member] | Natural Gas [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	(0.37)
2025 | Fixed Price Swaps [Member] | CME SWAPS MARKETS (NYMEX) [Member] | Crude Oil [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	(75.10)
2025 | Fixed Price Swaps [Member] | CIG [Member] | Natural Gas [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	(3.10)
2025 | Collars [Member] | CME SWAPS MARKETS (NYMEX) [Member] | Crude Oil [Member]
Derivative [Line Items]
Derivative, Floor Price	0
Derivative, Cap Price	0
2025 | CME SWAPS MARKETS (NYMEX) [Member] | Fixed Price Swaps [Member] | CME SWAPS MARKETS (NYMEX) [Member] | Natural Gas [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	(4.87)
2025 | CME SWAPS MARKETS (NYMEX) [Member] | Collars [Member] | CME SWAPS MARKETS (NYMEX) [Member] | Natural Gas [Member]
Derivative [Line Items]
Derivative, Floor Price	0
Derivative, Cap Price	0
2025 | Natural Gas [Member] | CME SWAPS MARKETS (NYMEX) [Member] | Fixed Price Swaps [Member]
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ 2,640
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	6,225
2025 | Natural Gas [Member] | CME SWAPS MARKETS (NYMEX) [Member] | Collars [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	0
2025 | Natural Gas [Member] | Basis Protection - CIG [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	6,225
2025 | Natural Gas [Member] | Basis Protection - CIG [Member] | Fixed Price Swaps [Member]
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ (688)
2025 | Natural Gas [Member] | CIG [Member] | Fixed Price Swaps [Member]
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ (4,370)
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	4,800
2025 | Crude Oil [Member]
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ 12,262
2025 | Crude Oil [Member] | Fixed Price Swaps [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MBbls	2,640,000
2025 | Crude Oil [Member] | Collars [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MBbls	0

Derivative Financial Instrume_4

Derivative Financial Instruments Impact of Netting Agreements (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	$ 57,525	$ 33,086
Effect of Master netting agreements	57,525	33,086
Derivative Asset, net	0	0
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	327,818	400,431
Effect of master netting agreements	57,525	33,086
Derivative Liability, net	$ 270,293	$ 367,345

Derivative Financial Instrume_5

Derivative Financial Instruments Impact of Derivative Instruments on Statement of Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Derivative [Line Items]
Net change in fair value of unsettled derivatives	$ 416,278	$ (291,268)	$ (99,001)
Commodity price risk management gain (loss), net	(463,611)	(701,456)	180,270
Gain (Loss) on Sale of Derivatives	(879,889)	(410,188)	279,271
Commodity Price Risk Management, net
Derivative [Line Items]
Commodity price risk management gain (loss), net	$ (463,611)	$ (701,456)	$ 180,270

Properties and Equipment (Detai

Properties and Equipment (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2022 USD ($) Wells	Dec. 31, 2021 USD ($) Wells	Dec. 31, 2020 USD ($) Wells	Dec. 31, 2019 USD ($)
Property, Plant and Equipment [Line Items]
Proved Natural Gas and Crude Oil Properties	$ 11,324,756	$ 8,310,018
Unproved Natural Gas and Crude Oil Properties	156,418	306,181
Total Natural Gas and Crude Oil Properties	11,481,174	8,616,199
Equipment and other	72,151	63,099
Land and Buildings	25,406	19,928
Construction in Progress	716,302	371,968
Property and Equipment, at cost	12,295,033	9,071,194
Accumulated DD&A	(5,001,678)	(4,256,329)
Property, Plant and Equipment, Net	7,293,355	4,814,865
Capitalized Exploratory Well Costs	0	0	$ 7,459	$ 16,078
Capitalized Exploratory Well Cost, Additions Pending Determination of Proved Reserves	0	5,902	11,770
Reclassification to Well, Facilities, and Equipment Based on Determination of Proved Reserves	$ 0	$ (13,361)	$ (20,389)
Wells to be completed | Wells	0	0	2
Results of Operations, Dry Hole Costs	$ 12,000

Impairment of Natural Gas and C

Impairment of Natural Gas and Crude Oil Properties (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2020	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Impairment of natural gas and crude oil properties [Line Items]
Delaware Basin Proved Property Impairment	$ 753,000
Delaware Basin Unproved Property Impairment	127,300
Impairment of Oil and Gas Properties		$ 6,762	$ 402	$ 881,238
Impairment of Long-Lived Assets to be Disposed of		0	0	1,155
Results of Operations, Impairment of Oil and Gas Properties	$ 881,100	$ 6,762	$ 402	$ 882,393
Impairment Measurement Input				17%

Properties and Equipment Explor

Properties and Equipment Exploration (Details) $ in Millions	Dec. 31, 2020 USD ($)
Property, Plant and Equipment [Line Items]
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year	$ 7.5

Accounts Receivables (Details)

Accounts Receivables (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Concentration Risk [Line Items]
Accounts Receivable, Allowance for Credit Loss, Current	$ (5,445)	$ (6,055)
Accounts receivable, net	$ 546,311	$ 398,605
Customer Concentration Risk | Customer | Customer No. 1
Concentration Risk [Line Items]
Percentage of Revenue	27%	32%	31%
Customer Concentration Risk | Customer | Customer No. 2
Concentration Risk [Line Items]
Percentage of Revenue	9%	9%	17%
Customer Concentration Risk | Customer | Customer No. 3
Concentration Risk [Line Items]
Percentage of Revenue	7%	11%	16%
Customer Concentration Risk | Customer | Customer No. 4
Concentration Risk [Line Items]
Percentage of Revenue	5%	10%	13%
Natural gas, NGLs and crude oil sales
Concentration Risk [Line Items]
Accounts Receivable, before Allowance for Credit Loss	$ 491,327	$ 368,991
Joint interest billing
Concentration Risk [Line Items]
Accounts Receivable, before Allowance for Credit Loss	46,633	24,860
Other Accounts Receivable
Concentration Risk [Line Items]
Accounts Receivable, before Allowance for Credit Loss	$ 13,796	$ 10,809

Other accrued expenses (Details

Other accrued expenses (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Schedule of Other Accrued Expense [Line Items]
Asset Retirement Obligation, Current	$ 25,986	$ 32,146
Other accrued liabilities	106,082	91,409
Current Liabilities [Member]
Schedule of Other Accrued Expense [Line Items]
Accrued Employee Benefits, Current	29,288	29,319
Asset Retirement Obligation, Current	25,986	32,146
Accrued Environmental Loss Contingencies, Current	25,666	11,942
Operating and Finance Lease Liability, Current	5,987	7,197
Other Accrued Liabilities	19,155	10,805
Other accrued liabilities	$ 106,082	$ 91,409

Other liabilities (Details)

Other liabilities (Details) - Non Current Liabilities [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Schedule of Other Liabilities [Line Items]
Deferred Midstream gathering credits	$ 145,937	$ 159,788
Production Tax Liability	315,758	131,865
Operating and Finance Lease Liability, Noncurrent	41,815	6,274
Other Accrued Liabilities	29,360	16,842
Other Accrued Liabilities, Noncurrent	$ 532,870	$ 314,769

Other Accrued Expenses Deferred

Other Accrued Expenses Deferred Midstream Gathering Credits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Midstream Water Gathering [Member]
Deferred Midstream and Oil Gathering Credits [Line Items]
Amortization of Other Deferred Charges	$ 3,753	$ 2,422
Midstream Gas and Oil Gathering Credits
Deferred Midstream and Oil Gathering Credits [Line Items]
Amortization of Other Deferred Charges	$ 11,037	$ 7,317

Long-Term Debt SCHEDULE OF LONG

Long-Term Debt SCHEDULE OF LONG-TERM DEBT (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
Unamortized Debt Issuance Expense	$ 6,000	$ 7,900
Debt. Long-term and Short-term, Combined Amount	1,314,010	942,084
Long-term debt	1,314,010	942,084
Letters of Credit Outstanding, Amount	20,400
6.125% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Principal amount	200,000
Senior Notes, Noncurrent	199,163	198,674
5.75% Senior Notes due 2026 [Member]
Debt Instrument [Line Items]
Principal amount	750,000
Senior Notes, Noncurrent	744,847	743,410
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Revolving credit facility	$ 370,000	$ 0

Long-Term Debt ADDITIONAL INFOR

Long-Term Debt ADDITIONAL INFORMATION (Details) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Oct. 31, 2022	Sep. 30, 2022	Nov. 02, 2021
Debt Instrument [Line Items]
Unamortized Debt Issuance Expense	$ (6,000,000)	$ (7,900,000)
Document Period End Date	Dec. 31, 2022
Line Of Credit Facility Initial Borrowing Capacity	$ 3,500,000,000				$ 3,000,000,000
Line of Credit Facility, Remaining Borrowing Capacity	1,100,000,000
Gain (Loss) on Extinguishment of Debt	0	(6,927,000)	$ 0
6.125% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Senior Notes ($)	200,000,000
5.75% Senior Notes due 2026 [Member]
Debt Instrument [Line Items]
Senior Notes ($)	750,000,000
Initial Borrowing Base [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line Of Credit Facility Initial Borrowing Capacity						$ 2,400,000,000
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Debt Issuance Costs, Line of Credit Arrangements, Net	13,500,000	16,900,000
Long-term Line of Credit	$ 370,000,000	$ 0
Maximum credit amount | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line Of Credit Facility Initial Borrowing Capacity						2,500,000,000
Alternate Base Rate Option [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate at Period End	0.75%
Unused Commitment Fee [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate at Period End	0.375%
Elected commitment
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity	$ 1,500,000,000			$ 1,500,000,000		$ 1,500,000,000
SOFR
Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate at Period End	1.75%

Senior Notes additional details

Senior Notes additional details (Details)	12 Months Ended
	Dec. 31, 2022 Rate
6.125% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.125%
Debt Instrument, Maturity Date	Sep. 15, 2024
Debt Instrument, Frequency of Periodic Payment	March 15, September 15
Debt Instrument, Redemption Period, End Date	Sep. 15, 2022
5.75% Senior Notes due 2026 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.75%
Debt Instrument, Maturity Date	May 15, 2026
Debt Instrument, Frequency of Periodic Payment	May 15, November 15
Debt Instrument, Redemption Period, End Date	May 15, 2024

Leases Lease Narrative (Details

Leases Lease Narrative (Details)	12 Months Ended
	Dec. 31, 2022 Rate	Dec. 31, 2021 Rate
Lessee, Lease, Description [Line Items]
Operating Lease, Weighted Average Discount Rate, Percent	5.10%	4.80%
Operating Lease, Weighted Average Remaining Lease Term	7 years 10 months 24 days	2 years 9 months 18 days

Leases Lease Cost (Details)

Leases Lease Cost (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Lease, Cost [Abstract]
Operating Lease, Cost	$ 6,743	$ 6,125
Finance Lease, Right-of-Use Asset, Amortization	2,100	1,752
Finance Lease, Interest Payment on Liability	270	164
Finance Lease, Cost	2,370	1,916
Short-term Lease, Cost	338,404	203,361
Lease, Cost	347,517	211,402
Lessee, Lease, Description [Line Items]
Lease, Cost	347,517	211,402
Finance Lease, Cost	2,370	$ 1,916
Total Operating Lease Payments	$ 34,000

Leases Leases - Lease Assets an

Leases Leases - Lease Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Assets and Liabilities, Lessee [Abstract]
Operating Lease, Right-of-Use Asset	$ 19,577	$ 7,630
Operating Lease, Liability, short term	3,825	5,937
Operating Lease, Liability, long term	37,720	4,044
Operating Lease, Liability	41,545
Finance Lease, Right-of-Use Asset	6,184	3,483
Finance Lease, Liability, short term	2,162	1,260
Finance Lease, Liability, long term	4,095	$ 2,230
Finance Lease, Liability	$ 6,257

Leases Leases - Maturity of Lea

Leases Leases - Maturity of Lease Liabilities Operating and Financing (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2022 USD ($)
Leases [Abstract]
2022	$ 4,063
2023	3,101
2024	6,682
2025	6,754
2026	5,821
Thereafter	27,512
Total Operating Lease Payments	34,000
Less interest and discount operating, total	(12,388)
Operating Lease, Liability	41,545
2022	2,404
2023	1,891
2024	1,698
2025	649
2026	73
Thereafter	0
Total Financing Lease Payments	6,715
Less interest and discount financing, total	(458)
Finance Lease, Liability	6,257
2022	6,467
2023	4,992
2024	8,380
2025	7,403
2026	5,894
Thereafter	27,512
Total Lease Payments	60,648
Less: Interest and discount	(12,846)
Present value of lease liabilities	47,802
Lessee, Lease, Description [Line Items]
Total Operating Lease Payments	34,000
GW Acquisition
Leases [Abstract]
Total Operating Lease Payments	53,933
Lessee, Lease, Description [Line Items]
Total Operating Lease Payments	$ 53,933
Maximum [Member]
Lessee, Lease, Description [Line Items]
Operating and Financing Lease Renewal Term	10 years
Minimum [Member]
Lessee, Lease, Description [Line Items]
Operating and Financing Lease Renewal Term	1 month

Asset Retirement Obligations _2

Asset Retirement Obligations Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance beginning of year, January 1	$ 159,672	$ 166,570
Accretion of asset retirement obligations	13,408	12,086	$ 10,072
Revisions in estimated cash flows	19,606	10,609
Obligations discharged with disposal of properties and asset retirements	(25,667)	(34,343)
Balance end of year, December 31	197,651	159,672	$ 166,570
Increase (Decrease) in Asset Retirement Obligations	5,332	4,750
Less: Current portion	(25,986)	(32,146)
Asset retirement obligations	171,665	127,526
SRC [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Business Acquisition Purchase Price Allocation Asset Retirement Obligation	$ 25,300	$ 0

Commitments and Contigencies (D

Commitments and Contigencies (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Supply Commitment [Line Items]
Dollar Commitment ($ in thousands)	$ 763,533
Transportation netted against Revenue	64,100	$ 31,300	$ 21,400
2022
Supply Commitment [Line Items]
Other Commitment	96,567
2023
Supply Commitment [Line Items]
Other Commitment	64,403
2024
Supply Commitment [Line Items]
Other Commitment	49,187
2025
Supply Commitment [Line Items]
Other Commitment	36,692
2026
Supply Commitment [Line Items]
Other Commitment	10,388
Thereafter
Supply Commitment [Line Items]
Other Commitment	28,364
Total commitment
Supply Commitment [Line Items]
Other Commitment	285,601
2023
Supply Commitment [Line Items]
Other Commitment	117,509
2024
Supply Commitment [Line Items]
Other Commitment	101,553
2025
Supply Commitment [Line Items]
Other Commitment	61,633
2026
Supply Commitment [Line Items]
Other Commitment	35,608
Thereafter
Supply Commitment [Line Items]
Other Commitment	43,801
Total commitment
Supply Commitment [Line Items]
Other Commitment	477,932
2022
Supply Commitment [Line Items]
Dollar Commitment ($ in thousands)	214,395
2023
Supply Commitment [Line Items]
Dollar Commitment ($ in thousands)	181,912
2024
Supply Commitment [Line Items]
Dollar Commitment ($ in thousands)	150,740
2025
Supply Commitment [Line Items]
Dollar Commitment ($ in thousands)	98,325
2026
Supply Commitment [Line Items]
Dollar Commitment ($ in thousands)	45,996
Thereafter
Supply Commitment [Line Items]
Dollar Commitment ($ in thousands)	$ 72,165

Commitments and Contingencies A

Commitments and Contingencies Additional information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Loss Contingencies [Line Items]
Transportation netted against Revenue	$ 64,100	$ 31,300	$ 21,400
Transportation, gathering and processing expenses	124,577	$ 100,403	$ 77,835
2022
Supply Commitment [Line Items]
Other Commitment	$ 117,828

Common Stock Stocked Based Comp

Common Stock Stocked Based Compensation Summary (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	May 31, 2020
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share based compensation expense	$ 26,846	$ 23,023	$ 22,200
Stock-based Compensation - G&A
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share based compensation expense	25,257	21,830	21,182
Stock-based Compensation - LOE
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share based compensation expense	$ 1,589	$ 1,193	$ 1,018
2018 Equity Incentive Plan [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized				7,050,000
Common stock shares remain avaliable for issuance	3,840,404
2010 Long-Term Equity Compensation Plan [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Common stock shares remain avaliable for issuance	245,156
Minimum [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Performance Shares Payout Range	0%
Maximum [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Performance Shares Payout Range	250%
Restricted Stock [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award	three-year

Common Stock Restricted Stock -

Common Stock Restricted Stock - TIme Based Awards (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award	three-year
Number of Shares
Outstanding beginning of year, January 1,	1,165,187
Granted	363,395
Vested	(581,343)
Forfeited	(50,728)
Outstanding end of year, December 31,	896,511	1,165,187
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of year, January 1,	$ 25.33
Weighted-average grant date fair value per share	70.01	$ 33.64	$ 11.98
Weighted average Vested	26.15
Weighted average Forfeited	40.58
Outstanding at end of year, December 31,	42.05	25.33
Weighted-average grant date fair value per share	$ 70.01	$ 33.64	$ 11.98
Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 24,700
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Period for Recognition	1 year 3 months 18 days
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested in Period, Fair Value	$ 15,200	$ 13,600	$ 20,400
Restricted Stock - Market Based Awards [Member]
Number of Shares
Outstanding beginning of year, January 1,	439,229
Granted	102,098
Vested	(578,937)
Outstanding end of year, December 31,	309,753	439,229
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of year, January 1,	$ 43.21
Weighted-average grant date fair value per share	107.85	$ 54.01	$ 33.52
Weighted average Vested	33.52
Outstanding at end of year, December 31,	71.76	43.21
Weighted-average grant date fair value per share	$ 107.85	$ 54.01	$ 33.52
Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 11,600
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Period for Recognition	1 year 3 months 18 days
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested in Period, Fair Value	$ 19,400	$ 11,600	$ 4,700

Common Stock Restricted Stock_2

Common Stock Restricted Stock - Market Based Awards Fair Value Assumptions (Details) - USD ($) $ / shares in Units, $ in Millions		12 Months Ended
	Jan. 14, 2020	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Repurchase Program, Authorized Amount	$ 525
Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Shares Payout Range		0%
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Shares Payout Range		250%
Restricted Stock - Market Based Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected term of award		2 years 10 months 24 days	3 years	3 years
Risk-free interest rate		1.70%	0.20%	1.40%
Expected Volatility		86.30%	84.60%	46.60%
Weighted-average grant date fair value per share		$ 107.85	$ 54.01	$ 33.52
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award		three-year
Weighted-average grant date fair value per share		$ 70.01	$ 33.64	$ 11.98
SRC [Member] | Restricted Stock - Market Based Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Market based performance shares granted to executives	155,928

Common Stock Schedule of Change

Common Stock Schedule of Changes in Restricted Stock - Market Based Awards (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Maximum [Member]
Weighted-Average Grant-Date Fair Value
Performance Shares Payout Range	250%
Restricted Stock - Market Based Awards [Member]
Number of Shares
Outstanding beginning of year, January 1,	439,229
Granted	102,098
Vested	(578,937)
Outstanding end of year, December 31,	309,753	439,229
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of year, January 1,	$ 43.21
Weighted average Vested	33.52
Outstanding at end of year, December 31,	$ 71.76	$ 43.21
Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 11,600
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Period for Recognition	1 year 3 months 18 days
Expected term of award	2 years 10 months 24 days	3 years	3 years
Risk-free interest rate	1.70%	0.20%	1.40%
Expected Volatility	86.30%	84.60%	46.60%
Weighted-average grant date fair value per share	$ 107.85	$ 54.01	$ 33.52
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested in Period, Fair Value	$ 19,400	$ 11,600	$ 4,700
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award	three-year
Number of Shares
Outstanding beginning of year, January 1,	1,165,187
Granted	363,395
Vested	(581,343)
Forfeited	(50,728)
Outstanding end of year, December 31,	896,511	1,165,187
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of year, January 1,	$ 25.33
Weighted average Vested	26.15
Weighted average Forfeited	40.58
Outstanding at end of year, December 31,	$ 42.05	$ 25.33
Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 24,700
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Period for Recognition	1 year 3 months 18 days
Weighted-average grant date fair value per share	$ 70.01	$ 33.64	$ 11.98
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested in Period, Fair Value	$ 15,200	$ 13,600	$ 20,400
Restricted Stock - Market Based Awards multiplier
Number of Shares
Granted	347,363
Weighted-Average Grant-Date Fair Value
Weighted-average grant date fair value per share	$ 33.52

Common Stock Preferred Stock (D

Common Stock Preferred Stock (Details) - $ / shares	Dec. 31, 2022	Jun. 23, 2008
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Preferred Stock, Par or Stated Value Per Share		$ 0.01
Preferred Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Preferred Stock, Shares Authorized		50,000,000
Preferred Stock, Shares Issued	0

Common Stock Stock Repurchase (

Common Stock Stock Repurchase (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Jan. 14, 2020
Equity, Class of Treasury Stock [Line Items]
Stock Repurchase Program, Authorized Amount				$ 525,000
Operating Loss Carryforwards	$ 401,500
Stock Repurchase Program, Remaining Authorized Repurchase Amount		$ 187,300
Treasury Stock, Common [Member]
Equity, Class of Treasury Stock [Line Items]
Stock Repurchased During Period, Shares	(12,145,000)	(3,753,000)	1,266,000
Payments for Repurchase of Common Stock	$ 823,400	$ 159,500
Stock Repurchase Program, Remaining Authorized Repurchase Amount	$ 454,700

Common Stock Dividends (Details

Common Stock Dividends (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Share-Based Payment Arrangement [Abstract]
Common Stock, Dividends, Per Share, Declared	$ 1.95	$ 0.86
Payments of Dividends	$ (181,573)	$ (83,615)	$ 0
Dividends, Common Stock	$ 184,300	$ (83,600)

Income Taxes Provision for Inco

Income Taxes Provision for Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Current Federal Tax Benefit (Expense)	$ (400)	$ 0	$ 1,592
Current State and Local Tax Benefit (Expense)	(900)	(200)	(220)
Current Income Tax Expense (Benefit)	(1,300)	(200)	1,372
Deferred Federal Income Tax Benefit (Expense)	(385,300)	(23,790)	5,460
Deferred State and Local Income Tax Benefit (Expense)	(67,600)	(2,593)	1,070
Deferred Income Tax from Continuing Operations	(452,900)	(26,383)	6,530
Income tax benefit (expense)	$ (454,200)	$ (26,583)	$ 7,902

Income Taxes Reconciliation of

Income Taxes Reconciliation of Statutory Rate to Effective Rate (Details)	12 Months Ended
	Dec. 31, 2022 Rate	Dec. 31, 2021 Rate	Dec. 31, 2020 Rate
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Statutory tax rate	21%	21%	21%
State income tax, net	2.40%	3.20%	3%
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Percent	(2.00%)	(19.80%)	(22.10%)
Other	(1.10%)	0.40%	(0.80%)
Effective Income Tax Rate Reconciliation, Percent	20.30%	4.80%	1.10%

Income Taxes Tax Effects of Tem

Income Taxes Tax Effects of Temporary differences that Give Rise to Significant Portions of the Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Components of Deferred Tax Assets [Abstract]
Deferred compensation	$ 7,985	$ 9,949
Asset retirement obligations	47,919	38,274
Federal NOL carryforwards	84,323	97,555
State NOL and tax credit carryforwards, net	16,190	20,266
State credit carryforwards	3,555	3,059
Deferred Tax Assets, Derivative Instruments	64,622	88,053
Other	8,407	8,308
Deferred Tax Assets, Valuation Allowance	0	(56,634)
Deferred tax assets	233,001	208,830
Components of Deferred Tax Liabilities [Abstract]
Properties and equipment	740,684	235,213
Net deferred tax liability	$ 507,683	$ 26,383

Income Taxes Additional Informa

Income Taxes Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2020	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Jan. 14, 2020
Operating Loss Carryforwards:
Document Period End Date		Dec. 31, 2022
Deferred Tax Liabilities, Property, Plant and Equipment		$ 740,684	$ 235,213
Effective Income Tax Rate Reconciliation, Percent		20.30%	4.80%	1.10%
Net deferred tax liability		$ 507,683	$ 26,383
Income Tax Expense (Benefit)		452,900	26,383	$ (6,530)
Operating Loss Carryforwards		401,500
State NOL carryforwards		16,190	20,266
State credit carryforwards		3,555	3,059
Deferred Tax Assets, Operating Loss Carryforwards		84,323	97,555
Impairment of properties and equipment	$ 881,100	6,762	402	882,393
Income tax benefit (expense)		(454,200)	(26,583)	$ 7,902
Deferred Tax Assets, Valuation Allowance		0	$ 56,634
State NOL Carryforwards
Operating Loss Carryforwards:
State NOL carryforwards		331,200
SRC NOL Acquired
Operating Loss Carryforwards:
Deferred Tax Assets, Operating Loss Carryforwards					$ 232,500
SRC NOL
Operating Loss Carryforwards:
Deferred tax asset, operating loss carryforward, annual limitation		16,100
2022 [Member] | State Credit Carryforwards
Operating Loss Carryforwards:
State credit carryforwards		4,500
Pre-2018 NOL [Member]
Operating Loss Carryforwards:
Operating Loss Carryforwards		$ 201,300

Earnings per share Earnings Per

Earnings per share Earnings Per Share (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Reconciliation of Weighted-Average Diluted Shares Outstanding
Weighted average common shares outstanding - basic	94,796	98,546	98,251
Diluted	96,174	100,154	98,251
Anti-dilutive Effect
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	176	144	1,936
Restricted Stock [Member]
Reconciliation of Weighted-Average Diluted Shares Outstanding
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements	1,352	1,596	0
Anti-dilutive Effect
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	144	28	1,707
Other Equity-Based Awards
Reconciliation of Weighted-Average Diluted Shares Outstanding
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements	26	12	0
Anti-dilutive Effect
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	32	116	229

Supplemental Cash Flow Supple_3

Supplemental Cash Flow Supplemental Cash Flow (Details) - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Supplemental Cash Flow Elements [Line Items]
Interest Paid, Excluding Capitalized Interest, Operating Activities	$ 58,143	$ 66,647	$ 75,506
Income Taxes Paid, Net	58	(1,057)	9
Capital Expenditures Incurred but Not yet Paid	(38,384)	(519)	28,676
Increase (Decrease) in Asset Retirement Obligations	21,778	11,673	54,984
Operating Lease, Payments	7,230	7,603	9,246
Operating Cash Flow from Financing Leases	254	117	156
Finance Lease, Principal Payments	2,039	1,688	1,905
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	17,247	1,457	4,305
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability	$ 4,919	$ 2,109	$ 703
Noncash or Part Noncash Acquisition, Noncash Financial or Equity Instrument Consideration, Shares Issued	293,314	0	1,009,015
Great Western Petroleum, LLC
Supplemental Cash Flow Elements [Line Items]
Business Combination, Recognized Identifiable Asset Acquired and Liability Assumed, Lease Obligation	$ 1,500

Uncategorized Items - pdce-2022

Label	Element	Value
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents	us-gaap_CashCashEquivalentsRestrictedCashAndRestrictedCashEquivalents	$ 963,000