PDC Energy (PDCE) 10-K 25 Feb 21 2020 FY Annual report Financial data

Cover Page

Cover Page - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2020	Feb. 16, 2021	Jun. 30, 2020
Cover [Abstract]
ICFR Auditor Attestation Flag	true
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2020
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		99,781,332
Entity Public Float			$ 1.2
Entity Central Index Key	0000077877
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
Amendment Flag	false

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Current assets:
Cash and cash equivalents	$ 2,623	$ 963
Accounts receivable, net	244,251	266,354
Fair value of derivatives	48,869	28,078
Prepaid expense and other assets	12,505	8,635
Total current assets	308,248	304,030
Properties and equipment, net	4,859,199	4,095,202
Fair value of derivatives	9,565	3,746
Other assets	60,961	45,702
Total Assets	5,237,973	4,448,680
Current liabilities:
Accounts payable	90,635	98,934
Production tax liability	124,475	76,236
Fair value of derivatives	98,152	2,921
Funds held for distribution	177,132	98,393
Interest payable	14,734	14,284
Other accrued liabilities	81,715	70,462
Other long-term debt, current	193,014	0
Liabilities, Current, Total	779,857	361,230
Long-term debt	1,409,548	1,177,226
Deferred income taxes	0	195,841
Asset retirement obligations	132,637	95,051
Fair value of derivatives	36,359	692
Other liabilities	264,034	283,133
Total Liabilities	2,622,435	2,113,173
Commitments and contingencies
Shareholders' Equity:
Common shares - par value $0.01 per share, 150,000,000 authorized, 99,758,720 and 61,652,412 issued as of December 31, 2020 and 2019, respectively	998	617
Additional Paid in Capital	3,387,754	2,384,309
Retained Earnings (Accumulated Deficit)	(772,265)	(47,945)
Treasury shares - at cost, 37,510 and 34,922 as of December 31, 2020 and 2019, respectively	(949)	(1,474)
Total Stockholders' Equity	2,615,538	2,335,507
Liabilities and Equity, Total	$ 5,237,973	$ 4,448,680

Balance Sheet Parentheticals (P

Balance Sheet Parentheticals (Parentheticals) - USD ($)	Dec. 31, 2020	Dec. 31, 2019
Treasury Stock, Shares	37,510	34,922
Commitments and contingencies
Common Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Common Stock, Shares Authorized	150,000,000	150,000,000
Common Stock, Shares, Issued	99,758,720	61,652,412

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended	12 Months Ended
	Sep. 30, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Revenues:
Crude oil, natural gas and NGLs sales		$ 1,152,555	$ 1,307,275	$ 1,389,961
Commodity price risk management gain (loss), net		180,270	(162,844)	145,237
Other Income		6,401	11,692	13,461
Revenues, Total		1,339,226	1,156,123	1,548,659
Costs, expenses and other:
Lease operating expenses		161,346	142,248	130,957
Production tax expense		59,368	80,754	90,357
Transportation, gathering and processing expenses		77,835	46,353	37,403
Exploration, geologic and geophysical expense		1,376	4,054	6,204
General and administrative expense		161,087	161,753	170,504
Depreciation, depletion and amortization		619,739	644,152	559,793
Accretion of asset retirement obligations		10,072	6,117	5,075
Impairment of properties and equipment		882,393	38,536	458,397
Loss (gain) on sale of properties and equipment		(724)	9,734	394
Other expenses		10,272	11,317	11,829
Total cost, expenses and other		1,982,764	1,145,018	1,470,913
Income (loss) from operations		(643,538)	11,105	77,746
Interest expense		(88,684)	(71,099)	(70,317)
Income (Loss) before income taxes	$ 963	(732,222)	(59,994)	7,429
Income tax benefit (expense)		7,902	3,322	(5,406)
Net Income (loss)		$ (724,320)	$ (56,672)	$ 2,023
Earnings per share:
Basic		$ (7.37)	$ (0.89)	$ 0.03
Diluted		$ (7.37)	$ (0.89)	$ 0.03
Weighted-average common shares outstanding:
Basic		98,251	64,032	66,059
Diluted		98,251	64,032	66,303

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Cash flows from operating activities:
Net income (loss)	$ (724,320)	$ (56,672)	$ 2,023
Adjustments to net income (loss) to reconcile to net cash provided by operating activities:
Net change in fair value of unsettled commodity derivatives	99,001	145,246	(260,775)
Depreciation, depletion and amortization	619,739	644,152	559,793
Impairment of properties and equipment	882,393	38,536	458,397
Accretion of asset retirement obligations	10,072	6,117	5,075
Non-cash stock-based compensation	22,200	23,837	21,782
Loss (gain) on sale of properties and equipment	724	(9,734)	(394)
Amortization and write-off of debt discount, premium and issuance costs	16,772	13,575	12,769
Deferred income taxes	(6,530)	(2,256)	6,105
Other	3,004	3,155	2,876
Accounts receivable	139,664	(88,304)	12,025
Other assets	(5,341)	(11,560)	(81)
Production tax liability	(50,803)	22,240	35,225
Accounts payable and accrued expenses	(66,183)	(29,578)	16,261
Funds held for future distribution	(23,621)	(7,298)	9,973
Asset retirement obligations	(27,491)	(21,511)	(13,341)
Other liabilities	(17,753)	168,813	20,801
Net cash from operating activities	870,079	858,226	889,302
Cash flows from investing activities:
Capital expenditures for development of crude oil and natural gas properties	(550,964)	(855,908)	(946,350)
Payments to Acquire Other Property, Plant, and Equipment	1,634	20,839	11,055
Acquisition of crude oil and natural gas properties	(139,812)	(13,207)	(180,026)
Proceeds from sale of properties and equipment	1,641	2,105	3,562
Proceeds from Sale of Oil and Gas Property and Equipment	3,610	202,076	44,693
Restricted cash	0	8,001	1,249
Net cash from investing activities	(687,159)	(677,772)	(1,087,927)
Net Cash Provided by (Used in) Financing Activities [Abstract]
Proceeds from revolving credit facility and other borrowings	1,799,350	1,577,000	1,072,500
Repayment of revolving credit facility and other borrowings	(1,635,350)	(1,605,500)	(1,040,000)
Proceeds from issuance of senior notes	148,500	0	0
Payment of debt issuance costs	(6,538)	(72)	(7,704)
Purchase of treasury shares	(23,819)	(154,363)	0
Purchase of treasury shares for employee stock-based compensation tax withholding obligations	(9,345)	(4,003)	(5,147)
Redemption of senior notes	(452,153)	0	0
Finance Lease, Principal Payments	(1,905)	(1,952)	(1,495)
Other	0	0	(55)
Net cash from financing activities	(181,260)	(188,890)	18,099
Net change in cash, cash equivalents and restricted cash	1,660	(8,436)	(180,526)
Cash, cash equivalents and restricted cash, beginning of year	963	9,399	189,925
Cash, cash equivalents and restricted cash, end of year	$ 2,623	$ 963	$ 9,399

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			65,955,080			55,927
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stockholders' Equity Attributable to Parent		$ 2,507,649
Purchase of treasury shares						(102,647)
Issuance of treasury shares			0			104,068
Non-employee directors' deferred compensation plan						9,286
Stockholders' Equity Beginning, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2017			$ 659	$ 2,503,294	$ 6,704	$ (3,008)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Purchase of treasury shares		5,147				(5,147)
Share-based Compensation expense	$ 21,782			21,780
Issuance of treasury shares				(5,561)		5,561
Non-employee directors' deferred compensation plan		(491)				491
Net income (Loss) attributable to shareholders	2,023	2,023			2,023
Stock Issued During Period, Shares, Restricted Stock Award, Gross			193,529
Shares Issued, Value, Share-based Payment Arrangement, after Forfeiture		21,782	$ 2
Stockholders' Equity Ending, Including Portion Attributable to Noncontrolling Interest at Dec. 31, 2018			$ 661	2,519,423	8,727	$ (2,103)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stockholders' Equity, Other		90		(90)	0
Shares, Issued			66,148,609			45,220
Stockholders' Equity Attributable to Parent		2,526,708
Purchase of treasury shares						(106,151)
Issuance of treasury shares			0			112,646
Purchase of treasury shares		4,003				$ (4,003)
Share-based Compensation expense	23,837			23,835
Issuance of treasury shares				(4,505)		4,505
Net income (Loss) attributable to shareholders	(56,672)	(56,672)			(56,672)
Stock Issued During Period, Shares, Restricted Stock Award, Gross			213,745
Shares Issued, Value, Share-based Payment Arrangement, after Forfeiture		23,837	$ 2
Stockholders' Equity Ending, 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]
Stock Repurchased and Retired During Period, Shares			(4,706,139)				4,706,139
Stock Repurchased and Retired During Period, Value	0		$ (46)	(154,317)			$ 154,363
Treasury Stock, Shares, Retired			(3,803)			3,803
Treasury Stock, Retired, Cost Method, Amount				(127)		$ 127
Stock Repurchased During Period, Shares							(4,706,139)
Stock Repurchased During Period, Value		(154,363)					$ (154,363)
Shares, Issued			61,652,412			34,922
Stockholders' Equity Attributable to Parent	2,335,507	2,335,507
Purchase of treasury shares							456,995
Issuance of treasury shares			0			114,759
Purchase of treasury shares		9,345				$ 9,345
Share-based Compensation expense	22,200			19,738
Issuance of treasury shares				0		0
Net income (Loss) attributable to shareholders	(724,320)	(724,320)			(724,320)
Stock Issued During Period, Shares, Restricted Stock Award, Gross			529,911
Shares Issued, Value, Share-based Payment Arrangement, after Forfeiture		22,200	$ 5
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)		$ (12)	(23,807)			$ 23,819
Stock Issued During Period, Shares, Acquisitions			39,182,045
Stock Issued During Period, Value, Acquisitions		1,015,312	$ 391	1,014,921
Treasury Stock, Shares, Retired			(339,648)			339,648
Treasury Stock, Retired, Cost Method, Amount				$ (7,407)		$ 7,413
Stock Repurchased During Period, Shares							(1,266,000)
Stock Repurchased During Period, Value		(23,819)					$ (23,819)
Shares, Issued			99,758,720			(37,510)
Stockholders' Equity Attributable to Parent	$ 2,615,538	$ 2,615,538

NATURE OF OPERATIONS AND BASIS

NATURE OF OPERATIONS AND BASIS OF PRESENTATION	12 Months Ended
	Dec. 31, 2020
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 Wolfcamp zones. We previously operated properties in the Utica Shale in Southeastern Ohio; however, we divested these properties during the first quarter of 2018. As of December 31, 2020, we owned an interest in approximately 3,727 productive gross 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 upon consolidation. During 2020, the effects of coronavirus 2019 (“COVID-19”) led to a significant decline in global demand for crude oil and natural gas, contributing to a drastic reduction in commodity prices and negatively impacting oil and natural gas producers located in the United States, including PDC. The commodity price environment may remain volatile for an extended period as a result of reduced global oil and natural gas demand and the global economic recession. We expect to be able to fund our operations, planned capital expenditures and working capital and other requirements during the next 12 months and the foreseeable future.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2020
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 in 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 computing impairment test limitations; 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, 2020 and 2019. 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, changes in the fair value of our derivative instruments are recorded 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, 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. 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. Annually, or 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 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. Other Property and Equipment. Other property and equipment such as pipelines, vehicles, facilities, office furniture and equipment, buildings and computer hardware and software 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. Total depreciation expense related to other property and equipment was $8.7 million, $5.7 million and $8.5 million for the year ended December 31, 2020, 2019 and 2018, 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. Maintenance and repair costs on other property and equipment are charged to expense as incurred. Major renewals and improvements are capitalized and depreciated over the remaining useful life of the asset. Upon the sale or other disposition of assets, the cost and related accumulated DD&A are removed, the proceeds are applied and any resulting gain or loss is recognized. 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. Interest costs are capitalized as part of the historical cost of acquiring assets. Investments in unproved crude oil and natural gas properties and major development projects, on which DD&A expense is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready to be placed into service. Capitalized interest is calculated by multiplying our weighted-average interest rate on our outstanding debt by the qualifying costs. Interest capitalized may not exceed gross interest expense for the period. As the qualifying asset is placed into service, we begin amortizing the related capitalized interest over the useful life of the asset. Capitalized interest totaled $19.7 million, $13.4 million and $9.2 million during the year ended December 31, 2020, 2019 and 2018, respectively. Assets Held-for-Sale. Assets held-for-sale are valued at the lower of their carrying amount or estimated fair value, less costs to sell. If the carrying amount of the assets exceeds their estimated fair value, an impairment loss is recognized. Fair values are estimated using accepted valuation techniques, such as a discounted cash flow model, earnings multiples or indicative bids, when available. We consider historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected on the consolidated financial statements. DD&A expense is not recorded on assets once they are classified as held-for-sale. Assets classified as held-for-sale are expected to be disposed of within one year. 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. The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The 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. The Company's 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 (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. 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 crude oil, natural gas or NGLs 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, 2020, 2019 and 2018, 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 the crude oil, natural gas or NGLs has been transferred to the purchasers of these commodities 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, the Company has utilized the practical expedient in ASC Topic 606 which states the Company is 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 of non-producing interests and unproved mineral leases 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). Recently Adopted Accounting Pronouncement In March 2020, the SEC adopted final rules that amend the financial disclosure requirements for subsidiary issuers and guarantors of registered debt securities in Rule 3-10 of Regulation S-X. The amended rules, which can be found under new Rule 13-01 of Regulation S-X, narrow the circumstances that require separate financial statements of subsidiary issuers and guarantors and streamline the alternative disclosures required in lieu of those statements. The amended rules allow registrants, among other things, to disclose summarized financial information of the issuer and guarantors on a combined basis and to present only the most recently completed fiscal year and subsequent year-to-date interim period. The rule replaces the requirement to provide condensed consolidating financial information with a requirement to present summarized financial information of the issuers and guarantors. These disclosures may be included in the notes to the consolidated financial statements or can be disclosed outside the notes to the consolidated financial statements (i.e. management's discussion and analysis section). The rule is effective in the first quarter of 2021, with earlier adoption permitted. We early adopted the rule in the first quarter of 2020 and have provided these disclosures outside the notes to the condensed consolidated financial statements. In October 2020, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2020-09, Amendments to SEC Paragraphs Pursuant to SEC Release No. 33-10762 , to align the standards under Accounting Standard Codification 470, Debt , with the SEC final rules discussed above. Recently Issued Accounting Pronouncement but Not Yet Adopted In August 2020, FASB issued Accounting Standards Update ("ASU") No. 2020-06, Debt - Debt with conversion and other options and derivatives and hedging on contracts in entity's own equity.
Description of New Accounting Pronouncements Not yet Adopted	Recently Issued Accounting Pronouncement but Not Yet Adopted In August 2020, FASB issued Accounting Standards Update ("ASU") No. 2020-06, Debt - Debt with conversion and other options and derivatives and hedging on contracts in entity's own equity.

BUSINESS COMBINATIONS (Notes)

BUSINESS COMBINATIONS (Notes)	12 Months Ended
	Dec. 31, 2020
Acquisition [Abstract]
Mergers, Acquisitions and Dispositions Disclosures [Text Block]	NOTE 3 - BUSINESS COMBINATION In January 2020, we merged with SRC in a transaction valued at $1.7 billion, inclusive of SRC's net debt (the "SRC Acquisition"). SRC was an independent oil and natural gas company engaged in the exploration, development and production of unconventional oil and associated liquids-rich natural gas reserves in Weld County, Colorado. The acquisition added approximately 83,000 net acres which are located on large, contiguous acreage blocks in the core of the Wattenberg Field. Upon closing, we issued approximately 38.9 million shares of our common stock to SRC shareholders and holders of SRC equity awards, reflecting the issuance of 0.158 of a share of our common stock in exchange for each outstanding share of SRC common stock and the cancellation of outstanding SRC equity awards pursuant to the terms of the merger agreement that we entered into with the SRC (the "Merger Agreement"). During the year ended December 31, 2020, we recorded transaction costs related to the SRC Acquisition of $19.9 million. These expenses were accounted for separately from the assets and liabilities assumed and are included in general and administrative expense in the consolidated statements of operations. 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 SRC Acquisition: (in thousands) Consideration: Cash $ 40 Retirement of seller's credit facility 166,238 Total cash consideration 166,278 Common stock issued 1,009,015 Shares withheld in lieu of taxes 6,299 Total consideration $ 1,181,592 Recognized amounts of identifiable assets acquired and liabilities assumed: Assets acquired: Current assets $ 145,792 Properties and equipment, net - proved 1,613,674 Properties and equipment, net - unproved 109,615 Properties and equipment, net - other 16,242 Deferred tax asset 189,311 Other assets 11,810 Total assets acquired $ 2,086,444 Liabilities assumed: Current liabilities $ (253,967) Senior notes (555,500) Asset retirement obligations (42,417) Other liabilities (52,968) Total liabilities assumed (904,852) Total identifiable net assets acquired $ 1,181,592 This acquisition was accounted for under the acquisition method of accounting for business combinations. Accordingly, we conducted assessments of the net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred. The fair value 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 reserves volumes, future operating and development costs , future commodity prices, lease terms and expirations and a market-based weighted-average cost of capital rate of 10 percent. These inputs require significant judgments and estimates by management at the time of the valuation. The results of operations for the SRC Acquisition since the closing date have been included in our consolidated financial statements for the year ended December 31, 2020 and include approximately $320.9 million of total revenue, and $46.5 million of income from operations. Pro Forma Information. The following unaudited pro forma financial information represents a summary of the consolidated results of operations for the years ended December 31, 2020 and 2019, assuming the acquisition had been completed as of January 1, 2019. 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) the Company's common stock issued to convert SRC's outstanding shares of common stock and equity awards, (ii) the depletion of SRC's fair-valued proved oil and gas properties using the successful efforts method of accounting and (iii) the estimated tax impacts of the proforma adjustments, if any. 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. Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by the Company and SRC totaling approximately $38.0 million and $15.9 million for the years ended December 31, 2020 and 2019, respectively. Year Ended December 31, 2020 2019 (in thousands, except per share data) Total revenue $ 1,361,051 $ 1,761,498 Net income (loss) (695,663) 139,578 Earnings (loss) per share: Basic $ (6.97) $ 1.36 Diluted (6.97) 1.35

Revenue Recognition Revenue Rec

Revenue Recognition Revenue Recognition (Notes)	12 Months Ended
	Dec. 31, 2020
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 2020 2019 2018 (in thousands) Crude oil Wattenberg Field $ 668,948 $ 767,760 $ 783,158 Delaware Basin 147,902 252,929 252,107 Utica Shale (1) — — 2,696 Total 816,850 1,020,689 1,037,961 Natural gas Wattenberg Field 171,755 137,143 130,073 Delaware Basin 6,997 13,877 32,010 Utica Shale (1) — — 1,109 Total 178,752 151,020 163,192 NGLs Wattenberg Field 128,126 94,347 132,820 Delaware Basin 28,827 41,219 55,148 Utica Shale (1) — — 840 Total 156,953 135,566 188,808 Revenue by Operating Region Wattenberg Field 968,829 999,250 1,046,051 Delaware Basin 183,726 308,025 339,265 Utica Shale (1) — — 4,645 Total $ 1,152,555 $ 1,307,275 $ 1,389,961 ____________ (1) In March 2018, we completed the disposition of our Utica Shale properties. Contract Assets. Contract assets include material contributions in aid of construction, which are common in purchase and processing agreements with midstream service providers that are our customers. The intent of the payments is primarily to reimburse the customer for actual costs incurred related to the construction of its gathering and processing infrastructure. Contract assets are included in other assets on the consolidated balance sheets. The contract assets are amortized as a reduction to crude oil, natural gas and NGLs sales revenue during the periods in which the related production is transferred to the customer. The following table presents the changes in carrying amounts of the contract assets associated with our crude oil, natural gas and NGLs sales revenue for the periods presented: December 31, 2020 2019 (in thousands) Beginning balance $ 11,494 $ 11,144 Additions 16,739 443 Amortized as a reduction to crude oil, natural gas and NGLs sales (2,361) (93) Ending balance $ 25,872 $ 11,494

FAIR VALUE MEASUREMENTS AND DIS

FAIR VALUE MEASUREMENTS AND DISCLOSURES	12 Months Ended
	Dec. 31, 2020
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, discount rates, volatility factors and nonperformance risk. Nonperformance 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 validate our fair value measurement by corroborating the original source of inputs, monitoring changes in valuation methods and assumptions, and reviewing counterparty statements and other supporting documentation. Our crude oil and natural gas fixed-price exchanges are included in Level 2. Our collars are included in Level 3. Our basis exchanges are included in Level 2 and 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 periods presented: December 31, 2020 2019 Significant Other Significant Total Significant Other Significant Total (in thousands) Total assets $ 36,895 $ 21,539 $ 58,434 $ 22,886 $ 8,938 $ 31,824 Total liabilities (104,545) (29,966) (134,511) (3,089) (524) (3,613) Net derivative instruments $ (67,650) $ (8,427) $ (76,077) $ 19,797 $ 8,414 $ 28,211 The following table presents a reconciliation of our Level 3 assets and liabilities measured at fair value: Year Ended December 31, 2020 2019 2018 (in thousands) Fair value of Level 3 instruments, net asset (liability) beginning of period $ 8,414 $ 58,329 $ (9,687) Changes in fair value included in consolidated statements of operations line item: Commodity price risk management gain (loss), net 37,821 (41,749) 63,257 Settlements included in consolidated statements of operations line items: Commodity price risk management gain (loss), net (54,662) (8,166) 4,759 Fair value of Level 3 instruments, net asset (liability) end of period $ (8,427) $ 8,414 $ 58,329 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 $ — $ (22,694) $ — Total $ — $ (22,694) $ — The significant unobservable input used in the fair value measurement of our derivative contracts is the implied volatility curve, which is provided by a third-party vendor. 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 utilize fair value with inputs that are not observable in the market, 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. 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 not elected 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 and convertible notes as of the dates indicated: December 31, 2020 2019 Estimated Fair Value Percent of Par Estimated Fair Value Percent of Par (in millions) Senior notes: 2021 Convertible Notes $ 196.2 98.1 % $ 188.6 94.3 % 2024 Senior Notes 410.8 102.7 % 409.2 102.3 % 2025 Senior Notes 102.8 100.5 % — — % 2026 Senior Notes 775.5 103.4 % 599.4 99.9 %

DERIVATIVE FINANCIAL INSTRUMENT

DERIVATIVE FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2020
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 oil and 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, 2020, we had derivative instruments in place for a portion of our anticipated 2021 and 2022 production. 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, 2020 and 2019, 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. Commodity Derivative Contracts. As of December 31, 2020, we had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted-average contract price is shown. Collars Fixed-Price Exchanges 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, 2020 (1) (in thousands) Floors Ceilings Crude Oil NYMEX 2021 4,008 $ 38.76 $ 50.05 10,176 $ 47.01 $ (20,341) 2022 900 40.00 52.05 4,884 41.18 (26,440) Total Crude Oil 4,908 15,060 (46,781) Natural Gas NYMEX 2021 62,625 2.46 2.86 31,800 2.40 (9,169) 2022 17,400 2.50 2.89 8,700 2.62 1,325 Total Natural Gas 80,025 40,500 (7,844) Basis Protection - Natural Gas CIG 2021 — — — 94,425 (0.46) (19,773) 2022 — — — 26,100 (0.34) (1,679) Total Basis Protection - Natural Gas — 120,525 (21,452) Commodity Derivatives Fair Value $ (76,077) Effect of Derivative Instruments on the Consolidated Balance Sheet. The following table presents the consolidated balance sheet line item and fair value amounts of our derivative instruments as of the dates indicated: December 31, Consolidated Balance Sheet Line Item 2020 2019 (in thousands) Derivative assets: Current Commodity derivative contracts Fair value of derivatives $ 48,869 $ 27,766 Basis protection derivative contracts Fair value of derivatives — 312 48,869 28,078 Non-current Commodity derivative contracts Fair value of derivatives 9,565 3,746 Total derivative assets $ 58,434 $ 31,824 Derivative liabilities: Current Commodity derivative contracts Fair value of derivatives $ 78,379 $ 529 Basis protection derivative contracts Fair value of derivatives 19,773 2,392 98,152 2,921 Non-current Commodity derivative contracts Fair value of derivatives 34,680 692 Basis protection derivative contracts Fair value of derivatives 1,679 — Total derivative liabilities $ 134,511 $ 3,613 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: As of December 31, 2020 Total Gross Amount Presented on Balance Sheet Effect of Master Netting Agreements Total Net Amount (in thousands) Derivative assets: Derivative instruments, at fair value $ 58,434 $ (39,691) $ 18,743 Derivative liabilities: Derivative instruments, at fair value $ 134,511 $ (39,691) $ 94,820 As of December 31, 2019 Total Gross Amount Presented on Balance Sheet Effect of Master Netting Agreements Total Net Amount (in thousands) Derivative assets: Derivative instruments, at fair value $ 31,824 $ (2,619) $ 29,205 Derivative liabilities: Derivative instruments, at fair value $ 3,613 $ (2,619) $ 994 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: Year Ended December 31, Consolidated Statements of Operations Line Item 2020 2019 2018 (in thousands) Commodity price risk management gain (loss), net Net settlements $ 279,271 $ (17,598) $ (115,538) Net change in fair value of unsettled derivatives (99,001) (145,246) 260,775 Total commodity price risk management gain (loss), net $ 180,270 $ (162,844) $ 145,237 Derivative Counterparties. Our commodity derivative instruments expose us to credit risk of non-performance by our counterparties. We primarily 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 nonperformance of our current counterparties on the fair value of our derivative instruments is not significant at December 31, 2020; however, this determination may change.

PROPERTIES AND EQUIPMENT

PROPERTIES AND EQUIPMENT	12 Months Ended
	Dec. 31, 2020
Oil and Gas Property [Abstract]
Property, Plant and Equipment Disclosure	NOTE 7 - PROPERTIES AND EQUIPMENT, NET The following table presents the components of properties and equipment, net of accumulated DD&A, as of the dates indicated: December 31, 2020 2019 (in thousands) Properties and equipment, net: Crude oil and natural gas properties Proved $ 7,523,639 $ 6,241,780 Unproved 350,677 403,379 Total crude oil and natural gas properties 7,874,316 6,645,159 Infrastructure and other 65,027 41,888 Land and buildings 24,299 12,312 Construction in progress 523,550 408,428 Properties and equipment, at cost 8,487,192 7,107,787 Accumulated DD&A (3,627,993) (3,012,585) Properties and equipment, net $ 4,859,199 $ 4,095,202 Midstream Asset Divestitures. During the second quarter of 2019, we completed the sales of our Delaware Basin produced water gathering and disposal, crude oil gathering and natural gas gathering assets (the "Midstream Asset Divestitures") for aggregate proceeds of $345.6 million. The proceeds were received upon closing, with the exception of $82.0 million that we received in June 2020. Concurrent with the Midstream Asset Divestitures, we entered into agreements with the purchasers which provide us with certain gathering, processing, transportation and water disposal services. See Note 8 - Accounts Receivable, Other Accrued Expenses and Other Liabilities for further details regarding these agreements. Proceeds were allocated first to the assets sold based upon the fair values of the tangible assets sold, with the remainder of $179.6 million allocated to the acreage dedication agreements. We recorded an aggregate gain on the sale of $34.0 million based on the fair value of the tangible assets sold. The Midstream Asset Divestitures did not represent a strategic shift in our operations or have a significant impact on our operations or financial results; therefore, we did not account for the divested assets as discontinued operations. Impairments. The following table presents impairment charges recorded for properties and equipment: Year Ended December 31, 2020 2019 2018 (in thousands) Impairment of proved and unproved properties $ 881,238 $ 10,599 $ 458,397 Impairment of infrastructure and other 1,155 27,937 — Total impairment of properties and equipment $ 882,393 $ 38,536 $ 458,397 Oil and Gas Properties. In the first quarter of 2020, the significant decline in crude oil prices in addition to the ongoing effects of COVID-19 was considered a triggering event that required us to assess our crude oil and natural gas properties for possible impairment. As a result of our assessment, we recorded impairment expense of $881.1 million to our proved and unproved properties. Proved Properties. Of the total impairment expense recognized, approximately $753.0 million was related to our Delaware Basin proved properties. These impairment charges represented the amount by which the carrying value of the crude oil and natural gas properties exceeded the estimated fair value. We estimated the fair value of proved crude oil and natural gas properties using valuation techniques that convert future cash flows to a single discounted amount, a level 3 input. 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 discount rate of 17 percent, which was based on a weighted-average cost of capital for the area where the assets are located. There were no further triggering events identified for the remainder of 2020. There were no impairment charges recognized related to our proved properties during the years ended December 31, 2019 and 2018. Unproved Properties. We recognized approximately $127.3 million of impairment charges for our unproved properties in the Delaware Basin during the three months ended March 31, 2020. These impairment charges were recognized based on the fair value of the properties, a Level 3 input. The fair value is estimated based on a review of our current drilling plans, estimated future cash flows for probable well locations and expected future lease expirations, primarily in areas where we have no development plans. There were no further triggering events identified for the remainder of 2020. During the years ended December 31, 2019 and 2018, we recorded impairment charges totaling $10.6 million and $458.4 million related to the divestiture of unproved leaseholds and then-current and anticipated near-term leasehold expirations within our non-focus areas of the Delaware Basin that we determined not to develop. Other Property and Equipment Impairment. During the year ended December 31, 2019, we recorded impairments of $27.9 million related to certain midstream facility infrastructure in the Delaware Basin. Upon closing of the Midstream Asset Divestitures, it was determined that the net book value of these assets was not recoverable. Suspended Well Costs. The following table presents the capitalized exploratory well cost pending determination of proved reserves and included in properties and equipment as of the dates indicated: December 31, 2020 2019 (in thousands, except for number of wells) Beginning balance $ 16,078 $ 12,188 Additions to capitalized exploratory well costs pending the determination of proved reserves 11,770 31,901 Reclassifications to proved properties (20,389) (28,011) Ending balance $ 7,459 $ 16,078 Number of wells pending determination at period-end 2 4 Our net capitalized exploratory well costs that have been capitalized for a period greater than one year as of December 31, 2020 was $7.5 million, which consists of the entire balance of our suspended well costs. We expect to complete our two gross suspended wells associated with two projects in the first half of 2021. We did not have any capitalized costs for a period greater than one year as of December 31, 2019. During 2020, two wells classified as exploratory as of December 31, 2019 were reclassified as productive and no new wells drilled were classified as exploratory. Exploration Expenses. The following table presents the major components of exploration, geologic and geophysical expense: Year Ended December 31, 2020 2019 2018 (in thousands) Geological and geophysical costs, including seismic purchases $ 253 $ 3,017 $ 3,401 Exploratory dry hole costs — — 113 Operating, personnel and other 1,123 1,037 2,690 Total exploration, geologic and geophysical expense $ 1,376 $ 4,054 $ 6,204

Accounts Receivable, Other Accr

Accounts Receivable, Other Accrued Expenses and Other Liabilities	12 Months Ended
	Dec. 31, 2020
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, 2020 2019 (in thousands) Crude oil, natural gas and NGLs sales $ 178,147 $ 149,758 Joint interest billings 50,329 29,510 Midstream asset divestitures deferred payments — 81,702 Other 22,538 12,860 Allowance for doubtful accounts (6,763) (7,476) Accounts receivable, net $ 244,251 $ 266,354 The Company's accounts receivable consists mainly of receivables from (i) crude oil, natural gas and NGLs purchasers, (ii) receivable from joint interest owners in the properties we operate and (iii) from derivative counterparties. Most payments for production are received within two months after the production date. For receivables from joint interest owners, the Company typically has 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. As of December 31, 2020 and 2019, four of our customers represented 10 percent or more of our crude oil, natural gas and NGLs accounts receivable balance. During the year ended December 31, 2020, four customers accounted for approximately 31 percent, 17 percent, 16 percent and 13 percent of our total crude oil, natural gas and NGLs sales. During the year ended December 31, 2019, four customers accounted for approximately 20 percent, 17 percent,16 percent and 11 percent of our total crude oil, natural gas and NGLs sales. During the year ended December 31, 2018, one customer accounted for approximately 13 percent of our total crude oil, natural gas and NGLs sales. However, 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. Other Accrued Expenses. The following table presents the components of other accrued expenses as of the dates indicated: December 31, 2020 2019 (in thousands) Employee benefits $ 23,304 $ 21,611 Asset retirement obligations 33,933 32,200 Environmental expenses 10,139 2,256 Operating and finance leases 7,986 5,926 Other 6,353 8,469 Other accrued expenses $ 81,715 $ 70,462 Other Liabilities. The following table presents the components of other liabilities as of the dates indicated: December 31, 2020 2019 (in thousands) Deferred midstream gathering credits $ 168,478 $ 175,897 Deferred oil gathering credits 18,090 20,100 Production taxes 65,592 68,020 Operating and finance leases 10,763 15,779 Other 1,111 3,337 Other liabilities $ 264,034 $ 283,133 Deferred Midstream Gathering Credits. In the second quarter of 2019, concurrent with the sale of our Delaware Basin midstream assets, we entered into an agreement with the purchasers that dedicated the gathering of certain 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. Deferred Oil Gathering Credits. In 2018, we entered into an agreement that dedicates crude oil from the majority of our Wattenberg Field acreage to the midstream provider's gathering lines and extends the term of the agreement through December 2029. The acreage dedication agreement resulted in an initial cash receipt and is being amortized over the life of the agreement. 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, 2020 2019 (in thousands) Crude oil, natural gas and NGL sales $ 1,013 $ 439 Transportation, gathering and processing expenses 5,618 3,659 Lease operating expenses 2,015 935

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
Long-term Debt [Text Block]	NOTE 9 - LONG-TERM DEBT Long-term debt consisted of the following as of the dates indicated: December 31, 2020 2019 (in thousands) Senior Notes: 1.125% Convertible Notes due September 2021: Principal amount $ 200,000 $ 200,000 Unamortized discount (6,295) (14,763) Unamortized debt issuance costs (691) (1,666) Net of unamortized discount and debt issuance costs 193,014 183,571 6.125% Senior Notes due September 2024: Principal amount 400,000 400,000 Unamortized debt issuance costs (3,632) (4,611) Net of unamortized debt issuance costs 396,368 395,389 6.25% Senior Notes due December 2025: Principal amount 102,324 — Unamortized premium 880 — Net of unamortized premium 103,204 — 5.75% Senior Notes due May 2026: Principal amount 750,000 600,000 Unamortized discount (1,429) — Unamortized debt issuance costs (6,595) (5,734) Net of unamortized discount and debt issuance costs 741,976 594,266 Total senior notes 1,434,562 1,173,226 Revolving Credit Facility: Revolving credit facility due May 2023 168,000 4,000 Total debt, net of unamortized discount, premium, and debt issuance costs 1,602,562 1,177,226 Less current portion of long-term debt 193,014 — Total long-term debt $ 1,409,548 $ 1,177,226 Senior Notes 2021 Convertible Notes. In September 2016, we issued $200 million of 1.125% convertible notes due September 15, 2021 (the "2021 Convertible Notes"). Interest is payable semi-annually in arrears on March 15 and September 15. The 2021 Convertible Notes are convertible prior to March 15, 2021 only upon specified events and during specified periods and, thereafter, at any time, at an initial conversion rate of 11.7113 shares of our common stock per $1,000 principal amount of the 2021 Convertible Notes, which is equal to an initial conversion price of approximately $85.39 per share. The conversion rate is subject to adjustment upon certain events. Upon conversion, the 2021 Convertible Notes may be settled, at our sole election, in shares of our common stock, cash or a combination thereof. We have initially elected a combination settlement method to satisfy our conversion obligation, which allows us to settle the principal amount of the 2021 Convertible Notes in cash and to settle the excess conversion value, if any, in shares, as well as cash in lieu of fractional shares. We may not redeem the 2021 Convertible Notes prior to their maturity date. If we undergo a "fundamental change", as defined in the indenture for the 2021 Convertible Notes, subject to certain conditions, holders of the 2021 Convertible Notes may require us to repurchase all or part of the 2021 Convertible Notes for cash at a price equal to 100 percent of the principal amount of the 2021 Convertible Notes to be repurchased, plus any accrued and unpaid interest. The occurrence of a fundamental change will also result in the 2021 Convertible Notes becoming convertible. We allocated the gross proceeds of the 2021 Convertible Notes between the liability and equity components of the debt. The initial $160.5 million liability component was determined based on the fair value of similar debt instruments, excluding the conversion feature, priced on the same day we issued the 2021 Convertible Notes. The initial $39.5 million equity component represents the debt discount and was calculated as the difference between the fair value of the debt and the gross proceeds of the 2021 Convertible Notes. Approximately $4.8 million in costs associated with the issuance of the 2021 Convertible Notes were capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes. Based upon the Company's stock price of $20.53 per share as of December 31, 2020, the “if-converted” value of the 2021 Convertible Notes did not exceed the principal amount. 2024 Senior Notes. In September 2016, we issued $400 million aggregate principal amount of 6.125% senior notes due September 15, 2024. Interest is payable semi-annually on March 15 and September 15. Approximately $7.8 million in costs associated with the issuance of the 2024 Senior Notes were capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes. The 2024 Senior Notes are redeemable after September 15, 2020 at fixed redemption prices, currently 103.063 percent of the principal amount redeemed. 2025 Senior Notes. Upon completion of the SRC Acquisition in January 2020, we assumed $550 million aggregate principal amount of 6.25% senior notes due December 1, 2025 (the "2025 Senior Notes"). The 2025 Senior Notes were recorded at their approximate fair value of $555.5 million. The difference between the acquisition date fair value and the principal amount of the 2025 Senior Notes will be recognized as a reduction to interest expense over the remaining life of the notes. Interest is payable semi-annually on June 1 and December 1. On January 17, 2020, we commenced an offer to repurchase the 2025 Senior Notes from the holders at 101 percent of the principal amount of the 2025 Senior Notes, together with any accrued and unpaid interest. Upon expiration of the repurchase offer on February 18, 2020, holders of $447.7 million of the outstanding 2025 Senior Notes accepted the redemption offer for a total redemption price of approximately $452.2 million, plus accrued and unpaid interest of $6.2 million. The fair value of the 2025 Senior Notes approximated the repurchase offer price, resulting in recognition of an immaterial loss on extinguishment of the repurchased notes. The repurchase was funded by proceeds from our revolving credit facility. An aggregate principal amount of approximately $102.3 million remains outstanding. On and after December 1, 2020, the Company may redeem the remaining 2025 Senior Notes at a redemption price equal to a specified percentage of the principal amount of the redeemed notes (103.125% for 2021, 101.563% for 2022, and 100% for 2023 and thereafter, during the twelve-month period beginning on December 1 of each applicable year), plus accrued and unpaid interest. 2026 Senior Notes. In November 2017, we issued $600 million aggregate principal amount 5.75% senior notes due May 15, 2026 (the "2026 Senior Notes"). Interest is payable semi-annually on May 15 and November 15. Approximately $7.6 million in costs associated with the issuance of the 2026 Senior Notes were capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes. In September 2020, we issued an additional $150 million aggregate principal amount of the 2026 Senior Notes at a price equal to 99 percent of par, which resulted in net proceeds of $146.7 million, after deducting the original issuance discount of $1.5 million and debt issuance costs of $1.8 million. The additional 2026 Senior Notes issued have the same terms and conditions as the existing 2026 Senior Notes. The 2026 Senior Notes are redeemable after May 15, 2021 at fixed redemption prices beginning at 104.313 percent of the principal amount redeemed. At any time prior to May 15, 2021, we may redeem all or part of the 2026 Senior Notes at a make-whole price set forth in the indenture which generally approximates the present value of the redemption price at May 15, 2021 and remaining interest payments on the 2026 Senior Notes at the time of redemption. Our wholly-owned subsidiary, PDC Permian, Inc., is a guarantor of our obligations under the 2021 Convertible Notes, the 2024 Senior Notes, the 2025 Senior Notes and the 2026 Senior Notes (collectively, the "Senior Notes"). 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 2024 Senior Notes, 2025 Senior Notes and 2026 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 any 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 any accrued and unpaid interest to the date of purchase. The indentures governing the 2024 Senior Notes, 2025 Senior Notes, and 2026 Senior Notes contain covenants that, among other things, limit our ability and the ability of our subsidiaries to incur additional indebtedness; pay dividends or make distributions on our stock; purchase or redeem stock or subordinated indebtedness; make investments; create certain liens; enter into agreements that restrict distributions or other payments by restricted subsidiaries to us; enter into transactions with affiliates; sell assets; consolidate or merge with or into other companies or transfer all or substantially of our assets; and create unrestricted subsidiaries. As of December 31, 2020, we were in compliance with all covenants related to the Senior Notes. Revolving Credit Facility In May 2018, we entered into a Fourth Amended and Restated Credit Agreement (the “Restated Credit Agreement”). The Restated Credit Agreement provides for a maximum credit amount of $2.5 billion. The amount we may borrow under the Restated Credit Agreement is subject to certain limitations. As a result of closing the SRC Acquisition, the borrowing base on our revolving credit facility increased to $2.1 billion and we elected to increase the aggregate commitment amount under our revolving credit facility to $1.7 billion. In October 2020, as part of our fall 2020 semi-annual redetermination, the borrowing base was reduced to $1.6 billion, with a corresponding automatic reduction to our elected commitment level of $1.6 billion. As of December 31, 2020 and 2019, availability under our revolving credit facility was $1.4 billion and $1.3 billion, respectively. The revolving credit facility is available for working capital requirements, capital investments, acquisitions, to support letters of credit and for general corporate 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 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 London interbank market (“LIBOR”) for one month plus a premium) or, at our election, a rate equal to LIBOR 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, 2020, the applicable interest margin is 0.75 percent for the alternate base rate option or 1.75 percent for the LIBOR option, and the unused commitment fee is 0.375 percent. Principal payments are generally not required until the revolving credit facility expires in May 2023 unless the borrowing base falls below the outstanding balance. 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 maintenance of minimum current ratio of 1.0:1.0 and not exceed a maximum leverage ratio of 4.0:1.0; (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, 2020, we were in compliance with all the revolving credit facility covenants.

Leases Operating and Financing

Leases Operating and Financing Leases (Notes)	12 Months Ended
	Dec. 31, 2020
Leases [Abstract]
Leases of Lessee Disclosure	NOTE 10 - LEASES We adopted ASU 2016-02, Leases , effective January 1, 2019. We have operating leases for office space and compressors and finance leases for vehicles. Our leases have remaining lease terms ranging from one The following table presents the components of lease costs for the periods indicated: Year Ended December 31, 2020 2019 (in thousands) Operating lease costs (1) $ 7,983 $ 4,917 Finance lease costs: Amortization of ROU assets 1,812 1,961 Interest on lease liabilities 179 252 Total finance lease costs 1,991 2,213 Short-term lease costs 193,756 170,064 Total lease costs $ 203,730 $ 177,194 _______________ (1) The majority of our operating leases relate to the operation or completion of our wells. Therefore, the lease costs presented in the table above represent the total gross costs the Company incurs, which are not comparable to the Company’s 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 another asset 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: December 31, Consolidated Balance Sheet Line Item 2020 2019 (in thousands) Operating Leases: Operating lease ROU assets Other assets $ 11,722 $ 14,926 Operating lease obligation - short-term Other accrued expenses 6,520 4,159 Operating lease obligation - long-term Other liabilities 9,061 12,944 Total operating lease liabilities $ 15,581 $ 17,103 Finance Leases: Finance lease ROU assets Properties and equipment, net $ 3,189 $ 4,637 Finance lease obligation - short-term Other accrued expenses 1,466 1,767 Finance lease obligation - long-term Other liabilities 1,702 2,835 Total finance lease liabilities $ 3,168 $ 4,602 Weighted-average remaining lease term (years) Operating leases 3.07 4.28 Finance leases 2.58 3.17 Weighted-average discount rate Operating leases 4.8 % 5.0 % Finance leases 4.5 % 5.0 % 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, 2020 consist of the following: Operating Leases Finance Leases Total (in thousands) 2021 $ 7,055 $ 1,557 $ 8,612 2022 5,516 933 6,449 2023 1,559 655 2,214 2024 950 139 1,089 2025 950 10 960 Thereafter 748 — 748 Total lease payments 16,778 3,294 20,072 Less: Interest and discount (1,197) (126) (1,323) Present value of lease liabilities $ 15,581 $ 3,168 $ 18,749

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2020
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: Year Ended December 31, 2020 2019 (in thousands) Beginning balance $ 127,251 $ 115,021 Obligations incurred with development activities and other 6,494 4,605 Obligations incurred with acquisition 47,673 2,882 Accretion expense 10,072 6,117 Revisions in estimated cash flows 4,742 28,991 Obligations discharged with asset retirements (28,888) (23,426) Obligations discharged with divestitures (774) (6,939) Balance at December 31 166,570 127,251 Current portion (33,933) (32,200) Long-term portion $ 132,637 $ 95,051 Our estimated asset retirement obligations liability is based on historical experience in plugging and abandoning wells, estimated economic lives and estimated plugging, abandonment and surface reclamation costs considering federal and state regulatory requirements in effect at that time. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations liability, a corresponding adjustment is made to the properties and equipment balance. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as accretion expense. Short-term asset retirement obligations are included in other accrued expenses in our consolidated balance sheets. The revisions in estimated cash flows for 2019 were primarily due to increases in the estimated surface reclamation costs to obtain final well pad reclamation approval from the applicable regulatory agencies.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies Disclosure	NOTE 12 - COMMITMENTS AND CONTINGENCIES The following table presents gross volume information related to our long-term firm transportation, sales and processing agreements for pipeline capacity and water delivery and disposal commitments: Year Ending December 31, Area 2021 2022 2023 2024 2025 Thereafter Total Expiration Natural gas (MMcf) Wattenberg Field 64,014 64,014 64,014 64,189 52,045 18,779 327,055 August 31, 2026 Delaware Basin 31,025 9,125 9,125 9,150 9,125 45,650 113,200 December 31, 2030 Gas Marketing 1,777 1,183 — — — — 2,960 August 31, 2022 Total 96,816 74,322 73,139 73,339 61,170 64,429 443,215 Crude oil (MBbls) Wattenberg Field 17,002 15,330 11,655 9,882 9,855 6,561 70,285 August 31, 2026 Delaware Basin 8,030 8,030 8,030 — — — 24,090 December 31, 2023 Total 25,032 23,360 19,685 9,882 9,855 6,561 94,375 Water (MBbls) Wattenberg Field 6,207 6,207 6,207 6,223 — — 24,844 December 31, 2024 Total 6,207 6,207 6,207 6,223 — — 24,844 Dollar commitment (in thousands) $ 135,435 $ 114,472 $ 95,082 $ 68,175 $ 56,174 $ 47,489 $ 516,827 Firm Transportation and Processing Agreements. We enter into contracts that provide firm transportation and processing on pipeline systems through which we transport or sell crude oil and natural gas. 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. Our consolidated statements of operations reflect our share of these firm transportation and processing costs. These contracts require us to pay these transportation and processing charges whether or not the required volumes are delivered. 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. Facilities Expansion Agreements. We entered into two facilities expansion agreements with our primary midstream provider to expand and improve its natural gas gathering pipelines and processing facilities in the Wattenberg Field. The midstream provider completed and turned on line the first of the two 200 MMcfd cryogenic plants in August 2018 and the second plant was completed in August 2019. We are bound to the volume requirements in these agreements on the first day of the calendar month following the actual in-service date of the relevant plant. Both agreements require baseline volume commitments, consisting of our gross wellhead volume delivered in November 2016 to this midstream provider, and incremental wellhead volume commitments of 51.75 MMcfd and 33.5 MMcfd for the first and second agreements, respectively, for seven years. In addition, as a result of the SRC Acquisition, we are subject to substantially similar facilities expansion agreements with the same primary midstream provider of 46.4 MMcfd and 43.8 MMcfd, respectively. We may be required to pay shortfall fees for any volumes under 98.2 MMcfd and 77.3 MMcfd incremental commitments. Any shortfall in these volume commitments may be offset by other producers' volumes sold to the midstream provider that are greater than a certain total baseline volume. We are also required for the first three years of the contracts to guarantee a certain target profit margin to the midstream provider on these incremental volumes. The actual shortfall in target profit margin incurred, which we guaranteed to our midstream provider, was included as part of contract assets as part of Other assets on the consolidated balance sheets. Firm sales agreement . In May 2018, we entered into a firm sales agreement that is effective from June 2018 through December 2023 with an integrated marketing company for our crude oil production in the Delaware Basin. Contracted volumes are currently 24,000 barrels of crude oil per day and decrease over time to 22,000 barrels per day. 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. Crude Oil, Natural Gas and NGLs Sales . For the years ended December 31, 2020 and 2019, amounts related to long-term transportation volumes, net to our interest, in the table above were $22.2 million and $50.1 million, respectively, and were netted against our crude oil and natural gas sales. In addition, amounts related to long-term transportation volumes recorded in transportation, gathering and processing expenses amounted to $15.7 million and $1.9 million for the years ended December 31, 2020 and 2019, respectively. 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. Environmental. Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to minimize and mitigate the risks from environmental contamination. We conduct periodic reviews and simulated drills to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. Except as discussed herein, we are not aware of any material environmental claims existing as of December 31, 2020 which have not been provided for or would otherwise have a material impact on our financial statements; however, there can be no assurance that current regulatory requirements will not change or that unknown potential past non-compliance with environmental laws or other environmental liabilities will not be discovered on our properties. Accrued environmental liabilities are recorded in other accrued expenses in the consolidated balance sheets. In recent years, we have been executing a program to plug and abandon certain of our older vertical wells in the Wattenberg Field. A self-audit of final reclamation activities associated with site retirements, which we concluded in 2019, identified deficiencies, including incomplete documentation and agency submittals, inadequate plant growth and incomplete earthwork. In December 2019, we formally disclosed these deficiencies to the Colorado Oil and Gas Conservation Commission ("COGCC") and are working to close this backlog of site reclamation work. On August 19, 2020, COGCC issued to PDC a Notice of Alleged Violation ("NOAV") citing a failure to comply with reclamation requirements at multiple locations. During 2020, we similarly assessed and identified deficiencies in reclamation activities at sites acquired through the SRC Acquisition. We do not believe potential penalties and other expenditures associated with the deficiencies disclosed to the COGCC and the resulting NOAV, nor any potential future disclosure of deficiencies associated with reclamation of sites acquired in the SRC Acquisition, will have a material effect on our financial condition or results of operations, but they may exceed $300,000. As part of our integration activities over the facilities acquired through the SRC Acquisition, we are in the process of conducting a comprehensive air quality compliance audit. We do not believe potential penalties and other expenditures associated with deficiencies identified through the audit will have a material effect on our financial condition or results of operations, but they may exceed $300,000. Clean Air Act Agreement and Related Consent Decree. In June 2017, following our receipt of a 2015 Clean Air Act information request from the EPA and a 2015 compliance advisory from the Colorado Department of Public Health and Environment's (“CDPHE”) Air Pollution Control Division, the U.S. Department of Justice, on behalf of the EPA and the state of Colorado, filed a complaint against us in the U.S. District Court for the District of Colorado, claiming that we failed to operate and maintain certain condensate collection facilities at 65 facilities so as to minimize leakage of volatile organic compounds in compliance with applicable law. In October 2017, we entered into a consent decree to resolve the lawsuit and the compliance advisory. Pursuant to the consent decree, we agreed to implement a variety of operational enhancements and environmental mitigations and similar projects, including vapor control system modifications and verification, increased inspection and monitoring and installation of tank pressure monitors. While many of those actions are complete, some requirements will continue until the consent decree is terminated. In addition, as a result of the SRC Acquisition, we are subject to the obligations and requirements of a 2018 Compliance Order on Consent ("COC") entered into by SRC with CDPHE, applicable to certain SRC oil and gas production facilities. The CDPHE revised the COC to make the inspection and monitoring requirements, among others, consistent with those contained in our consent decree. Since the consent decree took effect, and more recently was expanded to include the COC, we have timely implemented the various programs that meet its requirements. Over the course of this execution, we have identified certain immaterial deficiencies in our implementation of the programs. We report these immaterial deficiencies to the appropriate authorities and remediate them promptly. We do not believe that the penalties and expenditures associated with the consent decree, including any sanctions associated with these deficiencies, will have a material effect on our financial condition or results of operations, but they may exceed $300,000. Further, we could be the subject of other enforcement actions by regulatory authorities in the future relating to our past, present or future operations.

COMMON STOCK

COMMON STOCK	12 Months Ended
	Dec. 31, 2020
Equity [Abstract]
Share-based Payment Arrangement	NOTE 13 - COMMON STOCK Stock-Based Compensation Plans 2018 Equity Incentive Plan . In May 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”) from 1,800,000 to 7,050,000. The 2018 Plan was approved in May 2018 and expires in March 2028. The capital stock available for issuance under the 2018 Plan shall be 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, the shares are not deemed to have been delivered under the 2018 Plan and remain available for issuance. Any shares withheld for taxes cannot be recycled under this plan. Awards may be issued in the form of 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 the board of directors (the "Compensation Committee"), with a minimum one-year vesting period applicable to most awards. With regard to SARs and options, awards have a maximum exercisable period of ten years. As of December 31, 2020, there were 5,204,837 shares available for grant under the 2018 Plan. 2010 Long-Term Equity Compensation Plan . Our Amended and Restated 2010 Long-Term Equity Compensation Plan, which was approved by stockholders 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, 2020, there were 189,154 shares available for grant under the 2010 Plan. 2015 SRC Equity Incentive Plan . Pursuant to the closing of the SRC Acquisition, SRC granted 155,928 PSUs to certain SRC executives under the 2015 SRC Equity Incentive Plan (the “2015 SRC Plan”). These PSUs (the “SRC PSUs”) were granted prior to the consummation of the merger, were assumed and converted into PDC PSUs at a rate of 0.158 per share and remain subject to the same terms and conditions (including performance-vesting terms) that applied immediately prior to the closing of the SRC Acquisition. The PSUs will result in a payout between zero and 200 percent of the target PSUs awarded. As of December 31, 2020, there were no shares available for grant under the 2015 SRC Plan. 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, Stock-based compensation expense included in: 2020 2019 2018 (in thousands) General and administrative expense $ 21,182 $ 22,754 $ 20,848 Lease operating expenses 1,018 1,083 934 Total stock-based compensation expense $ 22,200 $ 23,837 $ 21,782 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 for these time-based RSUs is based on the market price of our common stock on the grant date and are 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, including executive officers, during the year ended December 31, 2020: Shares Weighted-Average Grant Date Fair Value per Share Non-vested at December 31, 2019 795,926 $ 45.51 Granted 1,203,108 11.98 Vested (534,610) 38.08 Forfeited (313,454) 22.62 Non-vested at December 31, 2020 1,150,970 20.14 The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: As of/Year Ended December 31, 2020 2019 2018 (in thousands, except per share data) Total intrinsic value of time-based awards vested $ 7,312 $ 11,652 $ 12,282 Total intrinsic value of time-based awards non-vested 23,629 20,829 18,404 Market price per share as of December 31, 20.53 26.17 29.76 Weighted-average grant date fair value per share 11.98 40.34 50.69 Total compensation cost related to non-vested time-based awards and not yet recognized in our consolidated statements of operations as of December 31, 2020 was $13.0 million. This cost is expected to be recognized over a weighted-average period of 1.8 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 368,077 market-based PSUs to our executive officers during 2020. 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, 2022, 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. 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, 2020 2019 2018 Expected term of award (in years) 3 3 3 Risk-free interest rate 1.4 % 2.5 % 2.4 % Expected volatility 46.6 % 41.4 % 42.3 % Weighted-average grant date fair value per share $ 33.52 $ 56.68 $ 69.98 SRC Performance Stock Units. The terms of the SRC PSUs are substantially the same as those of the PDC PSUs, except that the SRC PSUs do not require continuous employment and the performance period associated with the awards of January 1, 2019 through December 31, 2021 predates the grant date . The fair value of the SRC PSU awards was determined on the grant date of January 13, 2020 using the Monte Carlo pricing model using the following assumptions: Year Ended December 31, 2020 Expected term of awards (in years) 2 Risk-free interest rate 1.6 % Expected volatility 56.9 % Weighted-average grant date fair value per share $ 33.35 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, including SRC PSUs, during the year ended December 31, 2020: Shares Weighted-Average Grant Date Fair Value per Share Non-vested at December 31, 2019 221,142 $ 61.61 Granted 524,005 30.29 Vested (156,003) 38.59 Forfeited (89,597) 46.43 Non-vested at December 31, 2020 499,547 38.66 The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: As of/Year Ended December 31, 2020 2019 2018 (in thousands, except per share data) Total intrinsic value of market-based awards vested $ 1,736 $ 530 $ 620 Total intrinsic value of market-based awards non-vested 10,256 5,787 3,063 Market price per share as of December 31, 20.53 26.17 29.76 Weighted-average grant date fair value per share 30.29 56.68 69.98 Total compensation cost related to non-vested market-based awards not yet recognized in our consolidated statements of operations as of December 31, 2020 was $7.6 million. This cost is expected to be recognized over a weighted-average period of 1.7 years. Stock Appreciation Rights The SARs vest ratably over a three-year period and may generally be exercised at any point after vesting through ten years from the date of issuance. Pursuant to the terms of the awards, upon exercise, the executive officers will receive, in shares of common stock, the excess of the market price of the award on the date of exercise over the market price of the award on the date of issuance. All outstanding SARs as of December 31, 2020 have vested and the related compensation cost has been fully recognized. As of December 31, 2020, there were 210,675 SARs outstanding and exercisable which have a weighted-average exercise price of $49.45 and average remaining contractual term of 3.3 years. Outstanding and exercisable SARs have no intrinsic value as of December 31, 2020. 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 the board of directors from time to time. Through December 31, 2020, no shares of preferred stock have been issued. Stock Repurchase Program

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2020
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 years presented: Year Ended December 31, 2020 2019 2018 (in thousands) Current: Federal $ 1,592 $ 1,366 $ 887 State (220) (300) (188) Total current income tax benefit 1,372 1,066 699 Deferred: Federal 5,460 4,507 (1,986) State 1,070 (2,251) (4,119) Total deferred income tax (expense) benefit 6,530 2,256 (6,105) Income tax (expense) benefit $ 7,902 $ 3,322 $ (5,406) The following table presents a reconciliation of the federal statutory rate to the effective tax rate related to our (expense) benefit for income taxes: Year Ended December 31, 2020 2019 2018 Federal statutory tax rate 21.0 % 21.0 % 21.0 % State income tax, net 3.0 3.6 (6.4) Federal tax credits — (3.3) (52.1) Effect of state income tax rate changes 0.2 (6.4) 6.7 Change in valuation allowance (22.1) (0.6) 45.5 Non-deductible compensation (0.6) (5.0) 21.8 Non-deductible acquisition costs (0.1) (2.3) — Non-deductible government relations (0.1) (1.0) 31.8 Other non-deductible items — (0.5) 4.9 Other (0.2) — (0.4) Effective tax rate 1.1 % 5.5 % 72.8 % The effective income tax rates for 2020 and 2019 were 1.1 percent and 5.5 percent on the respective pre-tax losses. The effective tax rate of 1.1 percent for 2020 differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 21 percent to the pre-tax loss due to the full valuation allowance in effect at December 31, 2020. The effective tax rate of 5.5 percent for 2019 differs from the statutory U.S. federal income tax rate of 21 percent due to state income taxes, non-deductible lobbying expenses, stock-based compensation and nondeductible officers’ compensation. 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, 2020 2019 (in thousands) Deferred tax assets: Deferred compensation $ 10,472 $ 9,905 Asset retirement obligations 39,371 30,993 Federal NOL carryforward 97,880 22,965 State NOL and tax credit carryforwards, net 21,034 9,508 Federal tax - credit carryforwards 3,059 4,448 Net change in fair value of unsettled commodity derivatives 18,351 — Prepaid revenue 4,364 4,874 Other 5,741 3,887 Valuation allowance (165,575) (3,775) Total gross deferred tax assets 34,697 82,805 Deferred tax liabilities: Properties and equipment 33,183 268,234 Net change in fair value of unsettled commodity derivatives — 6,841 Convertible debt 1,514 3,571 Total gross deferred tax liabilities 34,697 278,646 Net deferred tax liability $ — $ 195,841 The ultimate realization of deferred tax assets 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 scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies and projected future taxable income in making this assessment. As previously noted, we recorded impairments totaling $882.4 million in 2020. These impairments resulted in three years of cumulative historical pre-tax losses and a net deferred tax asset position. The impairment losses were a key consideration that led us to continue to provide a valuation allowance against our net deferred tax assets as of December 31, 2020 since we cannot conclude that it is more likely than not that our net deferred tax asset will be fully realized in future periods. As a result, we recorded a $7.9 million benefit in 2020 to increase our deferred tax valuation allowance to $165.6 million and reduce the carrying value of our deferred tax assets to zero. As of December 31, 2020, we have estimated net operating loss carryfowards ("NOLs") for federal income tax purposes of $466 million, of which $304 million was generated before January 1, 2018 and is not subject to the 80 percent limitation of taxable income. Such NOLs will expire beginning 2033. In 2016, we acquired a federal NOL of $60.1 million as a component of our acquisition in the Delaware Basin that will begin to expire in 2033. Also, we acquired a federal NOL of $232.5 million as component of the SRC Acquisition that will begin to expire in 2037. The federal NOLs acquired as part of our acquisition in the Delaware Basin and the SRC Acquisition are subject to an annual limitation of $15.1 million and $16.1 million, respectively, as both acquisitions constitute a change of ownership as defined under Internal Revenue Service ("IRS") Code Section 382. As of December 31, 2020, we have state NOL carryforwards of $494.8 million that begin to expire in 2029 and state credit carryforwards of $3.7 million that begin to expire in 2022. Unrecognized tax benefits and related accrued interest and penalties were immaterial for the three-year period ended December 31, 2020. The statutes of limitations for most of our state tax jurisdictions are open for tax year 2017 forward. As of December 31, 2020, there is no liability for unrecognized income tax benefits. We are subject to the following material taxing jurisdictions: U.S., Colorado, West Virginia, and Texas. As of December 31, 2020, we are current with our income tax filings in all applicable state jurisdictions and are not currently under

Earnings per share

Earnings per share	12 Months Ended
	Dec. 31, 2020
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 equity-based employee awards, convertible notes 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, 2020 2019 2018 (in thousands) Weighted-average common shares outstanding - basic 98,251 64,032 66,059 Dilutive effect of: RSUs and PSUs — — 173 Other equity-based awards — — 71 Weighted-average common shares and equivalents outstanding - diluted 98,251 64,032 66,303 We reported a net loss for the years ended December 31, 2020 and 2019. As a result, our basic and diluted weighted-average common shares outstanding were the same for those periods because the effect of the common share equivalents was 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, 2020 2019 2018 (in thousands) Weighted-average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect: RSUs and PSUs 1,707 989 145 Other equity-based awards 229 302 109 Total anti-dilutive common share equivalents 1,936 1,291 254 The 2021 Convertible Notes give the holders, at our election, the right to convert the aggregate principal amount into 2.3 million shares of our common stock at a conversion price of $85.39 per share. The 2021 Convertible Notes were not included in the diluted earnings per share calculation using the treasury stock method for any periods presented as the average market price of our common stock did not exceed the conversion price.

Supplemental Cash Flow Suppleme

Supplemental Cash Flow Supplemental Cash Flow (Notes)	12 Months Ended
	Dec. 31, 2020
Supplemental Cash Flow Elements [Abstract]
Cash Flow, Supplemental Disclosures [Text Block]	NOTE 16 - SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION Year Ended December 31, 2020 2019 2018 (1) (in thousands) Supplemental cash flow information: Cash payments (receipts) for: Interest, net of capitalized interest $ 75,506 $ 57,439 $ 55,586 Income taxes 9 (1,167) (6,719) Non-cash investing and financing activities: Issuance of common stock for acquisition of crude oil and natural gas properties, net 1,009,015 — — Change in accounts payable related to capital expenditures (28,676) (68,246) 36,328 Change in asset retirement obligations, with a corresponding change to crude oil and natural gas properties, net of disposals 54,984 29,533 37,136 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 9,246 $ 5,301 $ — Operating cash flows from finance leases 156 253 — ROU assets obtained in exchange for lease obligations: Operating leases $ 4,305 $ 1,428 $ — Finance leases 703 2,323 — ____________

Organization, Consolidation and

Organization, Consolidation and Presentation of Financial Statements (Policies)	12 Months Ended
	Dec. 31, 2020
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 upon consolidation.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2020
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 in 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 computing impairment test limitations; 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, 2020 and 2019. 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, changes in the fair value of our derivative instruments are recorded 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]	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, 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. 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. Annually, or 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 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 pipelines, vehicles, facilities, office furniture and equipment, buildings and computer hardware and software 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. Total depreciation expense related to other property and equipment was $8.7 million, $5.7 million and $8.5 million for the year ended December 31, 2020, 2019 and 2018, 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. Interest costs are capitalized as part of the historical cost of acquiring assets. Investments in unproved crude oil and natural gas properties and major development projects, on which DD&A expense is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready to be placed into service. Capitalized interest is calculated by multiplying our weighted-average interest rate on our outstanding debt by the qualifying costs. Interest capitalized may not exceed gross interest expense for the period. As the qualifying asset is placed into service, we begin amortizing the related capitalized interest over the useful life of the asset. Capitalized interest totaled $19.7 million, $13.4 million and $9.2 million during the year ended December 31, 2020, 2019 and 2018, respectively.
Assets Held For Sale, Policy [Policy Text Block]	Assets Held-for-Sale.
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. The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The 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. The Company's 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 (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. 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 crude oil, natural gas or NGLs 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, 2020, 2019 and 2018, 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 the crude oil, natural gas or NGLs has been transferred to the purchasers of these commodities 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, the Company has utilized the practical expedient in ASC Topic 606 which states the Company is 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 of non-producing interests and unproved mineral leases 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.
New Accounting Pronouncement, Early Adoption [Table Text Block]	Recently Adopted Accounting Pronouncement In March 2020, the SEC adopted final rules that amend the financial disclosure requirements for subsidiary issuers and guarantors of registered debt securities in Rule 3-10 of Regulation S-X. The amended rules, which can be found under new Rule 13-01 of Regulation S-X, narrow the circumstances that require separate financial statements of subsidiary issuers and guarantors and streamline the alternative disclosures required in lieu of those statements. The amended rules allow registrants, among other things, to disclose summarized financial information of the issuer and guarantors on a combined basis and to present only the most recently completed fiscal year and subsequent year-to-date interim period. The rule replaces the requirement to provide condensed consolidating financial information with a requirement to present summarized financial information of the issuers and guarantors. These disclosures may be included in the notes to the consolidated financial statements or can be disclosed outside the notes to the consolidated financial statements (i.e. management's discussion and analysis section). The rule is effective in the first quarter of 2021, with earlier adoption permitted. We early adopted the rule in the first quarter of 2020 and have provided these disclosures outside the notes to the condensed consolidated financial statements. In October 2020, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2020-09, Amendments to SEC Paragraphs Pursuant to SEC Release No. 33-10762 , to align the standards under Accounting Standard Codification 470, Debt

Business Combination Purchase P

Business Combination Purchase Price Transaction Details (Tables)	12 Months Ended
	Dec. 31, 2020
Business Combination, Separately Recognized Transactions [Line Items]
Business Acquisition, Pro Forma Information	Year Ended December 31, 2020 2019 (in thousands, except per share data) Total revenue $ 1,361,051 $ 1,761,498 Net income (loss) (695,663) 139,578 Earnings (loss) per share: Basic $ (6.97) $ 1.36 Diluted (6.97) 1.35
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	(in thousands) Consideration: Cash $ 40 Retirement of seller's credit facility 166,238 Total cash consideration 166,278 Common stock issued 1,009,015 Shares withheld in lieu of taxes 6,299 Total consideration $ 1,181,592 Recognized amounts of identifiable assets acquired and liabilities assumed: Assets acquired: Current assets $ 145,792 Properties and equipment, net - proved 1,613,674 Properties and equipment, net - unproved 109,615 Properties and equipment, net - other 16,242 Deferred tax asset 189,311 Other assets 11,810 Total assets acquired $ 2,086,444 Liabilities assumed: Current liabilities $ (253,967) Senior notes (555,500) Asset retirement obligations (42,417) Other liabilities (52,968) Total liabilities assumed (904,852) Total identifiable net assets acquired $ 1,181,592

Revenue Recognition Revenue R_2

Revenue Recognition Revenue Recognition (Tables)	12 Months Ended
	Dec. 31, 2020
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 2020 2019 2018 (in thousands) Crude oil Wattenberg Field $ 668,948 $ 767,760 $ 783,158 Delaware Basin 147,902 252,929 252,107 Utica Shale (1) — — 2,696 Total 816,850 1,020,689 1,037,961 Natural gas Wattenberg Field 171,755 137,143 130,073 Delaware Basin 6,997 13,877 32,010 Utica Shale (1) — — 1,109 Total 178,752 151,020 163,192 NGLs Wattenberg Field 128,126 94,347 132,820 Delaware Basin 28,827 41,219 55,148 Utica Shale (1) — — 840 Total 156,953 135,566 188,808 Revenue by Operating Region Wattenberg Field 968,829 999,250 1,046,051 Delaware Basin 183,726 308,025 339,265 Utica Shale (1) — — 4,645 Total $ 1,152,555 $ 1,307,275 $ 1,389,961 ____________
Contract with Customer, Asset and Liability	December 31, 2020 2019 (in thousands) Beginning balance $ 11,494 $ 11,144 Additions 16,739 443 Amortized as a reduction to crude oil, natural gas and NGLs sales (2,361) (93) Ending balance $ 25,872 $ 11,494

Fair Value of Financial Instrum

Fair Value of Financial Instruments Fair Value Measurements and Disclosures (Tables)	12 Months Ended
	Dec. 31, 2020
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 periods presented: December 31, 2020 2019 Significant Other Significant Total Significant Other Significant Total (in thousands) Total assets $ 36,895 $ 21,539 $ 58,434 $ 22,886 $ 8,938 $ 31,824 Total liabilities (104,545) (29,966) (134,511) (3,089) (524) (3,613) Net derivative instruments $ (67,650) $ (8,427) $ (76,077) $ 19,797 $ 8,414 $ 28,211
Fair Value Assets and Liabilities Unobservable Input Reconciliation [Table Text Block]	The following table presents a reconciliation of our Level 3 assets and liabilities measured at fair value: Year Ended December 31, 2020 2019 2018 (in thousands) Fair value of Level 3 instruments, net asset (liability) beginning of period $ 8,414 $ 58,329 $ (9,687) Changes in fair value included in consolidated statements of operations line item: Commodity price risk management gain (loss), net 37,821 (41,749) 63,257 Settlements included in consolidated statements of operations line items: Commodity price risk management gain (loss), net (54,662) (8,166) 4,759 Fair value of Level 3 instruments, net asset (liability) end of period $ (8,427) $ 8,414 $ 58,329 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 $ — $ (22,694) $ — Total $ — $ (22,694) $ —
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 not elected 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 and convertible notes as of the dates indicated: December 31, 2020 2019 Estimated Fair Value Percent of Par Estimated Fair Value Percent of Par (in millions) Senior notes: 2021 Convertible Notes $ 196.2 98.1 % $ 188.6 94.3 % 2024 Senior Notes 410.8 102.7 % 409.2 102.3 % 2025 Senior Notes 102.8 100.5 % — — % 2026 Senior Notes 775.5 103.4 % 599.4 99.9 %

Derivative Financial Instrume_2

Derivative Financial Instruments Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2020
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block]	As of December 31, 2020, we had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted-average contract price is shown. Collars Fixed-Price Exchanges 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, 2020 (1) (in thousands) Floors Ceilings Crude Oil NYMEX 2021 4,008 $ 38.76 $ 50.05 10,176 $ 47.01 $ (20,341) 2022 900 40.00 52.05 4,884 41.18 (26,440) Total Crude Oil 4,908 15,060 (46,781) Natural Gas NYMEX 2021 62,625 2.46 2.86 31,800 2.40 (9,169) 2022 17,400 2.50 2.89 8,700 2.62 1,325 Total Natural Gas 80,025 40,500 (7,844) Basis Protection - Natural Gas CIG 2021 — — — 94,425 (0.46) (19,773) 2022 — — — 26,100 (0.34) (1,679) Total Basis Protection - Natural Gas — 120,525 (21,452) Commodity Derivatives Fair Value $ (76,077)
Derivatives Not Designated as Hedging Instruments [Table Text Block]	The following table reflects the impact of netting agreements on gross derivative assets and liabilities: As of December 31, 2020 Total Gross Amount Presented on Balance Sheet Effect of Master Netting Agreements Total Net Amount (in thousands) Derivative assets: Derivative instruments, at fair value $ 58,434 $ (39,691) $ 18,743 Derivative liabilities: Derivative instruments, at fair value $ 134,511 $ (39,691) $ 94,820 As of December 31, 2019 Total Gross Amount Presented on Balance Sheet Effect of Master Netting Agreements Total Net Amount (in thousands) Derivative assets: Derivative instruments, at fair value $ 31,824 $ (2,619) $ 29,205 Derivative liabilities: Derivative instruments, at fair value $ 3,613 $ (2,619) $ 994
Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location	The following table presents the consolidated balance sheet line item and fair value amounts of our derivative instruments as of the dates indicated: December 31, Consolidated Balance Sheet Line Item 2020 2019 (in thousands) Derivative assets: Current Commodity derivative contracts Fair value of derivatives $ 48,869 $ 27,766 Basis protection derivative contracts Fair value of derivatives — 312 48,869 28,078 Non-current Commodity derivative contracts Fair value of derivatives 9,565 3,746 Total derivative assets $ 58,434 $ 31,824 Derivative liabilities: Current Commodity derivative contracts Fair value of derivatives $ 78,379 $ 529 Basis protection derivative contracts Fair value of derivatives 19,773 2,392 98,152 2,921 Non-current Commodity derivative contracts Fair value of derivatives 34,680 692 Basis protection derivative contracts Fair value of derivatives 1,679 — Total derivative liabilities $ 134,511 $ 3,613

Properties and Equipment (Table

Properties and Equipment (Tables)	12 Months Ended
	Dec. 31, 2020
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 DD&A, as of the dates indicated: December 31, 2020 2019 (in thousands) Properties and equipment, net: Crude oil and natural gas properties Proved $ 7,523,639 $ 6,241,780 Unproved 350,677 403,379 Total crude oil and natural gas properties 7,874,316 6,645,159 Infrastructure and other 65,027 41,888 Land and buildings 24,299 12,312 Construction in progress 523,550 408,428 Properties and equipment, at cost 8,487,192 7,107,787 Accumulated DD&A (3,627,993) (3,012,585) Properties and equipment, net $ 4,859,199 $ 4,095,202
Impairment of natural gas and crude oil properties [Table Text Block]	The following table presents impairment charges recorded for properties and equipment: Year Ended December 31, 2020 2019 2018 (in thousands) Impairment of proved and unproved properties $ 881,238 $ 10,599 $ 458,397 Impairment of infrastructure and other 1,155 27,937 — Total impairment of properties and equipment $ 882,393 $ 38,536 $ 458,397
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block]	Exploration Expenses. The following table presents the major components of exploration, geologic and geophysical expense: Year Ended December 31, 2020 2019 2018 (in thousands) Geological and geophysical costs, including seismic purchases $ 253 $ 3,017 $ 3,401 Exploratory dry hole costs — — 113 Operating, personnel and other 1,123 1,037 2,690 Total exploration, geologic and geophysical expense $ 1,376 $ 4,054 $ 6,204
Capitalized Exploratory Well Costs, Roll Forward	The following table presents the capitalized exploratory well cost pending determination of proved reserves and included in properties and equipment as of the dates indicated: December 31, 2020 2019 (in thousands, except for number of wells) Beginning balance $ 16,078 $ 12,188 Additions to capitalized exploratory well costs pending the determination of proved reserves 11,770 31,901 Reclassifications to proved properties (20,389) (28,011) Ending balance $ 7,459 $ 16,078 Number of wells pending determination at period-end 2 4

Accounts Receivable, Other Ac_2

Accounts Receivable, Other Accrued Expenses and Other Liabilities (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020 2019 (in thousands) Crude oil, natural gas and NGLs sales $ 178,147 $ 149,758 Joint interest billings 50,329 29,510 Midstream asset divestitures deferred payments — 81,702 Other 22,538 12,860 Allowance for doubtful accounts (6,763) (7,476) Accounts receivable, net $ 244,251 $ 266,354
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, 2020 2019 (in thousands) Employee benefits $ 23,304 $ 21,611 Asset retirement obligations 33,933 32,200 Environmental expenses 10,139 2,256 Operating and finance leases 7,986 5,926 Other 6,353 8,469 Other accrued expenses $ 81,715 $ 70,462 Other Liabilities. The following table presents the components of other liabilities as of the dates indicated: December 31, 2020 2019 (in thousands) Deferred midstream gathering credits $ 168,478 $ 175,897 Deferred oil gathering credits 18,090 20,100 Production taxes 65,592 68,020 Operating and finance leases 10,763 15,779 Other 1,111 3,337 Other liabilities $ 264,034 $ 283,133 Deferred Midstream Gathering Credits. In the second quarter of 2019, concurrent with the sale of our Delaware Basin midstream assets, we entered into an agreement with the purchasers that dedicated the gathering of certain 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. Deferred Oil Gathering Credits. In 2018, we entered into an agreement that dedicates crude oil from the majority of our Wattenberg Field acreage to the midstream provider's gathering lines and extends the term of the agreement through December 2029. The acreage dedication agreement resulted in an initial cash receipt and is being amortized over the life of the agreement. 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, 2020 2019 (in thousands) Crude oil, natural gas and NGL sales $ 1,013 $ 439 Transportation, gathering and processing expenses 5,618 3,659 Lease operating expenses 2,015 935
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, 2020 2019 (in thousands) Crude oil, natural gas and NGL sales $ 1,013 $ 439 Transportation, gathering and processing expenses 5,618 3,659 Lease operating expenses 2,015 935

Long-Term Debt LONG-TERM DEBT (

Long-Term Debt LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
Schedule of Long-term Debt Instruments [Table Text Block]	Long-term debt consisted of the following as of the dates indicated: December 31, 2020 2019 (in thousands) Senior Notes: 1.125% Convertible Notes due September 2021: Principal amount $ 200,000 $ 200,000 Unamortized discount (6,295) (14,763) Unamortized debt issuance costs (691) (1,666) Net of unamortized discount and debt issuance costs 193,014 183,571 6.125% Senior Notes due September 2024: Principal amount 400,000 400,000 Unamortized debt issuance costs (3,632) (4,611) Net of unamortized debt issuance costs 396,368 395,389 6.25% Senior Notes due December 2025: Principal amount 102,324 — Unamortized premium 880 — Net of unamortized premium 103,204 — 5.75% Senior Notes due May 2026: Principal amount 750,000 600,000 Unamortized discount (1,429) — Unamortized debt issuance costs (6,595) (5,734) Net of unamortized discount and debt issuance costs 741,976 594,266 Total senior notes 1,434,562 1,173,226 Revolving Credit Facility: Revolving credit facility due May 2023 168,000 4,000 Total debt, net of unamortized discount, premium, and debt issuance costs 1,602,562 1,177,226 Less current portion of long-term debt 193,014 — Total long-term debt $ 1,409,548 $ 1,177,226

Leases Operating and Financin_2

Leases Operating and Financing Leases (Tables)	12 Months Ended
	Dec. 31, 2020
Leases [Abstract]
Lease, Cost [Table Text Block]	The following table presents the components of lease costs for the periods indicated: Year Ended December 31, 2020 2019 (in thousands) Operating lease costs (1) $ 7,983 $ 4,917 Finance lease costs: Amortization of ROU assets 1,812 1,961 Interest on lease liabilities 179 252 Total finance lease costs 1,991 2,213 Short-term lease costs 193,756 170,064 Total lease costs $ 203,730 $ 177,194
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: December 31, Consolidated Balance Sheet Line Item 2020 2019 (in thousands) Operating Leases: Operating lease ROU assets Other assets $ 11,722 $ 14,926 Operating lease obligation - short-term Other accrued expenses 6,520 4,159 Operating lease obligation - long-term Other liabilities 9,061 12,944 Total operating lease liabilities $ 15,581 $ 17,103 Finance Leases: Finance lease ROU assets Properties and equipment, net $ 3,189 $ 4,637 Finance lease obligation - short-term Other accrued expenses 1,466 1,767 Finance lease obligation - long-term Other liabilities 1,702 2,835 Total finance lease liabilities $ 3,168 $ 4,602 Weighted-average remaining lease term (years) Operating leases 3.07 4.28 Finance leases 2.58 3.17 Weighted-average discount rate Operating leases 4.8 % 5.0 % Finance leases 4.5 % 5.0 %
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, 2020 consist of the following: Operating Leases Finance Leases Total (in thousands) 2021 $ 7,055 $ 1,557 $ 8,612 2022 5,516 933 6,449 2023 1,559 655 2,214 2024 950 139 1,089 2025 950 10 960 Thereafter 748 — 748 Total lease payments 16,778 3,294 20,072 Less: Interest and discount (1,197) (126) (1,323) Present value of lease liabilities $ 15,581 $ 3,168 $ 18,749

Asset Retirement Obligations As

Asset Retirement Obligations Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2020
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: Year Ended December 31, 2020 2019 (in thousands) Beginning balance $ 127,251 $ 115,021 Obligations incurred with development activities and other 6,494 4,605 Obligations incurred with acquisition 47,673 2,882 Accretion expense 10,072 6,117 Revisions in estimated cash flows 4,742 28,991 Obligations discharged with asset retirements (28,888) (23,426) Obligations discharged with divestitures (774) (6,939) Balance at December 31 166,570 127,251 Current portion (33,933) (32,200) Long-term portion $ 132,637 $ 95,051

Commitments and Contingencies C

Commitments and Contingencies Commitments and Contigencies (Tables)	12 Months Ended
	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Supply Commitment	The following table presents gross volume information related to our long-term firm transportation, sales and processing agreements for pipeline capacity and water delivery and disposal commitments: Year Ending December 31, Area 2021 2022 2023 2024 2025 Thereafter Total Expiration Natural gas (MMcf) Wattenberg Field 64,014 64,014 64,014 64,189 52,045 18,779 327,055 August 31, 2026 Delaware Basin 31,025 9,125 9,125 9,150 9,125 45,650 113,200 December 31, 2030 Gas Marketing 1,777 1,183 — — — — 2,960 August 31, 2022 Total 96,816 74,322 73,139 73,339 61,170 64,429 443,215 Crude oil (MBbls) Wattenberg Field 17,002 15,330 11,655 9,882 9,855 6,561 70,285 August 31, 2026 Delaware Basin 8,030 8,030 8,030 — — — 24,090 December 31, 2023 Total 25,032 23,360 19,685 9,882 9,855 6,561 94,375 Water (MBbls) Wattenberg Field 6,207 6,207 6,207 6,223 — — 24,844 December 31, 2024 Total 6,207 6,207 6,207 6,223 — — 24,844 Dollar commitment (in thousands) $ 135,435 $ 114,472 $ 95,082 $ 68,175 $ 56,174 $ 47,489 $ 516,827

Common Stock Common Stock (Tabl

Common Stock Common Stock (Tables)	12 Months Ended
	Dec. 31, 2020
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, Stock-based compensation expense included in: 2020 2019 2018 (in thousands) General and administrative expense $ 21,182 $ 22,754 $ 20,848 Lease operating expenses 1,018 1,083 934 Total stock-based compensation expense $ 22,200 $ 23,837 $ 21,782
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, including executive officers, during the year ended December 31, 2020: Shares Weighted-Average Grant Date Fair Value per Share Non-vested at December 31, 2019 795,926 $ 45.51 Granted 1,203,108 11.98 Vested (534,610) 38.08 Forfeited (313,454) 22.62 Non-vested at December 31, 2020 1,150,970 20.14 The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: As of/Year Ended December 31, 2020 2019 2018 (in thousands, except per share data) Total intrinsic value of time-based awards vested $ 7,312 $ 11,652 $ 12,282 Total intrinsic value of time-based awards non-vested 23,629 20,829 18,404 Market price per share as of December 31, 20.53 26.17 29.76 Weighted-average grant date fair value per share 11.98 40.34 50.69
Restricted Stock Awards, Market-Based, Valuation assumptions [Table Text Block]	Year Ended December 31, 2020 2019 2018 Expected term of award (in years) 3 3 3 Risk-free interest rate 1.4 % 2.5 % 2.4 % Expected volatility 46.6 % 41.4 % 42.3 % Weighted-average grant date fair value per share $ 33.52 $ 56.68 $ 69.98
Schedule of Nonvested Performance-based Units Activity [Table Text Block]	The following table presents the change in non-vested market-based awards, including SRC PSUs, during the year ended December 31, 2020: Shares Weighted-Average Grant Date Fair Value per Share Non-vested at December 31, 2019 221,142 $ 61.61 Granted 524,005 30.29 Vested (156,003) 38.59 Forfeited (89,597) 46.43 Non-vested at December 31, 2020 499,547 38.66 The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: As of/Year Ended December 31, 2020 2019 2018 (in thousands, except per share data) Total intrinsic value of market-based awards vested $ 1,736 $ 530 $ 620 Total intrinsic value of market-based awards non-vested 10,256 5,787 3,063 Market price per share as of December 31, 20.53 26.17 29.76 Weighted-average grant date fair value per share 30.29 56.68 69.98
Restricted Stock SRC - Market Based Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted Stock Awards, Market-Based, Valuation assumptions [Table Text Block]	The fair value of the SRC PSU awards was determined on the grant date of January 13, 2020 using the Monte Carlo pricing model using the following assumptions: Year Ended December 31, 2020 Expected term of awards (in years) 2 Risk-free interest rate 1.6 % Expected volatility 56.9 % Weighted-average grant date fair value per share $ 33.35

Income Taxes Income Taxes (Tabl

Income Taxes Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2020
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 years presented: Year Ended December 31, 2020 2019 2018 (in thousands) Current: Federal $ 1,592 $ 1,366 $ 887 State (220) (300) (188) Total current income tax benefit 1,372 1,066 699 Deferred: Federal 5,460 4,507 (1,986) State 1,070 (2,251) (4,119) Total deferred income tax (expense) benefit 6,530 2,256 (6,105) Income tax (expense) benefit $ 7,902 $ 3,322 $ (5,406)
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: Year Ended December 31, 2020 2019 2018 Federal statutory tax rate 21.0 % 21.0 % 21.0 % State income tax, net 3.0 3.6 (6.4) Federal tax credits — (3.3) (52.1) Effect of state income tax rate changes 0.2 (6.4) 6.7 Change in valuation allowance (22.1) (0.6) 45.5 Non-deductible compensation (0.6) (5.0) 21.8 Non-deductible acquisition costs (0.1) (2.3) — Non-deductible government relations (0.1) (1.0) 31.8 Other non-deductible items — (0.5) 4.9 Other (0.2) — (0.4) Effective tax rate 1.1 % 5.5 % 72.8 %
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, 2020 2019 (in thousands) Deferred tax assets: Deferred compensation $ 10,472 $ 9,905 Asset retirement obligations 39,371 30,993 Federal NOL carryforward 97,880 22,965 State NOL and tax credit carryforwards, net 21,034 9,508 Federal tax - credit carryforwards 3,059 4,448 Net change in fair value of unsettled commodity derivatives 18,351 — Prepaid revenue 4,364 4,874 Other 5,741 3,887 Valuation allowance (165,575) (3,775) Total gross deferred tax assets 34,697 82,805 Deferred tax liabilities: Properties and equipment 33,183 268,234 Net change in fair value of unsettled commodity derivatives — 6,841 Convertible debt 1,514 3,571 Total gross deferred tax liabilities 34,697 278,646 Net deferred tax liability $ — $ 195,841

Earnings per share (Tables)

Earnings per share (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020 2019 2018 (in thousands) Weighted-average common shares outstanding - basic 98,251 64,032 66,059 Dilutive effect of: RSUs and PSUs — — 173 Other equity-based awards — — 71 Weighted-average common shares and equivalents outstanding - diluted 98,251 64,032 66,303
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, 2020 2019 2018 (in thousands) Weighted-average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect: RSUs and PSUs 1,707 989 145 Other equity-based awards 229 302 109 Total anti-dilutive common share equivalents 1,936 1,291 254

Supplemental Cash Flow Supple_2

Supplemental Cash Flow Supplemental Cash Flow (Tables)	12 Months Ended
	Dec. 31, 2020
Supplemental Cash Flow Elements [Abstract]
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]	Year Ended December 31, 2020 2019 2018 (1) (in thousands) Supplemental cash flow information: Cash payments (receipts) for: Interest, net of capitalized interest $ 75,506 $ 57,439 $ 55,586 Income taxes 9 (1,167) (6,719) Non-cash investing and financing activities: Issuance of common stock for acquisition of crude oil and natural gas properties, net 1,009,015 — — Change in accounts payable related to capital expenditures (28,676) (68,246) 36,328 Change in asset retirement obligations, with a corresponding change to crude oil and natural gas properties, net of disposals 54,984 29,533 37,136 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 9,246 $ 5,301 $ — Operating cash flows from finance leases 156 253 — ROU assets obtained in exchange for lease obligations: Operating leases $ 4,305 $ 1,428 $ — Finance leases 703 2,323 —

Nature of Operations and Basi_2

Nature of Operations and Basis of Presentation Additional Information (Details)	Dec. 31, 2020Wells
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Oil and gas producing wells, gross	3,727

Summary of Significant Accoun_3

Summary of Significant Accounting Policies Detail (Details)	12 Months Ended
	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Significant Accounting Policies [Line Items]
Customers Greater than 10% Trade Receivable	4
Property, Plant and Equipment, Useful Life	35 years
Non-Oil and gas Depreciation, Depletion and Amortization	$ 8,700,000	$ 5,700,000	$ 8,500,000
Capitalized Interest	$ 19,700,000	$ 13,400,000	$ 9,200,000

BUSINESS COMBINATIONS (Details)

BUSINESS COMBINATIONS (Details) $ / shares in Units, $ in Thousands	Jan. 14, 2020USD ($)Rateshares	Dec. 31, 2020USD ($)a$ / shares	Dec. 31, 2019USD ($)$ / shares	Apr. 30, 2019USD ($)
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares	38,900,000
Conversion of Stock, Shares Issued | shares	0.158
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Long-term Debt		$ (555,500)
Stock Repurchase Program, Authorized Amount	$ 525,000			$ 200,000
Business Combination, Consideration Transferred	$ 1,181,592
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets		145,792
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment		16,242
Business Combination Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Assets		189,311
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Assets		11,810
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets		2,086,444
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities		(253,967)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other		(42,417)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities		(52,968)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities		(904,852)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net		1,181,592
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual		320,900
Business Acquisition, Pro Forma Income (Loss) from Continuing Operations, Net of Tax		46,500
Business Acquisition, Pro Forma Revenue		1,361,051	$ 1,761,498
Business Acquisition, Pro Forma Net Income (Loss)		$ (695,663)	$ 139,578
Business Acquisition, Pro Forma Earnings Per Share, Basic | $ / shares		$ (6.97)	$ 1.36
Business Acquisition, Pro Forma Earnings Per Share, Diluted | $ / shares		$ (6.97)	$ 1.35
Purch Price Adj Disc Cash Flow | Rate	1000.00%
Area of Land | a		83,000
Business Combination, Acquisition Related Costs		$ 19,900
SRC and PDC
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs		38,000	$ 15,900
SRC Acquisition [Member]
Business Acquisition [Line Items]
Value of Transaction	$ 1,700,000
Proved [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment		1,613,674
Unproved [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment		$ 109,615
Cash
Business Acquisition [Line Items]
Business Combination, Consideration Transferred	40
Revolving Credit Facility [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred	166,238
Cash and Cash Equivalents
Business Acquisition [Line Items]
Business Combination, Consideration Transferred	166,278
Common Stock [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable	1,009,015
Shares withheld in lieu of taxes [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable	$ 6,299

Revenue Recognition Revenue fro

Revenue Recognition Revenue from Contract with Customer (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 1,152,555	$ 1,307,275	$ 1,389,961

Revenue Recognition Revenue by

Revenue Recognition Revenue by Commodity and Location (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Revenue from Contract with Customer, Excluding Assessed Tax	$ 1,152,555	$ 1,307,275	$ 1,389,961
Natural Gas Liquids
Revenue from Contract with Customer, Excluding Assessed Tax	156,953	135,566	188,808
Natural Gas [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	178,752	151,020	163,192
Crude Oil [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	816,850	1,020,689	1,037,961
Wattenberg Field
Revenue from Contract with Customer, Excluding Assessed Tax	968,829	999,250	1,046,051
Delaware Basin [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	183,726	308,025	339,265
Crude Oil [Member] | Utica Shale [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	0	0	2,696
Crude Oil [Member] | Delaware Basin [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	147,902	252,929	252,107
Crude Oil [Member] | Wattenberg Field
Revenue from Contract with Customer, Excluding Assessed Tax	668,948	767,760	783,158
Natural Gas [Member] | Utica Shale [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	0	0	1,109
Natural Gas [Member] | Delaware Basin/Wattenberg Field [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	6,997	13,877	32,010
Natural Gas [Member] | Wattenberg Field
Revenue from Contract with Customer, Excluding Assessed Tax	171,755	137,143	130,073
Natural Gas Liquids | Utica Shale [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	0	0	840
Natural Gas Liquids | Delaware Basin/Wattenberg Field [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	28,827	41,219	55,148
Natural Gas Liquids | Wattenberg Field
Revenue from Contract with Customer, Excluding Assessed Tax	128,126	94,347	132,820
Utica Shale [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 0	$ 0	$ 4,645

Revenue Recognition Contract As

Revenue Recognition Contract Assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Capitalized Contract Cost [Line Items]
Capitalized Contract Cost, Net	$ 25,872	$ 11,494	$ 11,144
Capitalized Contract Cost, Gross	16,739	443
Capitalized Contract Cost, Amortization	$ (2,361)	$ (93)

Fair Value of Financial Instr_2

Fair Value of Financial Instruments Fair Value Measurements and Disclosures (Details) - USD ($) $ in Thousands	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	$ 58,434	$ 31,824
Derivative Liability, Fair Value, Gross Liability	134,511	3,613
Derivative, Fair Value, Net	(76,077)
Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	58,434	31,824
Derivative Liability, Fair Value, Gross Liability	(134,511)	(3,613)
Derivative, Fair Value, Net	(76,077)	28,211
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	36,895	22,886
Derivative Liability, Fair Value, Gross Liability	(104,545)	(3,089)
Derivative, Fair Value, Net	(67,650)	19,797
Fair Value | Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net Asset Fair Value	(8,427)
Derivative Asset, Fair Value, Gross Asset	21,539	8,938
Derivative Liability, Fair Value, Gross Liability	(29,966)	(524)
Derivative, Fair Value, Net		8,414
1.125% Convertible Senior Notes due 2021 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Notes fair value	$ 196,200	$ 188,600
Senior Notes Percent of Par	98.10%	94.30%
6.125% Senior Notes due 2024 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Notes fair value	$ 410,800	$ 409,200
Senior Notes Percent of Par	102.70%	102.30%
5.75% Senior Notes due 2026 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Notes fair value	$ 775,500	$ 599,400
Senior Notes Percent of Par	103.40%	99.90%
6.25% Senior Notes due 2025 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Notes fair value	$ 102,800
Senior Notes Percent of Par	100.50%

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, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
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	$ (8,427)	$ 8,414	$ 58,329
Changes in unrealized gains (losses) relating to assets (liabilities) still held as of period end, included in statement of operations line item;	0	(22,694)	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		8,414	58,329	$ (9,687)
Commodity Price Risk Management, net | Derivative Financial Instrument Net Assets [Member]
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	37,821	(41,749)	63,257
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Asset, Purchases, Sales, Issues, Settlements	(54,662)	(8,166)	4,759
Changes in unrealized gains (losses) relating to assets (liabilities) still held as of period end, included in statement of operations line item;	$ 0	$ (22,694)	$ 0

Derivative Financial Instrume_3

Derivative Financial Instruments Fair Value of Derivative and Balance Sheet Location (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 58,434	$ 31,824
Derivative Liability, Fair Value, Gross Liability	134,511	3,613
Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	48,869	28,078
Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	98,152	2,921
Commodity Contracts Related to Natural Gas and Crude Oil Sales [Member] | Current Assets [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivatives	48,869	27,766
Commodity Contracts Related to Natural Gas and Crude Oil Sales [Member] | Non Current Assets [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivatives	9,565	3,746
Commodity Contracts Related to Natural Gas and Crude Oil Sales [Member] | Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivatives	78,379	529
Commodity Contracts Related to Natural Gas and Crude Oil Sales [Member] | Non Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivatives	34,680	692
Basis Protection Contracts Related to Natural Gas and Crude Oil Sales [Member] | Current Assets [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivatives	0	312
Basis Protection Contracts Related to Natural Gas and Crude Oil Sales [Member] | Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivatives	19,773	2,392
Basis Protection Contracts Related to Natural Gas and Crude Oil Sales [Member] | Non Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivatives	$ 1,679	$ 0

Derivative Financial Instrume_4

Derivative Financial Instruments Outstanding Derivative Contracts (Details) MMBTU in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2020USD ($)MMBTU$ / UnitMBbls
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ (76,077)
Natural Gas [Member]
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ (7,844)
Natural Gas [Member] | Fixed Price Swaps [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	40,500
Natural Gas [Member] | Collars [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	80,025
Natural Gas [Member] | Basis Protection - CIG [Member]
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ (21,452)
Natural Gas [Member] | Basis Protection Contracts Related to Natural Gas Marketing [Member] | Fixed Price Swaps [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	120,525
Crude Oil [Member]
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ (46,781)
Crude Oil [Member] | Fixed Price Swaps [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MBbls	15,060,000
Crude Oil [Member] | Collars [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MBbls	4,908,000
2022 [Member] | Natural Gas [Member] | Fixed Price Swaps [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	8,700
2022 [Member] | Natural Gas [Member] | Collars [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	17,400
2022 [Member] | Natural Gas [Member] | CME SWAPS MARKETS (NYMEX) [Member]
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ 1,325
2022 [Member] | Natural Gas [Member] | Basis Protection - CIG [Member]
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ (1,679)
2022 [Member] | Natural Gas [Member] | Basis Protection - CIG [Member] | Fixed Price Swaps [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	26,100
2022 [Member] | Crude Oil [Member]
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ (26,440)
2022 [Member] | Crude Oil [Member] | Fixed Price Swaps [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MBbls	4,884,000
2022 [Member] | Crude Oil [Member] | Collars [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MBbls	900,000
2021 [Member] | Natural Gas [Member] | Fixed Price Swaps [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	31,800
2021 [Member] | Natural Gas [Member] | Collars [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	62,625
2021 [Member] | Natural Gas [Member] | CME SWAPS MARKETS (NYMEX) [Member]
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ (9,169)
2021 [Member] | Natural Gas [Member] | Basis Protection - CIG [Member]
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ (19,773)
2021 [Member] | Natural Gas [Member] | Basis Protection - CIG [Member] | Fixed Price Swaps [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	94,425
2021 [Member] | Crude Oil [Member]
Derivative [Line Items]
Derivative, Fair Value, Net | $	$ (20,341)
2021 [Member] | Crude Oil [Member] | Fixed Price Swaps [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MBbls	10,176,000
2021 [Member] | Crude Oil [Member] | Collars [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MBbls	4,008,000
Natural Gas [Member] | 2022 [Member] | Fixed Price Swaps [Member] | CME SWAPS MARKETS (NYMEX) [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	2.62
Natural Gas [Member] | 2022 [Member] | Fixed Price Swaps [Member] | CIG [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	(0.34)
Natural Gas [Member] | 2022 [Member] | Collars [Member] | CME SWAPS MARKETS (NYMEX) [Member]
Derivative [Line Items]
Derivative, Floor Price	2.50
Derivative, Cap Price	2.89
Natural Gas [Member] | 2021 [Member] | Fixed Price Swaps [Member] | CME SWAPS MARKETS (NYMEX) [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	2.40
Natural Gas [Member] | 2021 [Member] | Fixed Price Swaps [Member] | CIG [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	(0.46)
Natural Gas [Member] | 2021 [Member] | Collars [Member] | CME SWAPS MARKETS (NYMEX) [Member]
Derivative [Line Items]
Derivative, Floor Price	2.46
Derivative, Cap Price	2.86
Crude Oil [Member] | 2022 [Member] | Fixed Price Swaps [Member] | CME SWAPS MARKETS (NYMEX) [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	41.18
Crude Oil [Member] | 2022 [Member] | Collars [Member] | CME SWAPS MARKETS (NYMEX) [Member]
Derivative [Line Items]
Derivative, Floor Price	40
Derivative, Cap Price	52.05
Crude Oil [Member] | 2021 [Member] | Fixed Price Swaps [Member] | CME SWAPS MARKETS (NYMEX) [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	47.01
Crude Oil [Member] | 2021 [Member] | Collars [Member] | CME SWAPS MARKETS (NYMEX) [Member]
Derivative [Line Items]
Derivative, Floor Price	38.76
Derivative, Cap Price	50.05

Derivative Financial Instrume_5

Derivative Financial Instruments Impact of Netting Agreements (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	$ 58,434	$ 31,824
Effect of Master netting agreements	39,691	2,619
Derivative Asset, net	18,743	29,205
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	134,511	3,613
Effect of master netting agreements	39,691	2,619
Derivative Liability, net	$ 94,820	$ 994

Derivative Financial Instrume_6

Derivative Financial Instruments Impact of Derivative Instruments on Statement of Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Derivative [Line Items]
Net change in fair value of unsettled derivatives	$ (99,001)	$ (145,246)	$ 260,775
Commodity price risk management gain (loss), net	180,270	(162,844)	145,237
Gain (Loss) on Sale of Derivatives	279,271	(17,598)	(115,538)
Commodity Price Risk Management, net
Derivative [Line Items]
Commodity price risk management gain (loss), net	$ 180,270	$ (162,844)	$ 145,237

Properties and Equipment (Detai

Properties and Equipment (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2020USD ($)Wells	Dec. 31, 2019USD ($)Wells	Dec. 31, 2018USD ($)
Property, Plant and Equipment [Line Items]
Proved Natural Gas and Crude Oil Properties	$ 7,523,639	$ 6,241,780
Unproved Natural Gas and Crude Oil Properties	350,677	403,379
Total Natural Gas and Crude Oil Properties	7,874,316	6,645,159
Equipment and other	65,027	41,888
Land and Buildings	24,299	12,312
Construction in Progress	523,550	408,428
Property and Equipment, at cost	8,487,192	7,107,787
Accumulated DD&A	(3,627,993)	(3,012,585)
Property, Plant and Equipment, Net	4,859,199	4,095,202
Capitalized Exploratory Well Costs	7,459	16,078	$ 12,188
Capitalized Exploratory Well Cost, Additions Pending Determination of Proved Reserves	11,770	31,901
Reclassification to Well, Facilities, and Equipment Based on Determination of Proved Reserves	$ (20,389)	$ (28,011)
Wells to be completed | Wells	2	4

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, 2020	Dec. 31, 2019	Dec. 31, 2018
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		$ 881,238	$ 10,599	$ 458,397
Impairment of Long-Lived Assets to be Disposed of		1,155	27,937	0
Results of Operations, Impairment of Oil and Gas Properties	$ 881,100	$ 882,393	38,536	458,397
Impairment Measurement Input		17.00%
Delaware Basin Assets
Impairment of natural gas and crude oil properties [Line Items]
Impairment of leasehold			10,600	$ 458,400
Midstream Asset Divestitures [Member]
Impairment of natural gas and crude oil properties [Line Items]
Impairment related to midstream facility infrastructure			$ 27,900

Properties and Equipment Explor

Properties and Equipment Exploration (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2020USD ($)Wells	Dec. 31, 2019USD ($)Wells	Dec. 31, 2018USD ($)
Property, Plant and Equipment [Line Items]
Geological and geophysical	$ 253	$ 3,017	$ 3,401
Exploratory operating costs	0	0	113
Other Exploratory costs	1,123	1,037	2,690
Exploration Expense	$ 1,376	$ 4,054	6,204
Oil and Gas, Exploratory Well Drilled, Net Productive, Number | Wells	2
Oil and Gas, Exploratory Well Drilled, Net Nonproductive, Number | Wells		0
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year	$ 7,500
Exploration and Production Equipment [Member]
Property, Plant and Equipment [Line Items]
Exploration Expense	$ 1,376	$ 4,054	$ 6,204

Properties and Equipment Midstr

Properties and Equipment Midstream Asset Divestiture (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Jun. 30, 2020	Dec. 31, 2019
Deferred Midstream and Oil Gathering Credits [Line Items]
Proceeds from Divestiture of Businesses, Net of Cash Divested	$ 82,000
Residual Proceeds Allocated to Acreage Dedication Agreements		$ 179,600
Midstream Asset Divestitures [Member]
Deferred Midstream and Oil Gathering Credits [Line Items]
Proceeds from Sales of Assets, Investing Activities		345,600
Midstream Gas Gathering [Member]
Deferred Midstream and Oil Gathering Credits [Line Items]
Gain (Loss) on Disposition of Assets		$ 34,000

Accounts Receivables (Details)

Accounts Receivables (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Concentration Risk [Line Items]
Midstream Assets Deferred Payments	$ 0	$ 81,702
Accounts Receivable, Allowance for Credit Loss, Current	(6,763)	(7,476)
Accounts receivable, net	$ 244,251	$ 266,354
Customer No. 1
Concentration Risk [Line Items]
Percentage of Revenue	31.00%	20.00%
Customer No. 2
Concentration Risk [Line Items]
Percentage of Revenue	17.00%	17.00%	13.00%
Customer No. 3
Concentration Risk [Line Items]
Percentage of Revenue	16.00%	16.00%
Customer No. 4
Concentration Risk [Line Items]
Percentage of Revenue	13.00%	11.00%
Natural gas, NGLs and crude oil sales
Concentration Risk [Line Items]
Accounts Receivable, before Allowance for Credit Loss	$ 178,147	$ 149,758
Joint interest billing
Concentration Risk [Line Items]
Accounts Receivable, before Allowance for Credit Loss	50,329	29,510
Other Accounts Receivable
Concentration Risk [Line Items]
Accounts Receivable, before Allowance for Credit Loss	$ 22,538	$ 12,860

Other accrued expenses (Details

Other accrued expenses (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Schedule of Other Accrued Expense [Line Items]
Asset Retirement Obligation, Current	$ 33,933	$ 32,200
Other accrued liabilities	81,715	70,462
Current Liabilities [Member]
Schedule of Other Accrued Expense [Line Items]
Accrued Employee Benefits, Current	23,304	21,611
Asset Retirement Obligation, Current	33,933	32,200
Accrued Environmental Loss Contingencies, Current	10,139	2,256
Operating and Finance Lease Liability, Current	7,986	5,926
Other Accrued Liabilities	6,353	8,469
Other accrued liabilities	$ 81,715	$ 70,462

Other liabilities (Details)

Other liabilities (Details) - Non Current Liabilities [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Schedule of Other Liabilities [Line Items]
Deferred Midstream gathering credits	$ 168,478	$ 175,897
Deferred oil gathering credits	18,090	20,100
Production Tax Liability	65,592	68,020
Operating and Finance Lease Liability, Noncurrent	10,763	15,779
Other Accrued Liabilities	1,111	3,337
Other Accrued Liabilities, Noncurrent	$ 264,034	$ 283,133

Other Accrued Expenses Deferred

Other Accrued Expenses Deferred Midstream Gathering Credits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Midstream Oil Gathering [Member]
Deferred Midstream and Oil Gathering Credits [Line Items]
Amortization of Other Deferred Charges	$ 1,013	$ 439
Midstream Water Gathering [Member]
Deferred Midstream and Oil Gathering Credits [Line Items]
Amortization of Other Deferred Charges	2,015	935
Midstream Gas and Oil Gathering Credits
Deferred Midstream and Oil Gathering Credits [Line Items]
Amortization of Other Deferred Charges	$ 5,618	$ 3,659

Long-Term Debt SCHEDULE OF LONG

Long-Term Debt SCHEDULE OF LONG-TERM DEBT (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019	Nov. 14, 2017	Sep. 14, 2016
Debt Instrument [Line Items]
Total senior notes	$ 1,434,562	$ 1,173,226
Debt. Long-term and Short-term, Combined Amount	1,602,562	1,177,226
Long-term debt	1,409,548	1,177,226
Long-term Debt, Current Maturities	193,014	0
1.125% Convertible Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Principal amount	200,000	200,000
Unamortized Discount	(6,295)	(14,763)
Unamortized Debt Issuance Expense	691	1,666		$ 4,800
Convertible Debt	193,014	183,571
6.125% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Principal amount	400,000	400,000
Unamortized Debt Issuance Expense	3,632	4,611		$ 7,800
Senior Notes, Noncurrent	396,368	395,389
6.25% Senior Notes due 2025 [Member]
Debt Instrument [Line Items]
Principal amount	102,324	0
Debt Instrument, Unamortized Premium	880
Unamortized Debt Issuance Expense		0
Senior Notes, Noncurrent	103,204	0
5.75% Senior Notes due 2026 [Member]
Debt Instrument [Line Items]
Principal amount	750,000	600,000
Unamortized Discount	(1,429)	0
Unamortized Debt Issuance Expense	6,595	5,734	$ 7,600
Senior Notes, Noncurrent	741,976	594,266
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Revolving credit facility	$ 168,000	$ 4,000

Long-Term Debt ADDITIONAL INFOR

Long-Term Debt ADDITIONAL INFORMATION (Details) - USD ($)

12 Months Ended

24 Months Ended

60 Months Ended

Nov. 30, 2023

Nov. 30, 2022

Sep. 15, 2021

Dec. 31, 2020

Nov. 15, 2025

May 15, 2026

Mar. 15, 2021

Sep. 15, 2020

Feb. 18, 2020

Jan. 14, 2020

Dec. 31, 2019

Nov. 14, 2017

Sep. 14, 2016

Debt Instrument [Line Items]

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Long-term Debt

$ 555,500,000

Document Period End Date

Dec. 31, 2020

Line of Credit Facility, Initial Borrowing Base

$ 1,600,000,000

$ 2,100,000,000

Revolving Credit Facility Elected Commitment Amount

1,600,000,000

$ 1,700,000,000

Debt Issuance Costs, Line of Credit Arrangements, Net

8,100,000

$ 8,900,000

Line of Credit Facility, Remaining Borrowing Capacity

$ 1,400,000,000

1,300,000,000

Common Stock [Member]

Debt Instrument [Line Items]

PDC Energy Stock Price

$ 20.53

6.25% Senior Notes due 2025 [Member]

Debt Instrument [Line Items]

Senior Notes ($)

$ 102,300,000

1.125% Convertible Senior Notes due 2021 [Member]

Debt Instrument [Line Items]

Convertible Senior Notes fair value

$ 200,000,000

200,000,000

Debt Instrument, Interest Rate, Stated Percentage

1.125%

Convertible Note, Conversion Price

$ 85.39

$ 85.39

Liability component of gross proceeds of Convertible Notes

$ 160,500,000

Debt Instrument, Convertible, Carrying Amount of Equity Component

$ 39,500,000

Debt Instrument, Frequency of Periodic Payment

semi-annually

Unamortized Debt Issuance Expense

$ (691,000)

(1,666,000)

$ (4,800,000)

Debt Instrument, Unamortized Discount

$ 6,295,000

14,763,000

Convertible Senior Note, Shares Issued Upon Conversion

11.7113

1.125% Convertible Senior Notes due 2021 [Member] | Forecast [Member]

Debt Instrument [Line Items]

Convertible Note Principal Amount

$ 1,000

6.125% Senior Notes due 2024 [Member]

Debt Instrument [Line Items]

Debt Instrument, Interest Rate, Stated Percentage

6.125%

Unamortized Debt Issuance Expense

$ (3,632,000)

(4,611,000)

$ (7,800,000)

Senior Notes ($)

$ 400,000,000

400,000,000

6.125% Senior Notes due 2024 [Member] | 2024 Senior notes redemption price, after September 15, 2020

Debt Instrument [Line Items]

Debt Instrument, Redemption Price, Percentage

103.063%

6.25% Senior Notes due 2025 [Member]

Debt Instrument [Line Items]

Debt Instrument, Interest Rate, Stated Percentage

6.25%

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Long-term Debt

$ 555,500,000

Debt Conversion, Original Debt, Interest Rate of Debt

101.00%

Debt Instrument, Repurchased Face Amount

$ 447,700,000

Redemption offer accepted

$ 452,200,000

Unamortized Debt Issuance Expense

0

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt

550,000,000

Senior Notes ($)

$ 102,324,000

0

Senior Notes Redeemed Interest Payable

$ 6,200,000

Debt Instrument, Redemption Price, Percentage

101.563%

103.125%

100.00%

5.75% Senior Notes due 2026 [Member]

Debt Instrument [Line Items]

Debt Instrument, Interest Rate, Stated Percentage

5.75%

Debt Instrument, Frequency of Periodic Payment

semi-annually

Unamortized Debt Issuance Expense

$ (6,595,000)

(5,734,000)

$ (7,600,000)

Senior Notes ($)

750,000,000

600,000,000

Debt Instrument, Unamortized Discount

$ 1,429,000

$ 0

5.75% Senior Notes due 2026 [Member] | 2026 Senior notes redemption price, after to May 15, 2021 [Member]

Debt Instrument [Line Items]

Debt Instrument, Redemption Price, Percentage

104.313%

5.75% Senior Notes due 2026 [Member] | Issuance of additional aggregate principal for 2026 Senior Notes [Member]

Debt Instrument [Line Items]

Debt Conversion, Original Debt, Interest Rate of Debt

99.00%

Unamortized Debt Issuance Expense

$ (1,800,000)

Senior Notes ($)

150,000,000

Proceeds from Debt, Net of Issuance Costs

$ 146,700,000

Debt Instrument, Unamortized Discount

$ 1,500,000

Initial Borrowing Base [Member] | 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%

LIBOR Option [Member]

Debt Instrument [Line Items]

Line of Credit Facility, Interest Rate at Period End

1.75%

Unused Commitment Fee [Member]

Debt Instrument [Line Items]

Line of Credit Facility, Interest Rate at Period End

0.375%

Leases Lease Narrative (Details

Leases Lease Narrative (Details)	12 Months Ended
	Dec. 31, 2020
Maximum [Member]
Lessee, Lease, Description [Line Items]
Operating and Financing Lease Renewal Term	5 years
Minimum [Member]
Lessee, Lease, Description [Line Items]
Operating and Financing Lease Renewal Term	1 year

Leases Lease Cost (Details)

Leases Lease Cost (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Lease, Cost [Abstract]
Operating Lease, Cost	$ 7,983	$ 4,917
Finance Lease, Right-of-Use Asset, Amortization	1,812	1,961
Finance Lease, Interest Payment on Liability	179	252
Finance Lease, Cost	1,991	2,213
Short-term Lease, Cost	193,756	170,064
Lease, Cost	$ 203,730	$ 177,194

Leases Leases - Lease Assets an

Leases Leases - Lease Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Assets and Liabilities, Lessee [Abstract]
Operating Lease, Right-of-Use Asset	$ 11,722	$ 14,926
Operating Lease, Liability, short term	6,520	4,159
Operating Lease, Liability, long term	9,061	12,944
Operating Lease, Liability	15,581	17,103
Finance Lease, Right-of-Use Asset	3,189	4,637
Finance Lease, Liability, short term	1,466	1,767
Finance Lease, Liability, long term	1,702	2,835
Finance Lease, Liability	$ 3,168	$ 4,602
Operating Lease, Weighted Average Remaining Lease Term	3 years 25 days	4 years 3 months 10 days
Finance Lease, Weighted Average Remaining Lease Term	2 years 6 months 29 days	3 years 2 months 1 day
Operating Lease, Weighted Average Discount Rate, Percent	4.80%	5.00%
Finance Lease, Weighted Average Discount Rate, Percent	4.50%	5.00%

Leases Leases - Maturity of Lea

Leases Leases - Maturity of Lease Liabilities Operating and Financing (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Leases [Abstract]
2021	$ 7,055
2022	5,516
2023	1,559
2024	950
2025	950
Thereafter	748
Total Operating Lease Payments	16,778
Less interest and discount operating, total	(1,197)
Operating Lease, Liability	15,581	$ 17,103
2021	1,557
2022	933
2023	655
2024	139
2025	10
Thereafter	0
Total Financing Lease Payments	3,294
Less interest and discount financing, total	(126)
Finance Lease, Liability	3,168	$ 4,602
2021	8,612
2022	6,449
2023	2,214
2024	1,089
2025	960
Thereafter	748
Total Lease Payments	20,072
Less: Interest and discount	(1,323)
Present value of lease liabilities	$ 18,749

Asset Retirement Obligations _2

Asset Retirement Obligations Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance beginning of year, January 1	$ 127,251	$ 115,021
Change in asset retirement obligation, with a corresponding change to crude oil and natural gas properties, net of disposal	6,494	4,605
Accretion of asset retirement obligations	10,072	6,117	$ 5,075
Revisions in estimated cash flows	4,742	28,991
Obligations discharged with disposal of properties and asset retirements	(28,888)	(23,426)
Asset Retirement Obligation Liabilities Discharged with Divestiture	(774)	(6,939)
Balance end of year, December 31	166,570	127,251	$ 115,021
Less: Current portion	(33,933)	(32,200)
Asset retirement obligations	132,637	95,051
SRC [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Business Acquisition Purchase Price Allocation Asset Retirement Obligation	$ 47,673	$ 2,882

Commitments and Contigencies (D

Commitments and Contigencies (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2020USD ($)MMcfMBbls
Supply Commitment [Line Items]
Dollar Commitment ($ in thousands) | $	$ 516,827
2021
Supply Commitment [Line Items]
Dollar Commitment ($ in thousands) | $	135,435
2022
Supply Commitment [Line Items]
Dollar Commitment ($ in thousands) | $	114,472
2023
Supply Commitment [Line Items]
Dollar Commitment ($ in thousands) | $	95,082
2024
Supply Commitment [Line Items]
Dollar Commitment ($ in thousands) | $	68,175
2025
Supply Commitment [Line Items]
Dollar Commitment ($ in thousands) | $	56,174
Thereafter
Supply Commitment [Line Items]
Dollar Commitment ($ in thousands) | $	$ 47,489
Natural Gas [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	443,215
Natural Gas [Member] | 2021
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	96,816
Natural Gas [Member] | 2022
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	74,322
Natural Gas [Member] | 2023
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	73,139
Natural Gas [Member] | 2024
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	73,339
Natural Gas [Member] | 2025
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	61,170
Natural Gas [Member] | Thereafter
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	64,429
Crude Oil [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	94,375
Crude Oil [Member] | 2021
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	25,032
Crude Oil [Member] | 2022
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	23,360
Crude Oil [Member] | 2023
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	19,685
Crude Oil [Member] | 2024
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	9,882
Crude Oil [Member] | 2025
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	9,855
Crude Oil [Member] | Thereafter
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	6,561
Water [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	24,844
Water [Member] | 2021
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	6,207
Water [Member] | 2022
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	6,207
Water [Member] | 2023
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	6,207
Water [Member] | 2024
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	6,223
Water [Member] | 2025
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	0
Water [Member] | Thereafter
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	0
Wattenberg Field [Member] | Natural Gas [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	327,055
Wattenberg Field [Member] | Natural Gas [Member] | 2021
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	64,014
Wattenberg Field [Member] | Natural Gas [Member] | 2022
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	64,014
Wattenberg Field [Member] | Natural Gas [Member] | 2023
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	64,014
Wattenberg Field [Member] | Natural Gas [Member] | 2024
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	64,189
Wattenberg Field [Member] | Natural Gas [Member] | 2025
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	52,045
Wattenberg Field [Member] | Natural Gas [Member] | Thereafter
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	18,779
Wattenberg Field [Member] | Natural Gas [Member] | Supply Contract Expiration Date [Member]
Supply Commitment [Line Items]
Supply Commitments Contract Expiration Date	Aug. 31, 2026
Wattenberg Field [Member] | Crude Oil [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	70,285
Wattenberg Field [Member] | Crude Oil [Member] | 2021
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	17,002
Wattenberg Field [Member] | Crude Oil [Member] | 2022
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	15,330
Wattenberg Field [Member] | Crude Oil [Member] | 2023
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	11,655
Wattenberg Field [Member] | Crude Oil [Member] | 2024
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	9,882
Wattenberg Field [Member] | Crude Oil [Member] | 2025
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	9,855
Wattenberg Field [Member] | Crude Oil [Member] | Thereafter
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	6,561
Wattenberg Field [Member] | Crude Oil [Member] | Supply Contract Expiration Date [Member]
Supply Commitment [Line Items]
Supply Commitments Contract Expiration Date	Aug. 31, 2026
Wattenberg Field [Member] | Water [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	24,844
Wattenberg Field [Member] | Water [Member] | 2021
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	6,207
Wattenberg Field [Member] | Water [Member] | 2022
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	6,207
Wattenberg Field [Member] | Water [Member] | 2023
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	6,207
Wattenberg Field [Member] | Water [Member] | 2024
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	6,223
Wattenberg Field [Member] | Water [Member] | 2025
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	0
Wattenberg Field [Member] | Water [Member] | Thereafter
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	0
Wattenberg Field [Member] | Water [Member] | Supply Contract Expiration Date [Member]
Supply Commitment [Line Items]
Supply Commitments Contract Expiration Date	Dec. 31, 2024
Delaware Basin [Member] | Natural Gas [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	113,200
Delaware Basin [Member] | Natural Gas [Member] | 2021
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	31,025
Delaware Basin [Member] | Natural Gas [Member] | 2022
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	9,125
Delaware Basin [Member] | Natural Gas [Member] | 2023
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	9,125
Delaware Basin [Member] | Natural Gas [Member] | 2024
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	9,150
Delaware Basin [Member] | Natural Gas [Member] | 2025
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	9,125
Delaware Basin [Member] | Natural Gas [Member] | Thereafter
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	45,650
Delaware Basin [Member] | Natural Gas [Member] | Supply Contract Expiration Date [Member]
Supply Commitment [Line Items]
Supply Commitments Contract Expiration Date	Dec. 31, 2030
Delaware Basin [Member] | Crude Oil [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	24,090
Delaware Basin [Member] | Crude Oil [Member] | 2021
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	8,030
Delaware Basin [Member] | Crude Oil [Member] | 2022
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	8,030
Delaware Basin [Member] | Crude Oil [Member] | 2023
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	8,030
Delaware Basin [Member] | Crude Oil [Member] | 2024
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	0
Delaware Basin [Member] | Crude Oil [Member] | 2025
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	0
Delaware Basin [Member] | Crude Oil [Member] | Thereafter
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf) | MBbls	0
Delaware Basin [Member] | Crude Oil [Member] | Supply Contract Expiration Date [Member]
Supply Commitment [Line Items]
Supply Commitments Contract Expiration Date	Dec. 31, 2023
Appalachiain Basin [Member] | Natural Gas [Member]
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	2,960
Appalachiain Basin [Member] | Natural Gas [Member] | 2021
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	1,777
Appalachiain Basin [Member] | Natural Gas [Member] | 2022
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	1,183
Appalachiain Basin [Member] | Natural Gas [Member] | 2023
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	0
Appalachiain Basin [Member] | Natural Gas [Member] | 2024
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	0
Appalachiain Basin [Member] | Natural Gas [Member] | 2025
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	0
Appalachiain Basin [Member] | Natural Gas [Member] | Thereafter
Supply Commitment [Line Items]
Oil and Gas Delivery Commitments Volumes (MMcf)	0
Appalachiain Basin [Member] | Natural Gas [Member] | Supply Contract Expiration Date [Member]
Supply Commitment [Line Items]
Supply Commitments Contract Expiration Date	Aug. 31, 2022

Commitments and Contingencies A

Commitments and Contingencies Additional information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2020USD ($)bbl	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Loss Contingencies [Line Items]
Transportation, gathering and processing expenses	$ 77,835	$ 46,353	$ 37,403
Delaware Basin/Wattenberg Field [Member]
Loss Contingencies [Line Items]
Transportation netted against Revenue	22,200	50,100
Transportation, gathering and processing expenses	$ 15,700	$ 1,900
Minimum [Member] | Delaware Basin [Member]
Loss Contingencies [Line Items]
Committed Barrels of Crude Oil per day | bbl	22,000
Maximum [Member] | Delaware Basin [Member]
Loss Contingencies [Line Items]
Committed Barrels of Crude Oil per day | bbl	24,000

Commitments and Contingencies N

Commitments and Contingencies New Plant (Details)	12 Months Ended
	Dec. 31, 2020MMcf
Natural Gas [Member]
Property, Plant and Equipment [Line Items]
Qualitative and Quantitative Information, Transferor's Continuing Involvement, Third Party Commitments	200
First facilities agreement with midstream provider [Member]
Property, Plant and Equipment [Line Items]
combined incremental volume commitment	98.2
incremental volume commitment	51.75
First facilities agreement with midstream provider [Member] | SRC [Member]
Property, Plant and Equipment [Line Items]
combined incremental volume commitment	46.4
Second facilities agreement with midstream provider [Member]
Property, Plant and Equipment [Line Items]
combined incremental volume commitment	77.3
incremental volume commitment	33.5
Second facilities agreement with midstream provider [Member] | SRC [Member]
Property, Plant and Equipment [Line Items]
combined incremental volume commitment	43.8

Common Stock Stocked Based Comp

Common Stock Stocked Based Compensation Summary (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	May 31, 2020	May 31, 2018
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share based compensation expense	$ 22,200	$ 23,837	$ 21,782
Stock-based Compensation - G&A
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share based compensation expense	21,182	22,754	20,848
Stock-based Compensation - LOE
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share based compensation expense	$ 1,018	$ 1,083	$ 934
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	1,800,000
Common stock shares remain avaliable for issuance	5,204,837
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	189,154
Minimum [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Performance Shares Payout Range	0.00%
Stock Appreciation Rights (SARs) [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Exercisable at December 31,	$ 49.45
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) - Restricted Stock [Member] - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
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,	795,926
Granted	1,203,108
Vested	(534,610)
Forfeited	(313,454)
Outstanding end of year, December 31,	1,150,970	795,926
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of year, January 1,	$ 45.51
Weighted-average grant date fair value per share	11.98	$ 40.34	$ 50.69
Weighted average Vested	38.08
Weighted average Forfeited	22.62
Outstanding at end of year, December 31,	$ 20.14	$ 45.51
Total intrinsic value of time based awards vested	$ 7,312	$ 11,652	$ 12,282
Total intrinsic value of time-based awards non-vested	$ 23,629	$ 20,829	$ 18,404
Market price per common share as of December 31,	$ 20.53	$ 26.17	$ 29.76
Weighted-average grant date fair value per share	$ 11.98	$ 40.34	$ 50.69
Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 13,000
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Period for Recognition	1 year 9 months 18 days

Common Stock Schedule of Change

Common Stock Schedule of Changes in SARs (Details) - Stock Appreciation Rights (SARs) [Member]	12 Months Ended
	Dec. 31, 2020$ / sharesshares
Average Remaining Contractual Term (in years)
Exercisable at December 31,	3 years 3 months 18 days
Exercisable at December 31, | shares	210,675
Exercisable at December 31, | $ / shares	$ 49.45

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
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Jan. 14, 2020	Apr. 30, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Repurchase Program, Authorized Amount				$ 525	$ 200
Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Shares Payout Range	0.00%
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Shares Payout Range	250.00%
Restricted Stock - Market Based Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Market based performance shares granted to executives	368,077
Expected term of award	3 years	3 years	3 years
Risk-free interest rate	1.40%	2.50%	2.40%
Expected Volatility	46.60%	41.40%	42.30%
Weighted-average grant date fair value per share	$ 33.52	$ 56.68	$ 69.98
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	$ 11.98	$ 40.34	$ 50.69
SRC [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Shares Payout Range	0.00%
SRC [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Shares Payout Range	200.00%
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
Weighted-average grant date fair value per share	$ 30.29

Common Stock Schedule of Chan_2

Common Stock Schedule of Changes in Restricted Stock - Market Based Awards (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Maximum [Member]
Weighted-Average Grant-Date Fair Value
Performance Shares Payout Range	250.00%
SRC [Member] | Maximum [Member]
Weighted-Average Grant-Date Fair Value
Performance Shares Payout Range	200.00%
Restricted Stock - Market Based Awards [Member]
Number of Shares
Outstanding beginning of year, January 1,	221,142
Granted	524,005
Vested	(156,003)
Forfeited	(89,597)
Outstanding end of year, December 31,	499,547	221,142
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of year, January 1,	$ 61.61
Weighted average Vested	38.59
Weighted average Forfeited	46.43
Outstanding at end of year, December 31,	$ 38.66	$ 61.61
Intrinsic value of market based awards vested	$ 1,736	$ 530	$ 620
Total intrinsic value of market-based awards non-vested	$ 10,256	$ 5,787	$ 3,063
Market price per common share as of December 31,	$ 20.53	$ 26.17	$ 29.76
Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 7,600
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Period for Recognition	1 year 8 months 12 days
Expected term of award	3 years	3 years	3 years
Risk-free interest rate	1.40%	2.50%	2.40%
Expected Volatility	46.60%	41.40%	42.30%
Weighted-average grant date fair value per share	$ 33.52	$ 56.68	$ 69.98
Market based performance shares granted to executives	368,077
Restricted Stock - Market Based Awards [Member] | SRC [Member]
Weighted-Average Grant-Date Fair Value
Weighted-average grant date fair value per share	$ 30.29
Market based performance shares granted to executives	155,928
Restricted Stock SRC - Market Based Awards [Member]
Weighted-Average Grant-Date Fair Value
Expected term of award	2 years
Risk-free interest rate	1.60%
Expected Volatility	56.90%
Weighted-average grant date fair value per share	$ 33.35
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,	795,926
Granted	1,203,108
Vested	534,610
Forfeited	(313,454)
Outstanding end of year, December 31,	1,150,970	795,926
Weighted-Average Grant-Date Fair Value
Outstanding at beginning of year, January 1,	$ 45.51
Weighted average Vested	38.08
Weighted average Forfeited	22.62
Outstanding at end of year, December 31,	$ 20.14	$ 45.51
Total intrinsic value of market-based awards non-vested	$ 23,629	$ 20,829	$ 18,404
Market price per common share as of December 31,	$ 20.53	$ 26.17	$ 29.76
Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 13,000
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Period for Recognition	1 year 9 months 18 days
Weighted-average grant date fair value per share	$ 11.98	$ 40.34	$ 50.69

Common Stock Preferred Stock (D

Common Stock Preferred Stock (Details) - $ / shares	Dec. 31, 2020	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, 2020	Dec. 31, 2019	Dec. 31, 2018	Jan. 14, 2020	Apr. 30, 2019
Equity, Class of Treasury Stock [Line Items]
Stock Repurchase Program, Authorized Amount				$ 525,000	$ 200,000
Payments for Repurchase of Common Stock	$ 9,345	$ 4,003	$ 5,147
Treasury Stock, Common [Member]
Equity, Class of Treasury Stock [Line Items]
Stock Repurchased During Period, Shares	1,266,000	4,706,139
Payments for Repurchase of Common Stock	$ 23,800	$ 154,400

Income Taxes Provision for Inco

Income Taxes Provision for Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Current Federal Tax Benefit (Expense)	$ 1,592	$ 1,366	$ 887
Current State and Local Tax Benefit (Expense)	(220)	(300)	(188)
Current Income Tax Expense (Benefit)	1,372	1,066	699
Deferred Federal Income Tax Benefit (Expense)	5,460	4,507	(1,986)
Deferred State and Local Income Tax Benefit (Expense)	1,070	(2,251)	(4,119)
Deferred Income Tax from Continuing Operations	6,530	2,256	(6,105)
Income tax benefit (expense)	$ 7,902	$ 3,322	$ (5,406)

Income Taxes Reconciliation of

Income Taxes Reconciliation of Statutory Rate to Effective Rate (Details)	12 Months Ended
	Dec. 31, 2020Rate	Dec. 31, 2019Rate	Dec. 31, 2018Rate
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Statutory tax rate	21.00%	21.00%	21.00%
State income tax, net	3.00%	3.60%	(6.40%)
Federal tax credits	0.00%	(3.30%)	(52.10%)
Effect of state income tax rate changes	0.20%	(6.40%)	6.70%
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Percent	(22.10%)	(0.60%)	45.50%
Non-deductible compensation	(0.60%)	(5.00%)	(21.80%)
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Depletion, Percent	(0.10%)	(2.30%)	0.00%
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Other, Amount	(0.10%)	(1.00%)	31.80%
Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent	0.00%	(0.50%)	4.90%
Other	(0.20%)	0.00%	(0.40%)
Effective Income Tax Rate Reconciliation, Percent	1.10%	5.50%	72.80%

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, 2020	Dec. 31, 2019
Components of Deferred Tax Assets [Abstract]
Deferred compensation	$ 10,472	$ 9,905
Asset retirement obligations	39,371	30,993
Federal NOL carryforwards	97,880	22,965
State NOL and tax credit carryforwards, net	21,034	9,508
Federal tax - credit carryforwards	3,059	4,448
Deferred Tax Assets, Derivative Instruments	18,351	0
Deferred Tax Assets, Tax Deferred Expense, Other	4,364	4,874
Other	5,741	3,887
Deferred Tax Assets, Valuation Allowance	(165,575)	(3,775)
Deferred tax assets	34,697	82,805
Components of Deferred Tax Liabilities [Abstract]
Properties and equipment	33,183	268,234
Deferred Tax Liabilities, Derivatives	0	6,841
Convertible debt	1,514	3,571
Total gross deferred tax liabilities	34,697	278,646
Net deferred tax liability	$ 0	$ 195,841

Income Taxes Additional Informa

Income Taxes Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Operating Loss Carryforwards:
Document Period End Date		Dec. 31, 2020
Deferred Tax Liabilities, Property, Plant and Equipment		$ 33,183	$ 268,234
Effective Income Tax Rate Reconciliation, Percent		1.10%	5.50%	72.80%
Net deferred tax liability		$ 0	$ 195,841
Income Tax Expense (Benefit)		(6,530)	(2,256)	$ 6,105
Deferred tax asset, operating loss carryforward, annual limitation		15,100
Operating Loss Carryforwards		466,000
Alternative minimum tax - credit carryforward		3,059	4,448
State NOL carryforwards		21,034	9,508
Deferred Tax Assets, Operating Loss Carryforwards		97,880	22,965
Impairment of properties and equipment	$ 881,100	882,393	38,536	458,397
Income tax benefit (expense)		7,902	3,322	$ (5,406)
Deferred Tax Assets, Valuation Allowance		(165,575)	$ (3,775)
State NOL Carryforwards
Operating Loss Carryforwards:
State NOL carryforwards		494,800
Delaware Basin Acquisition [Member]
Operating Loss Carryforwards:
Deferred Tax Assets, Operating Loss Carryforwards		60,100
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		$ 3,700

Earnings per share Earnings Per

Earnings per share Earnings Per Share (Details) - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Mar. 15, 2021
Reconciliation of Weighted-Average Diluted Shares Outstanding
Weighted average common shares outstanding - basic	98,251	64,032	66,059
Diluted	98,251	64,032	66,303
Anti-dilutive Effect
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	1,936	1,291	254
Convertible Senior Note
Convertible Note, Number of Shares Convertible	2,300
1.125% Convertible Senior Notes due 2021 [Member]
Convertible Senior Note
Convertible Note, Conversion Price	$ 85.39			$ 85.39
Restricted Stock [Member]
Reconciliation of Weighted-Average Diluted Shares Outstanding
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements	0	0	173
Anti-dilutive Effect
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	1,707	989	145
Other Equity-Based Awards
Reconciliation of Weighted-Average Diluted Shares Outstanding
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements	0	0	71
Anti-dilutive Effect
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	229	302	109

Supplemental Cash Flow Supple_3

Supplemental Cash Flow Supplemental Cash Flow (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Supplemental Cash Flow Elements [Line Items]
Interest Paid, Excluding Capitalized Interest, Operating Activities	$ 75,506	$ 57,439	$ 55,586
Income Taxes Paid, Net	9	(1,167)	(6,719)
Capital Expenditures Incurred but Not yet Paid	(28,676)	(68,246)	(36,328)
Increase (Decrease) in Asset Retirement Obligations	54,984	29,533	37,136
Operating Lease, Payments	9,246	5,301
Operating Cash Flow from Financing Leases	156	253
Finance Lease, Principal Payments	1,905	1,952	1,495
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	4,305	1,428	0
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability	$ 703	$ 2,323	$ 0