SM Energy (SM) 10-K 18 Feb 21 2020 FY Annual report Financial data

Cover page

Cover page - USD ($)	12 Months Ended
	Dec. 31, 2020	Feb. 04, 2021	Jun. 30, 2020
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2020
Document Transition Report	false
Entity File Number	001-31539
Entity Registrant Name	SM ENERGY CO
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	41-0518430
Entity Address, Address Line One	1775 Sherman Street, Suite 1200
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	861-8140
Title of 12(b) Security	Common stock, $.01 par value
Trading Symbol	SM
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Entity Shell Company	false
Entity Public Float			$ 419,107,095
Entity Common Stock, Shares Outstanding		114,742,304
Documents Incorporated by Reference	Certain information required by Items 10, 11, 12, 13, and 14 of Part III of this report is incorporated by reference from portions of the registrant’s Definitive Proxy Statement on Schedule 14A relating to its 2021 annual meeting of stockholders, to be filed within 120 days after December 31, 2020.
Entity Central Index Key	0000893538
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
Amendment Flag	false

CONSOLIDATED BALANCE SHEETS (in

CONSOLIDATED BALANCE SHEETS (in thousands, except share data) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Current assets:
Cash and cash equivalents	$ 10	$ 10
Accounts receivable	162,455	184,732
Derivative assets	31,203	55,184
Prepaid expenses and other	10,001	12,708
Total current assets	203,669	252,634
Property and equipment (successful efforts method):
Proved oil and gas properties	8,608,522	8,934,020
Accumulated depletion, depreciation, and amortization	(4,886,973)	(4,177,876)
Unproved oil and gas properties	714,602	1,005,887
Wells in progress	233,498	118,769
Other property and equipment, net of accumulated depreciation of $63,662 and $64,032, respectively	32,217	72,848
Total property and equipment, net	4,701,866	5,953,648
Noncurrent assets:
Derivative assets	23,150	20,624
Other noncurrent assets	47,746	65,326
Total noncurrent assets	70,896	85,950
Total assets	4,976,431	6,292,232
Other property and equipment, accumulated depreciation	63,662	64,032
Current liabilities:
Accounts payable and accrued expenses	371,670	402,008
Derivative liabilities	200,189	50,846
Other current liabilities	11,880	19,189
Total current liabilities	583,739	472,043
Noncurrent liabilities:
Revolving credit facility	93,000	122,500
Senior Notes, net	2,121,319	2,610,298
Asset retirement obligations	83,325	84,134
Deferred income taxes	0	189,386
Derivative liabilities	22,331	3,444
Other noncurrent liabilities	56,557	61,433
Total noncurrent liabilities	2,376,532	3,071,195
Commitments and contingencies (note 6)
Stockholders’ equity:
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 114,742,304 and 112,987,952 shares, respectively	1,147	1,130
Additional paid-in capital	1,827,914	1,791,596
Retained earnings	200,697	967,587
Accumulated other comprehensive loss	(13,598)	(11,319)
Total stockholders’ equity	2,016,160	2,748,994
Total liabilities and stockholders’ equity	$ 4,976,431	$ 6,292,232
Common Stock, par value per share	$ 0.01	$ 0.01
Common Stock, shares authorized	200,000,000	200,000,000
Common Stock, shares issued	114,742,304	112,987,952
Common Stock, shares outstanding	114,742,304	112,987,952

CONSOLIDATED BALANCE SHEETS (_2

CONSOLIDATED BALANCE SHEETS (in thousands, except share data) Parenthetical - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Statement of Financial Position [Abstract]
Other property and equipment, accumulated depreciation	$ 63,662	$ 64,032
Common Stock, par value per share	$ 0.01	$ 0.01
Common Stock, shares authorized	200,000,000	200,000,000
Common Stock, shares issued	114,742,304	112,987,952
Common Stock, shares outstanding	114,742,304	112,987,952

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS (in thousands, except per share data) - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Operating revenues and other income:
Oil, gas, and NGL production revenue	$ 1,126,188	$ 1,585,750	$ 1,636,357
Net gain on divestiture activity	91	862	426,917
Other operating revenues	394	3,493	3,798
Total operating revenues and other income	1,126,673	1,590,105	2,067,072
Operating expenses:
Oil, gas, and NGL production expense	391,217	500,709	487,367
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	784,987	823,798	665,313
Exploration	40,997	51,500	55,166
Impairment	1,016,013	33,842	49,889
General and administrative	99,160	132,797	116,504
Net derivative (gain) loss	(161,576)	97,539	(161,832)
Other operating expense, net	24,825	19,888	18,328
Total operating expenses	2,195,623	1,660,073	1,230,735
Income (loss) from operations	(1,068,950)	(69,968)	836,337
Interest expense	(163,892)	(159,102)	(160,906)
Net gain (loss) on extinguishment of debt	280,081	0	(26,740)
Other non-operating income (expense), net	(3,944)	(1,974)	3,086
Income (loss) before income taxes	(956,705)	(231,044)	651,777
Income tax (expense) benefit	192,091	44,043	(143,370)
Net income (loss)	$ (764,614)	$ (187,001)	$ 508,407
Basic weighted-average common shares outstanding	113,730	112,544	111,912
Diluted weighted-average common shares outstanding	113,730	112,544	113,502
Basic net income (loss) per common share	$ (6.72)	$ (1.66)	$ 4.54
Diluted net income (loss) per common share	$ (6.72)	$ (1.66)	$ 4.48

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (in thousands) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Statement of Comprehensive Income [Abstract]
Net income (loss)		$ (764,614)	$ (187,001)	$ 508,407
Other comprehensive income (loss), net of tax:
Pension liability adjustment	[1]	(2,279)	1,061	4,378
Total other comprehensive income (loss), net of tax		(2,279)	1,061	4,378
Total comprehensive income (loss)		$ (766,893)	$ (185,940)	$ 512,785
[1]	(1) Please refer to Note 8 – Pension Benefits for additional discussion of the pension liability adjustment.

CONSOLIDATED STATEMENTS OF STOC

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (in thousands, except share data and dividends per share) - USD ($) $ in Thousands	Total	Common Stock	Additional Paid-in Capital	Retained Earnings	Accumulated Other Comprehensive Loss
Cash dividends per share	$ 0.10
Balances, Common Stock, Shares, Outstanding, Beginning at Dec. 31, 2017		111,687,016
Balances, Total Stockholders' Equity, Beginning at Dec. 31, 2017	$ 2,394,608	$ 1,117	$ 1,741,623	$ 665,657	$ (13,789)
Increase (Decrease) in Stockholders' Equity
Net income (loss)	508,407			508,407
Other comprehensive income (loss)	4,378				4,378
Cash dividends	(11,191)			(11,191)
Issuance of common stock under Employee Stock Purchase Plan (Shares)		199,464
Issuance of common stock under Employee Stock Purchase Plan (Amount)	3,187	$ 2	3,185
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings (Shares)		291,745
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings (Amount)	(2,975)	$ 3	(2,978)
Stock-based compensation expense (Shares)		63,741
Stock-based compensation expense (Amount)	23,908	$ 0	23,908
Balances, Common Stock, Shares, Outstanding, Ending at Dec. 31, 2018		112,241,966
Balances, Total Stockholders' Equity, Ending at Dec. 31, 2018	$ 2,920,322	$ 1,122	1,765,738	1,165,842	(12,380)
Cash dividends per share	$ 0.10
Increase (Decrease) in Stockholders' Equity
Net income (loss)	$ (187,001)			(187,001)
Other comprehensive income (loss)	1,061				1,061
Cash dividends	(11,254)			(11,254)
Issuance of common stock under Employee Stock Purchase Plan (Shares)		314,868
Issuance of common stock under Employee Stock Purchase Plan (Amount)	3,209	$ 3	3,206
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings (Shares)		334,399
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings (Amount)	(1,661)	$ 4	(1,665)
Stock-based compensation expense (Shares)		96,719
Stock-based compensation expense (Amount)	$ 24,318	$ 1	24,317
Balances, Common Stock, Shares, Outstanding, Ending at Dec. 31, 2019	112,987,952	112,987,952
Balances, Total Stockholders' Equity, Ending at Dec. 31, 2019	$ 2,748,994	$ 1,130	1,791,596	967,587	(11,319)
Cash dividends per share	$ 0.02
Increase (Decrease) in Stockholders' Equity
Net income (loss)	$ (764,614)			(764,614)
Other comprehensive income (loss)	(2,279)				(2,279)
Cash dividends	(2,276)			(2,276)
Issuance of common stock under Employee Stock Purchase Plan (Shares)		464,757
Issuance of common stock under Employee Stock Purchase Plan (Amount)	1,464	$ 4	1,460
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings (Shares)		1,022,019
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings (Amount)	(1,560)	$ 10	(1,570)
Stock-based compensation expense (Shares)		267,576
Stock-based compensation expense (Amount)	14,999	$ 3	14,996
Issuance of warrants	21,520		21,520
Other	$ (88)		(88)
Balances, Common Stock, Shares, Outstanding, Ending at Dec. 31, 2020	114,742,304	114,742,304
Balances, Total Stockholders' Equity, Ending at Dec. 31, 2020	$ 2,016,160	$ 1,147	$ 1,827,914	$ 200,697	$ (13,598)

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Cash flows from operating activities:
Net income (loss)		$ (764,614)	$ (187,001)	$ 508,407
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net gain on divestiture activity		(91)	(862)	(426,917)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion		784,987	823,798	665,313
Impairment		1,016,013	33,842	49,889
Stock-based compensation expense		14,999	24,318	23,908
Net derivative (gain) loss		(161,576)	97,539	(161,832)
Derivative settlement gain (loss)		351,261	39,222	(135,803)
Amortization of debt discount and deferred financing costs		17,704	15,474	15,258
(Gain) loss on extinguishment of debt		(280,081)	0	26,740
Deferred income taxes		(192,540)	(41,835)	141,708
Other, net		(6,709)	2,220	287
Changes in working capital:
Accounts receivable		29,100	(39,556)	(20,775)
Prepaid expenses and other		5,873	6,130	(729)
Accounts payable and accrued expenses		(23,382)	50,278	35,175
Net cash provided by operating activities		790,944	823,567	720,629
Cash flows from investing activities:
Net proceeds from the sale of oil and gas properties		92	13,059	748,509
Capital expenditures		(547,785)	(1,023,769)	(1,303,188)
Acquisition of proved and unproved oil and gas properties		(7,873)	(2,581)	(33,255)
Net cash used in investing activities		(555,566)	(1,013,291)	(587,934)
Cash flows from financing activities:
Proceeds from revolving credit facility		1,447,000	1,589,000	0
Repayment of revolving credit facility		(1,476,500)	(1,466,500)	0
Debt issuance costs related to 10.0% Senior Secured Notes due 2025		(13,069)	0	0
Net proceeds from Senior Notes		0	0	492,079
Cash paid to repurchase Senior Notes		(189,998)	0	(845,002)
Net proceeds from sale of common stock		1,464	3,209	3,187
Dividends paid		(2,276)	(11,254)	(11,191)
Other, net		(1,999)	(2,686)	(7,746)
Net cash provided by (used in) financing activities		(235,378)	111,769	(368,673)
Net change in cash, cash equivalents, and restricted cash		0	(77,955)	(235,978)
Cash, cash equivalents, and restricted cash at beginning of period		10	77,965	313,943
Cash, cash equivalents, and restricted cash at end of period		10	10	77,965
Supplemental Cash Flow Information - Operating Activities:
Cash paid for interest, net of capitalized interest		(140,493)	(141,902)	(150,727)
Net cash (paid) refunded for income taxes		6,664	6,109	(2,995)
Supplemental Cash Flow Information - Investing Activities:
Decrease in capital expenditure accruals and other		(7,965)	(24,289)	(2,774)
Non-cash investing and financing activities
Non-cash investing and financing activities (1)(2)	[1],[2]
[1]	(1) Please refer to Note 3 – Acquisitions, Divestitures, and Assets Held for Sale for discussion of the carrying value of properties exchanged during the years ended December 31, 2020, 2019, and 2018.
[2]	(2) Please refer to Note 5 – Long-Term Debt for discussion of the debt transactions executed during the years ended December 31, 2020, and 2018.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2020
Accounting Policies [Abstract]
Summary of Significant Accounting Policies [Text Block]	Note 1 – Summary of Significant Accounting Policies Description of Operations SM Energy Company, together with its consolidated subsidiaries, is an independent energy company engaged in the acquisition, exploration, development, and production of oil, gas, and NGLs in the state of Texas. Basis of Presentation The accompanying consolidated financial statements include the accounts of the Company and have been prepared in accordance with GAAP and the instructions to Form 10-K and Regulation S-X. Intercompany accounts and transactions have been eliminated. In connection with the preparation of the accompanying consolidated financial statements, the Company evaluated events subsequent to the balance sheet date of December 31, 2020, through the filing of this report. Additionally, certain prior period amounts have been reclassified to conform to current period presentation in the accompanying consolidated financial statements. Use of Estimates in the Preparation of Financial Statements The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of proved oil and gas reserves, assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of proved oil and gas reserve quantities provide the basis for the calculation of DD&A expense, impairment of proved and unproved oil and gas properties, and asset retirement obligations, each of which represents a significant component of the accompanying consolidated financial statements. Cash and Cash Equivalents The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments. Accounts Receivable The Company’s accounts receivable primarily consists of receivables due from oil, gas, and NGL purchasers and from joint interest owners on properties the Company operates. For receivables due from joint interest owners, the Company generally has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, the Company’s oil, gas, and NGL receivables are collected within 30 to 90 days and the Company has had minimal bad debts. Although diversified among many companies, collectibility is dependent upon the financial wherewithal of each individual company and is influenced by the general economic conditions of the industry. Receivables are not collateralized. Please refer to Note 13 – Accounts Receivable and Accounts Payable and Accrued Expenses for additional disclosure. Concentration of Credit Risk and Major Customers The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy related industries. The creditworthiness of customers and other counterparties is subject to regular review. The Company does not believe the loss of any single purchaser of its production would materially impact its operating results, as oil, gas, and NGLs are products with well-established markets and numerous purchasers in the Company’s operating areas. The following major customers and entities under common control accounted for 10 percent or more of the Company’s total oil, gas, and NGL production revenue for at least one of the periods presented: For the Years Ended December 31, 2020 2019 2018 Major customer #1 (1) — % 18 % 18 % Major customer #2 (1) 20 % 14 % 5 % Major customer #3 (1) 24 % 13 % 7 % Major customer #4 (1) 6 % 9 % 10 % Major customer #5 (1) 15 % 4 % — % Group #1 of entities under common control (2) 5 % 13 % 18 % Group #2 of entities under common control (2) 7 % 11 % 12 % ____________________________________________ (1) These major customers are purchasers of a portion of the Company’s production from its Midland Basin assets and South Texas assets. (2) In the aggregate, these groups of entities under common control represented purchasers of more than 10% of total oil, gas, and NGL production revenue for at least one of the periods presented; however, no individual entity comprising either group was a purchaser of more than 10% of the Company’s total oil, gas, and NGL production revenue. The Company generally contracts with the affiliates of the lenders under its Credit Agreement as its derivative counterparties, and the Company’s policy is that each counterparty must have certain minimum investment grade senior unsecured debt ratings. The Company maintains its primary bank accounts with a large, multinational bank that has branch locations in the Company’s areas of operations. The Company’s policy is to diversify its concentration of cash and cash equivalent investments among multiple institutions and investment products to limit the amount of credit exposure to any single institution or investment. Oil and Gas Producing Activities Proved properties . The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method, the costs of development wells are capitalized whether those wells are successful or unsuccessful. Capitalized drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities in the field, are depleted on an asset group basis (properties aggregated based on geographical and geological characteristics) using the units-of-production method based on estimated proved developed oil and gas reserves. Similarly, proved leasehold costs are depleted on the same asset group basis; however, the units-of-production method is based on estimated total proved oil and gas reserves. The computation of DD&A expense takes into consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging equipment. Proved oil and gas property costs are evaluated for impairment on a pool-by-pool basis and reduced to fair value when there is an indication that associated carrying costs may not be recoverable. The Company uses Level 3 inputs and the income valuation technique, which converts future cash flows to a single present value amount, to measure the fair value of proved properties using a discount rate, price and cost forecasts, and certain reserve risk-adjustment factors, as selected by the Company’s management. The Company uses a discount rate that represents a current market-based weighted average cost of capital. The discount rate typically ranges from 10 percent to 15 percent. The prices for oil and gas are forecasted based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLs are forecasted using OPIS Mont Belvieu pricing, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. Certain undeveloped reserve estimates are also risk-adjusted given the risk to related projected cash flows due to performance and exploitation uncertainties. The partial sale of a proved property within an existing field is accounted for as a normal retirement and no net gain or loss on divestiture activity is recognized as long as the treatment does not significantly affect the units-of-production depletion rate. The sale of a partial interest in an individual proved property is accounted for as a recovery of cost. A net gain or loss on divestiture activity is recognized in the accompanying statements of operations for all other sales of proved properties. Unproved properties . The unproved oil and gas properties line item on the accompanying consolidated balance sheets (“accompanying balance sheets”) consists of the costs incurred to acquire unproved leases. Leasehold costs allocated to those leases, or partial leases that have associated proved reserves recorded, are reclassified to proved properties and depleted on an asset group basis using the units-of-production method based on estimated total proved oil and gas reserves. Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. Lease acquisition costs that are not individually significant are aggregated by asset group and the portion of such costs estimated to be nonproductive prior to lease expiration are recognized as a valuation allowance and amortized over the appropriate period. The estimate of what could be nonproductive is based on historical trends or other information, including current drilling plans and the Company’s intent to renew leases. To measure the fair value of unproved properties, the Company uses a market approach, which takes into account the following significant assumptions: remaining lease terms, future development plans, risk-weighted potential resource recovery, estimated reserve values, and estimated acreage value based on price(s) received for similar, recent acreage transactions by the Company or other market participants. For the sale of unproved properties where the original cost has been partially or fully amortized by providing a valuation allowance on an asset group basis, neither a gain nor loss is recognized unless the sales price exceeds the original cost of the property, in which case a gain shall be recognized in the accompanying statements of operations in the amount of such excess. Exploratory . Exploratory geological and geophysical, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage are expensed as incurred. Under the successful efforts method, exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are found, exploratory well costs will be capitalized as proved properties and will be accounted for following the successful efforts method of accounting described above. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. The application of the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either development or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes. Once a well is drilled, the determination that economic proved reserves have been discovered may take considerable time and judgment. Exploratory dry hole costs are included in the cash flows from investing activities section as part of capital expenditures within the accompanying statements of cash flows. Please refer to Note 11 – Fair Value Measurements for additional information. Other Property and Equipment Other property and equipment such as facilities, office furniture and equipment, buildings, and computer hardware and software are recorded at cost. The Company capitalizes certain software costs incurred during the application development stage. The application development stage generally includes software design, configuration, testing, and installation activities. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed when incurred. Depreciation is calculated using either the straight-line method over the estimated useful lives of the assets, which range from 3 to 30 years, or the unit of output method when appropriate. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts. Other property and equipment costs are evaluated for impairment and reduced to fair value when there is an indication the carrying costs may not be recoverable. To measure the fair value of other property and equipment, the Company uses an income valuation technique or market approach depending on the quality of information available to support management’s assumptions and the circumstances. The valuation includes consideration of the proved and unproved assets supported by the property and equipment, future cash flows associated with the assets, and fixed costs necessary to operate and maintain the assets. Asset Retirement Obligations The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties, including facilities requiring decommissioning. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is drilled or acquired, or a facility is constructed. The increase in carrying value is included in the proved oil and gas properties line item in the accompanying balance sheets. The Company depletes the amount added to proved oil and gas property costs and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective long-lived assets. Cash paid to settle asset retirement obligations is included in the cash flows from operating activities section of the accompanying statements of cash flows. The Company’s estimated asset retirement obligation liability is based on historical experience in plugging and abandoning wells, estimated economic lives, estimated plugging and abandonment cost, and federal and state regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. The credit-adjusted risk-free rates used to discount the Company’s plugging and abandonment liabilities range from 5.5 percent to 12 percent. In periods subsequent to initial measurement of the liability, the Company must recognize period-to-period changes in the liability resulting from the passage of time, revisions to either the amount of the original estimate of undiscounted cash flows or economic life, or changes in inflation factors or the Company’s credit-adjusted risk-free rate as market conditions warrant. Please refer to Note 14 – Asset Retirement Obligations for a reconciliation of the Company’s total asset retirement obligation liability as of December 31, 2020, and 2019. Derivative Financial Instruments The Company periodically enters into commodity derivative instruments to mitigate a portion of its exposure to potentially adverse market changes in commodity prices for its expected future oil, natural gas, and NGL production and the associated impact on cash flows. These instruments typically include commodity price swaps and costless collars, as well as, basis differential and roll differential swaps. Commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities, with the exception of derivative instruments that meet the “normal purchase normal sale” exclusion. The Company does not designate its commodity derivative contracts as hedging instruments. Accordingly, the Company reflects changes in the fair value of its derivative instruments in its accompanying statements of operations as they occur. Gains and losses on derivatives are included within the cash flows from operating activities section of the accompanying statements of cash flows. For additional discussion on derivatives, please refer to Note 10 – Derivative Financial Instruments . Revenue Recognition The Company derives revenue primarily from the sale of produced oil, gas, and NGLs. Revenue is recognized at the point in time when custody and title (“control”) of the product transfers to the purchaser, which may differ depending on the applicable contractual terms. Revenue accruals are recorded monthly and are based on estimated production delivered to a purchaser and the expected price to be received. Variances between estimates and the actual amounts received are recorded in the month payment is received. Please refer to Note 2 - Revenue from Contracts with Customers for additional discussion. Stock-Based Compensation At December 31, 2020, the Company had stock-based employee compensation plans that included RSUs and PSUs issued to employees, RSUs and restricted stock issued to non-employee directors, and an employee stock purchase plan available to eligible employees. These are more fully described in Note 7 – Compensation Plans. The Company records expense associated with the fair value of stock-based compensation in accordance with authoritative accounting guidance, which is based on the estimated fair value of these awards determined at the time of grant, and is included within the general and administrative and exploration expense line items in the accompanying statements of operations. For stock-based compensation awards containing non-market based performance conditions, the Company evaluates the probability of the number of shares that are expected to vest, and then adjusts the expense to reflect the number of shares expected to vest and the cumulative vesting period met to date. Further, the Company accounts for forfeitures of stock-based compensation awards as they occur. Income Taxes The Company accounts for deferred income taxes whereby deferred tax assets and liabilities are recognized based on the tax effects of temporary differences between the carrying amounts on the accompanying consolidated financial statements and the tax basis of assets and liabilities, as measured using current enacted tax rates. These differences will result in taxable income or deductions in future years when the reported amounts of the assets or liabilities are recorded or settled, respectively. The Company records deferred tax assets and associated valuation allowances, when appropriate, to reflect amounts more likely than not to be realized based upon Company analysis. The cumulative effect of enacted tax rate changes on the net balance of reported amounts of assets and liabilities is recognized in the period of enactment. Please refer to Note 4 – Income Taxes for additional discussion. Earnings per Share The Company uses the treasury stock method to determine the effect of potentially dilutive instruments. Please refer to Note 9 - Earnings Per Share for additional discussion. Comprehensive Income (Loss) Comprehensive income (loss) is used to refer to net income (loss) plus other comprehensive income (loss). Other comprehensive income (loss) is comprised of revenues, expenses, gains, and losses that under GAAP are reported as separate components of stockholders’ equity instead of net income (loss). Comprehensive income (loss) is presented net of income taxes in the accompanying consolidated statements of comprehensive income (loss) (“accompanying statements of comprehensive income (loss)”). The Company’s policy for releasing income tax effects within accumulated other comprehensive loss is an incremental, unit-of-account approach. Please refer to Note 8 – Pension Benefits for detail on the changes in the balances of components comprising other comprehensive income (loss). Fair Value of Financial Instruments The Company’s financial instruments including cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The recorded value of the Company’s revolving credit facility approximates its fair value as it bears interest at a floating rate that approximates a current market rate. The Company had a $93.0 million balance under its revolving credit facility as of December 31, 2020, compared with a $122.5 million balance as of December 31, 2019. The Company’s Senior Notes, as defined in Note 5 – Long-Term Debt in Part II, Item 8 of this report, are recorded at cost, net of any unamortized discount and deferred financing costs, and their respective fair values are disclosed in Note 11 – Fair Value Measurements. The Company’s warrants were recorded at fair value upon issuance, with no recurring fair value measurement required. Additionally, the Company has derivative financial instruments that are recorded at fair value. Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would realize upon the sale or refinancing of such instruments. Industry Segment and Geographic Information The Company operates in the exploration and production segment of the oil and gas industry, onshore in the United States. The Company reports as a single industry segment. Off-Balance Sheet Arrangements The Company has not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or SPEs, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. The Company evaluates its transactions to determine if any variable interest entities exist. If it is determined that the Company is the primary beneficiary of a variable interest entity, that entity is consolidated. The Company has not been involved in any unconsolidated SPE transactions in 2020 or 2019. Recently Issued Accounting Standards In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, Leases (Topic 842) , followed by other related ASUs that provided targeted improvements and additional practical expedient options (collectively “ASU 2016-02” or “Topic 842”). The Company adopted ASU 2016-02 on January 1, 2019, using the modified retrospective method. The Company elected as part of its adoption to also use the optional transition methodology whereby lease accounting for previously reported periods continues to be reported in accordance with historical accounting guidance for leases in effect for those prior periods. Policy elections and practical expedients the Company implemented in connection with the adoption of ASU 2016-02 include (a) excluding from the balance sheet leases with terms that are less than one year, (b) for agreements that contain both lease and non-lease components, combining these components together and accounting for them as a single lease, (c) the package of practical expedients, which among other requirements, allows the Company to avoid reassessing contracts that commenced prior to adoption that were properly evaluated under legacy GAAP, and (d) excluding land easements that existed or expired before adoption of ASU 2016-02. The scope of ASU 2016-02 does not apply to leases used in the exploration or use of minerals, oil, natural gas, or other similar non-regenerative resources. Upon adoption on January 1, 2019, the Company recognized approximately $50.0 million in right-of-use (“ROU”) assets and related lease liabilities for its operating leases. There was no cumulative effect adjustment to retained earnings upon the adoption of this guidance. Please refer to Note 12 - Leases for additional discussion. In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments , followed by other related ASUs that provided targeted improvements (collectively “ASU 2016-13”). ASU 2016-13 provides financial statement users with more decision-useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. The Company adopted ASU 2016-13 on January 1, 2020, using the modified retrospective method, and there was no material impact to the Company’s accompanying consolidated financial statements or related disclosures. In August 2018, the FASB issued ASU No. 2018-15, Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”). ASU 2018-15 aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The Company adopted ASU 2018-15 on January 1, 2020, with prospective application, and there was no material impact to the Company’s accompanying consolidated financial statements or related disclosures. In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes (“ASU 2019-12”). ASU 2019-12 was issued as a means to reduce the complexity of accounting for income taxes for those entities that fall within the scope of the accounting standard. The guidance is to be applied using a prospective method, excluding amendments related to franchise taxes, which should be applied on either a retrospective basis for all periods presented or a modified retrospective basis through a cumulative-effect adjustment to retained earnings as of the beginning of the fiscal year of adoption. The Company adopted ASU 2019-12 on January 1, 2020, and there was no material impact on the Company’s accompanying consolidated financial statements or related disclosures. In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”) followed by ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), issued in January 2021 to provide clarifying guidance regarding the scope of Topic 848. ASU 2020-04 was issued to provide optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. Generally, the guidance is to be applied as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020, or prospectively from a date within an interim period that includes or is subsequent to March 12, 2020, up to the date that the financial statements are available to be issued. ASU 2020-04 and ASU 2021-01 are effective for all entities through December 31, 2022. As of December 31, 2020, the Company has not elected to use the optional guidance and continues to evaluate the options provided by ASU 2020-04 and ASU 2021-01. Please refer to Note 5 – Long-Term Debt for discussion of the use of the LIBOR in connection with borrowings under the Credit Agreement. In August 2020, the FASB issued ASU No. 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40) (“ASU 2020-06”). ASU 2020-06 was issued to reduce the complexity associated with accounting for certain financial instruments with characteristics of liabilities and equity. The guidance is to be applied using either a modified retrospective or a fully retrospective method. ASU 2020-06 is effective for fiscal years beginning after December 15, 2021, with early adoption permitted. The Company plans to adopt ASU 2020-06 on January 1, 2022, and does not expect a material impact on the Company’s accompanying consolidated financial statements or related disclosures. There are no other ASUs applicable to the Company that would have a material effect on the Company’s consolidated financial statements and related disclosures that have been issued but not yet adopted by the Company as of December 31, 2020, and through the filing of this report.

Revenue from Contracts with Cus

Revenue from Contracts with Customers	12 Months Ended
	Dec. 31, 2020
Revenue from Contract with Customer [Abstract]
Revenue from Contracts with Customer [Text Block]	Note 2 - Revenue from Contracts with Customers The Company recognizes its share of revenue from the sale of produced oil, gas, and NGLs from its Midland Basin and South Texas assets. Oil, gas, and NGL production revenue presented within the accompanying statements of operations is reflective of the revenue generated from contracts with customers. The tables below present oil, gas, and NGL production revenue by product type for each of the Company’s operating areas for the years ended December 31, 2020, 2019, and 2018: For the year ended December 31, 2020 Midland Basin South Texas Total (in thousands) Oil production revenue $ 802,494 $ 51,074 $ 853,568 Gas production revenue 76,759 110,700 187,459 NGL production revenue 324 84,837 85,161 Total $ 879,577 $ 246,611 $ 1,126,188 Relative percentage 78 % 22 % 100 % ____________________________________________ Note: Amounts may not calculate due to rounding. For the year ended December 31, 2019 Midland Basin South Texas Total (in thousands) Oil production revenue $ 1,119,786 $ 63,426 $ 1,183,212 Gas production revenue 75,827 186,702 262,529 NGL production revenue 123 139,886 140,009 Total $ 1,195,736 $ 390,014 $ 1,585,750 Relative percentage 75 % 25 % 100 % ____________________________________________ Note: Amounts may not calculate due to rounding. For the year ended December 31, 2018 Midland Basin South Texas Rocky Mountain (1) Total (in thousands) Oil production revenue $ 938,004 $ 72,821 $ 54,851 $ 1,065,676 Gas production revenue 125,603 227,252 1,595 354,450 NGL production revenue 1,000 214,441 790 216,231 Total $ 1,064,607 $ 514,514 $ 57,236 $ 1,636,357 Relative percentage 65 % 32 % 3 % 100 % ____________________________________________ Note: Amounts may not calculate due to rounding. (1) Following the divestiture of the Company’s remaining assets in the Rocky Mountain region during the first half of 2018, there has been no production revenue from this region after the second quarter of 2018. The Company recognizes oil, gas, and NGL production revenue at the point in time when custody and title (“control”) of the product transfers to the purchaser, which differs depending on the applicable contractual terms. Transfer of control drives the presentation of transportation, gathering, processing, and other post-production expenses (“fees and other deductions”) within the accompanying statements of operations. Fees and other deductions incurred by the Company prior to control transfer are recorded within the oil, gas, and NGL production expense line item on the accompanying statements of operations. When control is transferred at or near the wellhead, sales are based on a wellhead market price that is impacted by fees and other deductions incurred by the purchaser subsequent to the transfer of control. In general, the Company generates production revenue from a combination of the following types of contracts: • The Company sells oil and gas production at or near the wellhead and receives an agreed-upon market price from the purchaser. Under this type of arrangement, control transfers at or near the wellhead. • The Company has certain processing arrangements that include the delivery of unprocessed gas to a midstream processor’s facility for processing. Upon completion of processing, the midstream processor purchases the NGLs and redelivers residue gas back to the Company in-kind. For the NGLs extracted during processing, the midstream processor remits payment to the Company. For the residue gas taken in-kind, the Company has separate sales contracts where control transfers at points downstream of the processing facility. The Company also has certain oil sales that occur at market locations downstream of the production area. Given the structure of these arrangements and where control transfers, the Company separately recognizes fees and other deductions incurred prior to control transfer. These fees are recorded within the oil, gas, and NGL production expense line item on the accompanying statements of operations. Significant judgments made in applying the guidance in ASC Topic 606, Revenue from Contracts with Customers, relate to the point in time when control transfers to purchasers in gas processing arrangements with midstream processors. The Company does not believe that significant judgments are required with respect to the determination of the transaction price, including amounts that represent variable consideration, as volume and price carry a low level of estimation uncertainty given the precision of volumetric measurements and the use of index pricing with generally predictable differentials. Accordingly, the Company does not consider estimates of variable consideration to be constrained. The Company’s performance obligations arise upon the production of hydrocarbons from wells in which the Company has an ownership interest. The performance obligations are considered satisfied upon control transferring to a purchaser at the wellhead, inlet, or tailgate of the midstream processor’s processing facility, or other contractually specified delivery point. The time period between production and satisfaction of performance obligations is generally less than one day; thus, there are no material unsatisfied or partially unsatisfied performance obligations at the end of the reporting period. Revenue is recorded in the month when performance obligations are satisfied. However, settlement statements from the purchasers of hydrocarbons and the related cash consideration are received 30 to 90 days after production has occurred. As a result, the Company must estimate the amount of production delivered to the customer and the consideration that will ultimately be received for sale of the product. Estimated revenue due to the Company is recorded within the accounts receivable line item on the accompanying balance sheets until payment is received. The accounts receivable balances from contracts with customers within the accompanying balance sheets as of December 31, 2020, and 2019, were $108.9 million and $146.3 million, respectively. To estimate accounts receivable from contracts with customers, the Company uses knowledge of its properties, historical performance, contractual arrangements, index pricing, quality and transportation differentials, and other factors as the basis for these estimates. Differences between estimates and actual amounts received for product sales are recorded in the month that payment is received from the purchaser.

Acquisitions, Divestitures, and

Acquisitions, Divestitures, and Assets Held for Sale	12 Months Ended
	Dec. 31, 2020
Acquisitions, Divestitures, and Assets Held for Sale Disclosure [Abstract]
Acquisitions, Divestitures, and Assets Held for Sale	Note 3 – Acquisitions, Divestitures, and Assets Held for Sale 2020 Acquisition Activity During the third quarter of 2020, the Company completed a non-monetary acreage trade of primarily undeveloped properties located in Upton County, Texas, resulting in the exchange of approximately 535 net acres, with $6.5 million of carrying value attributed to the properties transferred by the Company. This trade was recorded at carryover basis with no gain or loss recognized. During the year ended December 31, 2020, the Company acquired approximately 380 net acres of proved and unproved properties located in Martin County, Texas, in two separate transactions which closed in 2020. Combined total cash consideration paid by the Company was $7.9 million. 2019 Acquisition Activity During 2019, the Company completed several non-monetary acreage trades of primarily undeveloped properties located in Howard, Martin, and Midland Counties, Texas, resulting in the exchange of approximately 2,200 net acres, with $73.4 million of carrying value attributed to the properties transferred by the Company. These trades were recorded at carryover basis with no gain or loss recognized. 2018 Acquisition Activity During the year ended December 31, 2018, the Company acquired approximately 1,030 net acres of primarily unproved properties located in Howard and Martin Counties, Texas, in two separate transactions which closed in 2018. Combined total cash consideration paid by the Company was $33.3 million. Under authoritative accounting guidance, these transactions were both individually considered to be asset acquisitions. Therefore, the properties were recorded based on the fair value of the total consideration transferred on the acquisition date and the transaction costs were capitalized as a component of the cost of the assets acquired. During the third quarter of 2018, the Company completed two non-monetary acreage trades of primarily undeveloped properties located in Howard and Martin Counties, Texas, which resulted in the exchange of approximately 2,650 net acres, with $95.1 million of carrying value attributed to the properties transferred by the Company. These trades were recorded at carryover basis with no gain or loss recognized. 2018 Divestiture Activity PRB Divestiture. On March 26, 2018, the Company completed the PRB Divestiture, divesting of approximately 112,000 net acres for total cash received at closing, net of costs (“net divestiture proceeds”), of $492.2 million, and recorded a final net gain of $410.6 million for the year ended December 31, 2018. Divide County Divestiture and Halff East Divestiture. During the second quarter of 2018, the Company completed the Divide County Divestiture and the Halff East Divestiture, for combined net divestiture proceeds of $252.2 million, and recorded a combined final net gain of $15.4 million for the year ended December 31, 2018. The Divide County Divestiture was considered a disposal of a significant asset group. The loss before income taxes from the Divide County, North Dakota assets sold for the year ended December 31, 2018, was $29.0 million. Loss before income taxes reflects oil, gas, and NGL production revenue, less oil, gas, and NGL production expense, depletion, depreciation, amortization, and asset retirement obligation liability accretion expense, impairment expense, and net loss on divestiture activity. The Company determined that executed asset sales in 2018 did not qualify for discontinued operations accounting under financial statement presentation authoritative guidance.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Income Taxes	Note 4 – Income Taxes The provision for income taxes consists of the following: For the Years Ended December 31, 2020 2019 2018 (in thousands) Current portion of income tax (expense) benefit Federal $ — $ 3,826 $ — State (449) (1,618) (1,662) Deferred portion of income tax (expense) benefit 192,540 41,835 (141,708) Income tax (expense) benefit $ 192,091 $ 44,043 $ (143,370) Effective tax rate 20.1 % 19.1 % 22.0 % The components of the net deferred tax liabilities are as follows: As of December 31, 2020 2019 (in thousands) Deferred tax liabilities Oil and gas properties excluding asset retirement obligation liabilities $ 83,816 $ 224,686 Derivative assets — 4,646 Other 10,054 12,361 Total deferred tax liabilities 93,870 241,693 Deferred tax assets Derivative liabilities 36,311 — Debt discount and deferred financing costs 23,925 — Asset retirement obligation liabilities 18,424 19,658 Credit carryover 7,543 11,270 Pension 7,183 5,971 Federal and state tax net operating loss carryovers 3,898 4,172 Stock compensation 2,701 3,503 Other liabilities 7,273 10,803 Total deferred tax assets 107,258 55,377 Valuation allowance (13,388) (3,070) Net deferred tax assets 93,870 52,307 Total net deferred tax liabilities $ — $ 189,386 Current federal income tax refundable $ — $ 3,885 Current state income tax payable $ 853 $ 1,404 As of December 31, 2020, the Company has recorded the utilization of its federal net operating loss (“NOL”) carryforward and has remaining state NOL carryforwards of $4.9 million. The state NOLs and de minimus state tax credits expire between 2021 and 2040. The Company has a federal research and development (“R&D”) credit carryforward of $7.5 million, which will expire between 2028 and 2033 if not used. The Company’s current valuation allowance relates to state NOL carryforwards and state tax credits, which are expected to expire before they can be utilized, and tax-effected unrealized derivative liabilities in excess of its net deferred liability balance. Recorded income tax expense or benefit differs from the amount that would be provided by applying the statutory United States federal income tax rate to income or loss before income taxes. These differences primarily relate to the effect of state income taxes, excess tax benefits and deficiencies from stock-based compensation awards, tax limitations on compensation of covered individuals, changes in valuation allowances, the cumulative impact of other smaller permanent differences, and can also reflect the cumulative effect of an enacted tax rate change, in the period of enactment, on the Company’s net deferred tax asset and liability balance. These differences are reported as follows: For the Years Ended December 31, 2020 2019 2018 (in thousands) Federal statutory tax (expense) benefit $ 200,908 $ 48,519 $ (136,873) (Increase) decrease in tax resulting from: State tax (expense) benefit (net of federal benefit) 5,722 (260) (2,771) Change in valuation allowance (10,318) 13 (105) Employee share-based compensation (2,578) (3,346) (2,508) Other (1,643) (883) (1,113) Income tax (expense) benefit $ 192,091 $ 44,043 $ (143,370) Acquisitions, divestitures, drilling activity, and basis differentials, which impact the prices received for oil, gas, and NGLs, impact the apportionment of taxable income to the states where the Company owns oil and gas properties. As these factors change, the Company’s state income tax rate changes. This change, when applied to the Company’s total temporary differences, impacts the total state income tax (expense) benefit reported in the current year. Items affecting state apportionment factors are evaluated upon completion of the prior year income tax return, after significant acquisitions and divestitures, if there are significant changes in drilling activity, or if estimated state revenue changes occur during the year. As a result of the 2018 divestitures, the Company’s state apportionment rate reflects its significant Texas presence. The Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”) was enacted on March 27, 2020. The primary feature of the CARES Act that the Company benefited from was the acceleration of its refundable Alternative Minimum Tax (“AMT”) credits. On April 1, 2020, the Company filed an election to accelerate its remaining refundable AMT credits of $7.6 million. The Company received the refund in July 2020. For all years before 2017, the Company is generally no longer subject to United States federal or state income tax examinations by tax authorities. The Company complies with authoritative accounting guidance regarding uncertain tax provisions. The entire amount of unrecognized tax benefit reported by the Company would affect its effective tax rate if recognized. Interest expense in the accompanying statements of operations includes a negligible amount associated with income taxes. The total amount recorded for unrecognized tax benefits for each of the years ended December 31, 2020, 2019, and 2018, was $446,000. The Company does not expect a significant change to the recorded unrecognized tax benefits in 2021.

Long-Term Debt

Long-Term Debt	Dec. 31, 2020
Debt Disclosure [Abstract]
Long-Term Debt	Note 5 – Long-Term Debt The following table summarizes the Company’s total outstanding balance on its revolving credit facility, Senior Secured Notes net of unamortized discount and deferred financing costs, and Senior Unsecured Notes, net of unamortized deferred financing costs, as of December 31, 2020, and 2019: As of December 31, 2020 As of December 31, 2019 (in thousands) Revolving credit facility $ 93,000 $ 122,500 Senior Secured Notes (1) 460,656 — Senior Unsecured Notes (1) 1,660,663 2,610,298 Total $ 2,214,319 $ 2,732,798 ____________________________________________ (1) Senior Secured Notes and Senior Unsecured Notes are defined below. During the year ended December 31, 2020, the Company executed multiple transactions to reduce outstanding debt. During the second quarter of 2020, the Company initiated an offer to exchange certain of its outstanding senior unsecured notes, as presented in the Senior Unsecured Notes section below (“Senior Unsecured Notes”), other than the 1.50% Senior Convertible Notes due 2021 (“2021 Senior Convertible Notes,” and together with the Senior Unsecured Notes, “Old Notes”), and entered into a private exchange of certain of its outstanding 2021 Senior Convertible Notes and portions of its outstanding Senior Unsecured Notes (“Private Exchange”), in each case for newly issued 10.0% Senior Secured Second Lien Notes due January 15, 2025 (“2025 Senior Secured Notes”), referred to together as “Exchange Offers.” In connection with the Exchange Offers, the Company and its lenders amended the Credit Agreement to increase the amount of permitted second lien indebtedness to an aggregate amount of $1.0 billion, inclusive of the 2021 Senior Convertible Notes (“Permitted Second Lien Debt”). Additionally, the Company amended the indenture governing its 2021 Senior Convertible Notes, by entering into the Third Supplemental Indenture, dated as of April 29, 2020 (“Third Supplemental Indenture”), to the original Indenture, dated as of May 21, 2015, as supplemented and amended by the Second Supplemental Indenture, dated as of August 12, 2016, collectively referred to as the (“2021 Notes Indenture”). The Third Supplemental Indenture provides that the Company will satisfy any conversion obligation solely in cash. On June 17, 2020 (“Settlement Date”), the Company exchanged $611.9 million in aggregate principal amount of Senior Unsecured Notes and $107.0 million in aggregate principal amount of 2021 Senior Convertible Notes for $446.7 million in aggregate principal amount of 2025 Senior Secured Notes, as well as, in connection with the Private Exchange, (a) $53.5 million in cash to certain holders of the 2021 Senior Convertible Notes and (b) warrants to acquire up to an aggregate of approximately 5.9 million shares, or approximately five percent of its outstanding common stock, exercisable upon the occurrence of certain future triggering events, to certain holders who exchanged Old Notes in the Private Exchange. Please refer to Note 11 – Fair Value Measurements for more information regarding the warrants issued by the Company. Pursuant to the 2021 Notes Indenture, upon the issuance of Permitted Second Lien Debt, the remaining outstanding 2021 Senior Convertible Notes became secured and are subsequently referred to as the “2021 Senior Secured Convertible Notes,” and together with the 2025 Senior Secured Notes, the “Senior Secured Notes.” For a summary of the principal amounts of the Senior Unsecured Notes tendered as of the Settlement Date, please refer to the Senior Unsecured Notes section below. The Company retired $611.9 million and $107.0 million in aggregate principal amount of its Senior Unsecured Notes and 2021 Senior Convertible Notes, respectively, upon the closing of the Exchange Offers. Upon closing, the Company paid $8.9 million of accrued and unpaid interest and accelerated $5.6 million of previously unamortized deferred financing costs associated with the retired Senior Unsecured Notes and 2021 Senior Convertible Notes and accelerated $6.1 million of previously unamortized debt discount associated with the retired 2021 Senior Convertible Notes. The Exchange Offers resulted in a net gain on extinguishment of debt of $227.3 million. The Company cancelled all retired Senior Unsecured Notes and 2021 Senior Convertible Notes upon the closing of the Exchange Offers. Additionally, during 2020, in open market transactions, the Company repurchased a total of $190.3 million in aggregate principal amount of its 2022 Senior Notes and 2024 Senior Notes for a total settlement amount, excluding accrued interest, of $136.5 million. In connection with the repurchases, the Company recorded a net gain on extinguishment of debt of $52.8 million for the year ended December 31, 2020. This amount included discounts realized upon repurchase of $53.8 million partially offset by approximately $1.0 million of accelerated unamortized deferred financing costs. The Company canceled all repurchased 2022 Senior Notes and 2024 Senior Notes upon settlement. Please refer to the Credit Agreement and Senior Notes sections below for additional information. Credit Agreement The Company’s Credit Agreement provides for a senior secured revolving credit facility with a maximum loan amount of $2.5 billion. During the second quarter of 2020, as a result of lower commodity prices and a corresponding decrease in the value of the Company’s proved reserves, the borrowing base and aggregate lender commitments under the Credit Agreement were both reduced to $1.1 billion. Also during the second quarter of 2020, the Company entered into the Third Amendment and the Fourth Amendment to the Credit Agreement (collectively, the “Amendments”), which permitted the Company to incur new second lien debt of up to $827.5 million prior to October 1, 2020, provided that all principal amounts of such debt are used to redeem unsecured senior debt of the Company for less than or equal to 80% of par value. The Amendments also permitted the Company to grant a second-priority security interest to the holders of the Company’s outstanding 2021 Senior Convertible Notes to secure the Company’s obligations under the 2021 Senior Convertible Notes. Additionally, the Amendments reduced the amount of dividends that the Company may declare and pay on an annual basis from $50.0 million to $12.0 million. During the fourth quarter of 2020, the Company and its lenders completed the fall semi-annual borrowing base redetermination and entered into the Fifth Amendment to the Credit Agreement, which reaffirmed the Company’s borrowing base and aggregate lender commitments at existing levels and extended the Company’s ability to incur Permitted Second Lien Debt until the next scheduled borrowing base redetermination date of April 1, 2021. As of December 31, 2020, the Company had $380.8 million of available Permitted Second Lien Debt capacity. The Credit Agreement is scheduled to mature on September 28, 2023, except that, pursuant to the Amendments, newly issued Permitted Second Lien Debt used to redeem any portion of the remaining 2022 Senior Notes must have maturities on or after 180 days after September 28, 2023; otherwise, the maturity date of the Credit Agreement will be July 2, 2023. Without regard to which maturity date is in effect, the maturity date could occur earlier on August 16, 2022, if the Company has not completed certain repurchase, redemption, or refinancing activities associated with its 2022 Senior Notes, and does not have certain unused availability for borrowing under the Credit Agreement, as outlined in the Credit Agreement. Interest and commitment fees associated with the revolving credit facility are accrued based on a borrowing base utilization grid set forth in the Credit Agreement. The Third Amendment to the Credit Agreement amended the borrowing base utilization grid as presented in the table below. At the Company’s election, borrowings under the Credit Agreement may be in the form of Eurodollar, Alternate Base Rate (“ABR”), or Swingline loans. Eurodollar loans accrue interest at LIBOR, plus the applicable margin from the utilization grid, and ABR and Swingline loans accrue interest at a market-based floating rate, plus the applicable margin from the utilization grid. Commitment fees are accrued on the unused portion of the aggregate lender commitment amount at rates from the utilization grid and are included in the interest expense line item on the accompanying statements of operations. Borrowing Base Utilization Percentage <25% ≥25% <50% ≥50% <75% ≥75% <90% ≥90% Eurodollar Loans (1) 1.750 % 2.000 % 2.500 % 2.750 % 3.000 % ABR Loans or Swingline Loans 0.750 % 1.000 % 1.500 % 1.750 % 2.000 % Commitment Fee Rate 0.375 % 0.375 % 0.500 % 0.500 % 0.500 % ____________________________________________ (1) The Credit Agreement specifies that if LIBOR is no longer a widely used benchmark rate, or if it is no longer used for determining interest rates for loans in the United States, a replacement interest rate that fairly reflects the cost to the lenders of funding loans shall be established by the Administrative Agent, as defined in the Credit Agreement, in consultation with the Company. Please refer to Note 1 – Summary of Significant Accounting Policies for discussion of FASB ASU 2020-04, which provides guidance related to reference rate reform . The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Credit Agreement as of February 4, 2021, December 31, 2020, and December 31, 2019: As of February 4, 2021 As of December 31, 2020 As of December 31, 2019 (in thousands) Revolving credit facility (1) $ 121,500 $ 93,000 $ 122,500 Letters of credit (2) 42,000 42,000 — Available borrowing capacity 936,500 965,000 1,077,500 Total aggregate lender commitment amount $ 1,100,000 $ 1,100,000 $ 1,200,000 ____________________________________________ (1) Unamortized deferred financing costs attributable to the revolving credit facility are presented as a component of the other noncurrent assets line item on the accompanying balance sheets and totaled $4.3 million and $5.9 million as of December 31, 2020, and 2019, respectively. These costs are being amortized over the term of the revolving credit facility on a straight-line basis. (2) Letters of credit outstanding reduce the amount available under the revolving credit facility on a dollar-for-dollar basis. Senior Notes Senior Secured Notes. Senior Secured Notes, net of unamortized debt discount and deferred financing costs, included within the Senior Notes, net line item on the accompanying balance sheets as of December 31, 2020, consisted of the following: As of December 31, 2020 Principal Amount Unamortized Debt Discount Unamortized Deferred Financing Costs Net (in thousands) 10.0% Senior Secured Notes due 2025 $ 446,675 $ 37,943 $ 11,558 $ 397,174 1.50% Senior Secured Convertible Notes due 2021 (1) 65,485 1,828 175 63,482 Total $ 512,160 $ 39,771 $ 11,733 $ 460,656 ____________________________________________ (1) As discussed above, as required by the 2021 Notes Indenture and as permitted by the Credit Agreement, as the Company issued Permitted Second Lien Debt upon the closing of the Exchange Offers, its remaining 2021 Senior Convertible Notes contemporaneously became secured. 2025 Senior Secured Notes . On June 17, 2020, the Company issued $446.7 million in aggregate principal amount of 2025 Senior Secured Notes due January 15, 2025. The Company incurred fees of $13.1 million, which are being amortized as deferred financing costs over the life of the 2025 Senior Secured Notes. Upon the issuance of the 2025 Senior Secured Notes, the Company recorded $405.0 million as the initial carrying amount, which approximated their fair value at issuance. The excess of the principal amount of the 2025 Senior Secured Notes over its fair value was recorded as a debt discount. The debt discount and deferred financing costs are amortized to interest expense through the maturity date. In connection with the issuance of the 2025 Senior Secured Notes, the Company entered into an indenture dated as of June 17, 2020 with UMB Bank, N.A., as trustee, governing the 2025 Senior Secured Notes (“2025 Notes Indenture”). The Company may redeem some or all of its 2025 Senior Secured Notes prior to their maturity at redemption prices based on a premium, plus accrued and unpaid interest as described in the 2025 Notes Indenture. The 2025 Senior Secured Notes are senior obligations of the Company, secured on a second-priority basis, ranking junior to the Company’s obligations under the Credit Agreement and equal in priority with the 2021 Senior Secured Convertible Notes. The 2025 Senior Secured Notes rank senior in right of payment with all of the Company’s existing and any future unsecured senior or subordinated debt. 2021 Senior Secured Convertible Notes . On August 12, 2016, the Company issued $172.5 million in aggregate principal amount of 1.50% Senior Convertible Notes due July 1, 2021, unless earlier converted. The Company received net proceeds of $166.6 million after deducting fees of $5.9 million, of which a portion is being amortized over the life of the 2021 Senior Convertible Notes. Upon the issuance of the 2021 Senior Convertible Notes, the Company recorded $132.3 million as the initial carrying amount of the debt component, which approximated its fair value at issuance, and, was estimated by using an interest rate for nonconvertible debt with terms similar to the Senior Convertible Notes. The effective interest rate used was 7.25%. The $40.2 million excess of the principal amount of the 2021 Senior Convertible Notes over the fair value of the debt component was recorded as a debt discount and a corresponding increase in additional paid-in capital. The Company incurred fees of $5.9 million relating to the issuance of the 2021 Senior Convertible Notes, which were allocated between the debt and equity components in proportion to their determined fair value amounts. During the second quarter of 2020, pursuant to the Third Supplemental Indenture, the Company agreed to satisfy any conversion obligation solely in cash, resulting in reclassification of the fair value of the equity components out of additional paid-in capital. As of December 31, 2019, the net carrying amount of the equity component of the Senior Convertible Notes recorded in additional paid-in capital on the accompanying balance sheets was $33.6 million. The debt discount and debt-related issuance costs are being amortized to the principal value of the 2021 Senior Secured Convertible Notes as interest expense through the maturity date. Interest expense recognized on the 2021 Senior Secured Convertible Notes related to the stated interest rate and amortization of the debt discount totaled $7.7 million, $11.0 million, and $10.5 million for the years ended December 31, 2020, 2019, and 2018, respectively. Upon the closing of the Exchange Offers, the Company retired $107.0 million in aggregate principal amount of its 2021 Senior Convertible Notes. Upon issuance of the 2025 Senior Secured Notes, which was Permitted Second Lien Debt, as required by the 2021 Notes Indenture, and as permitted by the Credit Agreement, the remaining 2021 Senior Convertible Notes became secured senior obligations of the Company on a second-priority basis, ranking junior to the Company’s obligations under the Credit Agreement and equal in priority with the 2025 Senior Secured Notes. The 2021 Senior Secured Convertible Notes rank senior in right of payment to all of the Company’s existing and any future unsecured senior or subordinated debt. Prior to January 1, 2021, holders could convert their 2021 Senior Convertible Notes at their option only under certain circumstances as defined by the 2021 Notes Indenture. The 2021 Senior Secured Convertible Notes were not convertible at the option of holders as of December 31, 2020. Notwithstanding the inability to convert as of December 31, 2020, the if-converted value of the 2021 Senior Secured Convertible Notes did not exceed the principal amount as of December 31, 2020, or through the filing of this report. On or after January 1, 2021, until the maturity date, holders may convert their 2021 Senior Secured Convertible Notes at any time. Holders may convert their notes based on a conversion rate of 24.6914 shares of the Company’s common stock per $1,000 principal amount of the 2021 Senior Secured Convertible Notes, which is equal to an initial conversion price of approximately $40.50 per share, subject to adjustment. The Company may not redeem the 2021 Senior Convertible Notes prior to the maturity date. The Company has the ability, and currently intends to settle its 2021 Senior Secured Convertible Notes obligation, due July 1, 2021, with borrowings under its revolving credit facility. If the Company undergoes a fundamental change, as defined by the 2021 Notes Indenture, holders of the 2021 Senior Secured Convertible Notes may require the Company to repurchase for cash all or any portion of their notes at a fundamental change repurchase price equal to 100% of the principal amount of the 2021 Senior Secured Convertible Notes to be repurchased, plus accrued and unpaid interest. The 2021 Notes Indenture contains customary events of default with respect to the 2021 Senior Secured Convertible Notes, including that upon certain events of default, the trustee by notice to the Company, or the holders of at least 25% in principal amount of the outstanding 2021 Senior Secured Convertible Notes by notice to the Company, may declare 100% of the principal and accrued and unpaid interest, if any, due and payable immediately. In case of certain events of bankruptcy, insolvency or reorganization involving the Company or a significant subsidiary, 100% of the principal and accrued and unpaid interest on the Senior Convertible Notes will automatically become due and payable. In connection with the issuance of the 2021 Senior Convertible Notes, the Company entered into capped call transactions with affiliates of the underwriters of such issuance. The aggregate cost of the capped call transactions was approximately $24.2 million. The capped call transactions are generally expected to partially offset any cash payments the Company is required to make in excess of the principal amount of converted 2021 Senior Secured Convertible Notes in the event that the market price per share of the Company’s common stock is greater than the strike price of the capped call transactions, which initially corresponds to the approximate $40.50 per share conversion price of the 2021 Senior Secured Convertible Notes. The cap price of the capped call transactions is initially $60.00 per share. If the market price per share exceeds the cap price of the capped call transactions, there would not be an offset of such potential cash payments. The Company classified the costs associated with the capped call transactions as equity instruments with no recurring fair value measurement recorded. As discussed above, during the second quarter of 2020, the fair value of this equity instrument was reclassified out of additional paid-in capital upon the Company’s agreement to satisfy any conversion obligation solely in cash. Senior Unsecured Notes Senior Unsecured Notes, net of unamortized deferred financing costs, included within the Senior Notes, net line item on the accompanying balance sheets as of December 31, 2020, and 2019, consisted of the following: As of December 31, 2020 As of December 31, 2019 Principal Amount Unamortized Deferred Financing Costs Principal Amount, Net Principal Amount Unamortized Deferred Financing Costs Principal Amount, Net (in thousands) 6.125% Senior Notes due 2022 $ 212,403 $ 855 $ 211,548 $ 476,796 $ 2,920 $ 473,876 5.0% Senior Notes due 2024 277,034 1,576 275,458 500,000 3,766 496,234 5.625% Senior Notes due 2025 349,118 2,792 346,326 500,000 4,903 495,097 6.75% Senior Notes due 2026 419,235 3,970 415,265 500,000 5,571 494,429 6.625% Senior Notes due 2027 416,791 4,725 412,066 500,000 6,601 493,399 1.50% Senior Convertible Notes due 2021 (1)(2) — — — 172,500 15,237 157,263 Total $ 1,674,581 $ 13,918 $ 1,660,663 $ 2,649,296 $ 38,998 $ 2,610,298 ____________________________________________ (1) Unamortized deferred financing costs attributable to the 2021 Senior Convertible Notes include $13.9 million related to the unamortized debt discount as of December 31, 2019. (2) As discussed above, as required by the 2021 Notes Indenture and as permitted by the Credit Agreement, as the Company issued Permitted Second Lien Debt upon the closing of the Exchange Offers, its remaining 2021 Senior Convertible Notes contemporaneously became secured. The senior unsecured notes listed above (collectively referred to as “Senior Unsecured Notes,” and together with the Senior Secured Notes, “Senior Notes”) are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt and are senior in right of payment to any future subordinated debt. The Company may redeem some or all of its Senior Unsecured Notes prior to their maturity at redemption prices based on a premium, plus accrued and unpaid interest as described in the indentures governing the Senior Unsecured Notes. Upon the closing of the Exchange Offers, the Company retired $611.9 million in aggregate principal amount of its Senior Unsecured Notes. Portions of the then-outstanding principal amount of each series of our Senior Unsecured Notes listed below were tendered and retired in connection with the Exchange Offers. The following table summarizes the principal amounts of the Senior Unsecured Notes tendered as of the Settlement Date: Title of Senior Unsecured Notes Tendered Principal Amount of Senior Unsecured Notes Tendered (in thousands) 6.125% Senior Notes due 2022 $ 141,701 5.0% Senior Notes due 2024 155,339 5.625% Senior Notes due 2025 150,882 6.75% Senior Notes due 2026 80,765 6.625% Senior Notes due 2027 83,209 Total $ 611,896 2022 Senior Notes. On November 17, 2014, the Company issued $600.0 million in aggregate principal amount of 6.125% Senior Notes due 2022 at par, which mature on November 15, 2022. The Company received net proceeds of $590.0 million after deducting fees of $10.0 million, which are being amortized as deferred financing costs over the life of the 2022 Senior Notes. During 2016, the Company repurchased $38.2 million in aggregate principal amount of its 2022 Senior Notes for a settlement amount of $24.3 million, excluding accrued interest. During 2018, the Company retired $85.0 million of its 2022 Senior Notes for a total settlement amount of $88.1 million, excluding accrued interest. During 2020, the Company repurchased $122.7 million in aggregate principal amount of its 2022 Senior Notes for a settlement amount of $94.2 million, excluding accrued interest. 2024 Senior Notes. On May 20, 2013, the Company issued $500.0 million in aggregate principal amount of 5.0% Senior Notes due 2024 at par, which mature on January 15, 2024. The Company received net proceeds of $490.2 million after deducting fees of $9.8 million, which are being amortized as deferred financing costs over the life of the 2024 Senior Notes. During 2020, the Company repurchased $67.6 million in aggregate principal amount of its 2024 Senior Notes for a total settlement amount of $42.3 million, excluding accrued interest. 2025 Senior Notes. On May 21, 2015, the Company issued $500.0 million in aggregate principal amount of 5.625% Senior Notes due 2025 at par, which mature on June 1, 2025. The Company received net proceeds of $491.0 million after deducting fees of $9.0 million, which are being amortized as deferred financing costs over the life of the 2025 Senior Notes. 2026 Senior Notes. On September 12, 2016, the Company issued $500.0 million in aggregate principal amount of 6.75% Senior Notes due 2026, at par, which mature on September 15, 2026. The Company received net proceeds of $491.6 million after deducting fees of $8.4 million, which are being amortized as deferred financing costs over the life of the 2026 Senior Notes. 2027 Senior Notes. On August 20, 2018, the Company issued $500.0 million in aggregate principal amount of 6.625% Senior Notes due 2027, at par, which mature on January 15, 2027. The Company received net proceeds of $492.1 million after deducting fees of $7.9 million, which are being amortized as deferred financing costs over the life of the 2027 Senior Notes. Covenants The Company is subject to certain financial and non-financial covenants under the Credit Agreement and the indentures governing the Senior Notes that, among other terms, limit the Company’s ability to incur additional indebtedness, make restricted payments including dividends, sell assets, with respect to the Company’s restricted subsidiaries, permit the consensual restriction on the ability of such restricted subsidiaries to pay dividends or indebtedness owing to the Company or to any other restricted subsidiaries, create liens that secure debt, enter into transactions with affiliates, and merge or consolidate with another company. The financial covenants under the Credit Agreement require that the Company’s (a) total funded debt, as defined in the Credit Agreement, to 12-month trailing adjusted EBITDAX ratio cannot be greater than 4.00 to 1.00 on the last day of each fiscal quarter; and (b) adjusted current ratio, as defined in the Credit Agreement, cannot be less than 1.00 to 1.00 as of the last day of any fiscal quarter. The Company was in compliance with all covenants under the Credit Agreement and the indentures governing the Senior Notes as of December 31, 2020, and through the filing of this report. Capitalized Interest Capitalized interest costs for the years ended December 31, 2020, 2019, and 2018, totaled $15.8 million, $18.5 million, and $20.6 million, respectively. The amount of interest the Company capitalizes generally fluctuates based on the amount borrowed, the Company’s capital program, and the timing and amount of costs associated with capital projects that are considered in progress. Capitalized interest costs are included in total costs incurred. Please refer to Costs Incurred in Overview of the Company in Part II, Item 7, and Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 6 – Commitments and Contingencies Commitments As of December 31, 2020, the Company has entered into various agreements, which include drilling rig contracts of $5.9 million, gathering, processing, transportation throughput, and delivery commitments of $161.6 million, office leases, including maintenance, of $22.1 million, fixed price contracts to purchase electricity of $45.4 million, and other miscellaneous contracts and leases of $14.3 million. As of December 31, 2020, the annual minimum payments for the next five years and total minimum payments thereafter are presented below: For the Years Ending December 31, Amount (in thousands) 2021 $ 86,776 2022 79,919 2023 45,474 2024 12,455 2025 11,463 Thereafter 13,233 Total $ 249,320 Drilling Rig and Completion Service Contracts. The Company has drilling rig and completion service contracts in place to facilitate its drilling and completion plans. During the twelve months ended December 31, 2020, and through the filing of this report, the Company entered into new and amended drilling rig contracts resulting in the reduction of day rates and potential early termination fees and the extension of contract terms. As of the filing of this report, the Company’s drilling rig commitments totaled $19.9 million under contract terms extending through the first quarter of 2022. If all of these contracts were terminated as of the filing of this report, the Company would avoid a portion of the contractual service commitments; however, the Company would be required to pay $11.6 million in early termination fees. Excluded from these amounts are variable commitments and potential penalties determined by the number of completion crews the Company has in operation in a particular area under a completion service agreement. As of December 31, 2020, potential penalties under this completion service agreement, which expires on December 31, 2023, range from zero to a maximum of $10.1 million. No material expenses related to early termination or standby fees were incurred by the Company during the year ended December 31, 2020, and the Company does not expect to incur material penalties with regard to its drilling rig and completion service contracts during 2021. Pipeline Transportation Commitments. The Company has gathering, processing, transportation throughput, and delivery commitments with various third-parties that require delivery of a minimum amount of oil, gas, and produced water. As of December 31, 2020, the Company has commitments to deliver a minimum of 16 MMBbl of oil and 257 Bcf of gas through 2024, and 17 MMBbl of produced water through 2027. The Company will be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments under certain agreements. As of December 31, 2020, if the Company fails to deliver any product, as applicable, the aggregate undiscounted deficiency payments total approximately $161.6 million. This amount does not include deficiency payment estimates associated with approximately 11.9 MMBbl of future oil delivery commitments where the Company cannot predict with accuracy the amount and timing of these payments, as such payments are dependent upon the price of oil in effect at the time of settlement. The Company expects to fulfill the delivery commitments from a combination of production from existing productive wells, future development of proved undeveloped reserves, and future development of resources not yet characterized as proved reserves. Under certain of the Company’s commitments, if the Company is unable to deliver the minimum quantity from its production, it may deliver production acquired from third-parties to satisfy its minimum volume commitments. As of the filing of this report, the Company does not expect to incur material shortfalls with regard to these commitments. Office Leases. The Company leases office space under various operating leases with terms extending as far as 2026. Rent expense for the years ended December 31, 2020, 2019, and 2018, was $5.4 million, $5.5 million, and $4.5 million, respectively. Electrical Power Purchase Contracts. As of December 31, 2020, the Company had a fixed price contract for the purchase of electrical power through 2027 with a total remaining obligation of $45.4 million. Delivery and Purchase Commitments. As of December 31, 2020, the Company had a sand sourcing agreement with certain commitments and potential penalties that vary based on the amount of sand the Company uses in well completions occurring in a particular area. This sand sourcing agreement expires on December 31, 2023. As of December 31, 2020, potential penalties under this sand sourcing agreement range from zero to a maximum of $10.0 million. The Company does not expect to incur penalties with regard to this agreement. Drilling and Completion Commitments. During the second quarter of 2020, the Company entered into an agreement that included minimum drilling and completion footage requirements on certain existing leases in South Texas. If these minimum requirements are not satisfied by March 31, 2021, the Company will be required to pay liquidated damages based on the difference between the actual footage drilled and completed and the minimum requirements. As of December 31, 2020, the liquidated damages could range from zero to a maximum of $26.9 million, with the maximum exposure assuming no additional development activity occurred prior to March 31, 2021. The Company also entered into an agreement that included a minimum number of wells drilled and completed on certain existing leases in South Texas. If these minimum requirements are not satisfied by December 31, 2021, the Company will be required to pay liquidated damages based on the difference between the actual number of wells drilled and completed and the minimum requirements. As of December 31, 2020, the liquidated damages could range from zero to a maximum of $11.5 million, with the maximum exposure assuming no additional development activity occurred prior to December 31, 2021. No liquidated damages related to these agreements were incurred by the Company during the year ended December 31, 2020, and the Company expects to meet its obligations under both agreements. Contingencies The Company is subject to litigation and claims arising in the ordinary course of business. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. In the opinion of management, the anticipated results of any pending litigation and claims are not expected to have a material effect on the results of operations, the financial position, or the cash flows of the Company.

Compensation Plans

Compensation Plans	12 Months Ended
	Dec. 31, 2020
Share-based Payment Arrangement [Abstract]
Compensation Plans	Note 7 – Compensation Plans Equity Incentive Compensation Plan There are several components to the Company’s Equity Plan that are described in this section. As of December 31, 2020, approximately 3.8 million shares of common stock were available for grant under the Equity Plan. The issuance of a direct share benefit, such as a share of common stock, a stock option, a restricted share, an RSU, or a PSU, counts as one share against the number of shares available to be granted under the Equity Plan. Each PSU has the potential to count as two shares against the number of shares available to be granted under the Equity Plan based on the final performance multiplier. Performance Share Units The Company generally grants PSUs to eligible employees as part of its Equity Plan. The number of shares of the Company’s common stock issued to settle PSUs ranges from zero to two times the number of PSUs awarded and is determined based on certain criteria over a three six three six The fair value of PSUs is measured at the grant date with a stochastic Monte Carlo simulation using geometric Brownian motion (“GBM Model”). A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company’s PSUs, the Company cannot predict with certainty the path its stock price or the stock prices of its peers will take over the three For PSUs granted in 2017, which the Company determined to be equity awards, the settlement criteria included a combination of the Company’s Total Shareholder Return (“TSR”) on an absolute basis, and the Company’s TSR relative to the TSR of certain peer companies over the associated three-year performance period. The fair value of the PSUs granted in 2017 was measured on the grant date using the GBM Model. As these awards depended entirely on market-based settlement criteria, the associated compensation expense was recognized on a straight-line basis within general and administrative expense and exploration expense over the vesting period of the awards. These awards fully vested during 2020 and were settled as discussed below. For PSUs granted in 2018 and 2019, the settlement criteria include a combination of the Company’s TSR relative to the TSR of certain peer companies and the Company’s cash return on total capital invested (“CRTCI”) relative to the CRTCI of certain peer companies over the associated three-year performance period. In addition to these performance criteria, the award agreements for these grants also stipulate that if the Company’s absolute TSR is negative over the three CRTCI performance condition will be met at the target amount at the end of the respective performance periods. Compensation expense for PSUs is recognized within general and administrative expense and exploration expense over the vesting periods of the respective awards. As these awards depend on a combination of performance-based settlement criteria and market-based settlement criteria, compensation expense may be adjusted in future periods as the number of units expected to vest increases or decreases based on the Company’s expected CRTCI performance relative to the applicable peer companies. The Company records compensation expense associated with the issuance of PSUs based on the fair value of the awards as of the date of grant. Total compensation expense recorded for PSUs was $4.4 million, $10.9 million, and $10.3 million for the years ended December 31, 2020, 2019, and 2018, respectively. As of December 31, 2020, there was $4.4 million of total unrecognized expense related to PSUs, which is being amortized through 2022. A summary of the status and activity of non-vested PSUs is presented in the following table: For the Years Ended December 31, 2020 2019 2018 PSUs (1) Weighted-Average Grant-Date Fair Value PSUs (1) Weighted-Average Grant-Date Fair Value PSUs (1) Weighted-Average Grant-Date Fair Value Non-vested at beginning of year 2,022,585 $ 16.87 1,711,259 $ 20.68 1,533,491 $ 22.97 Granted — $ — 793,125 $ 12.80 572,924 $ 24.45 Vested (792,572) $ 15.85 (346,021) $ 26.32 (233,102) $ 44.25 Forfeited (399,549) $ 17.56 (135,778) $ 16.98 (162,054) $ 21.79 Non-vested at end of year 830,464 $ 17.52 2,022,585 $ 16.87 1,711,259 $ 20.68 ____________________________________________ (1) The number of shares of common stock assumes a multiplier of one. The actual final number of shares of common stock to be issued will range from zero to two times the number of PSUs awarded depending on the three The fair value of the PSUs granted in 2019, and 2018, was $10.2 million and $14.0 million, respectively. During the year ended December 31, 2020, the Company settled PSUs that were granted in 2017, which earned a 0.9 times multiplier. The Company and the majority of grant participants mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings, as provided for in the Equity Plan and applicable award agreements. After withholding 215,451 shares to satisfy income and payroll tax withholding obligations that occurred upon delivery of the shares underlying those PSUs, 485,060 shares of the Company’s common stock were issued in accordance with the terms of the applicable PSU awards. During the years ended December 31, 2019, and 2018, PSUs that were granted in 2016, and 2015, respectively, did not satisfy the minimum performance requirements. This resulted in a multiplier of zero times and therefore no shares of common stock were issued upon settlement. The total fair value of PSUs that vested during the years ended December 31, 2020, 2019, and 2018, was $12.6 million, $9.1 million, and $10.3 million, respectively. Employee Restricted Stock Units The Company grants RSUs to eligible persons as part of its Equity Plan. Each RSU represents a right to receive one share of the Company’s common stock upon settlement of the award at the end of the specified vesting period. RSUs generally vest one-third of the total grant on each anniversary date of the grant over the applicable vesting period or upon other triggering events as set forth in the Equity Plan. Employees who are retirement eligible at the time an RSU award is granted, vest in each portion of that award equally in six six The Company records compensation expense associated with the issuance of RSUs based on the fair value of the awards as of the date of grant. The fair value of an RSU is equal to the closing price of the Company’s common stock on the day of the grant. Compensation expense for RSUs is recognized within general and administrative expense and exploration expense over the vesting periods of the respective awards. Total compensation expense recorded for employee RSUs for the years ended December 31, 2020, 2019, and 2018, was $8.7 million, $11.1 million, and $10.8 million, respectively. As of December 31, 2020, there was $14.7 million of total unrecognized compensation expense related to non-vested RSU awards, which is being amortized through 2023. A summary of the status and activity of non-vested RSUs granted to employees is presented in the following table: For the Years Ended December 31, 2020 2019 2018 RSUs Weighted- RSUs Weighted- RSUs Weighted- Non-vested at beginning of year 1,532,131 $ 16.01 1,243,163 $ 21.50 1,244,262 $ 20.25 Granted 1,458,869 $ 5.98 978,932 $ 12.36 583,552 $ 25.77 Vested (746,132) $ 16.74 (466,535) $ 21.94 (407,529) $ 24.30 Forfeited (147,008) $ 15.34 (223,429) $ 18.16 (177,122) $ 17.26 Non-vested at end of year 2,097,860 $ 8.83 1,532,131 $ 16.01 1,243,163 $ 21.50 The fair value of RSUs granted to eligible employees in 2020, 2019, and 2018, was $8.7 million, $12.1 million, and $15.0 million, respectively. A summary of the shares of common stock issued to settle employee RSUs is presented in the table below: For the Years Ended December 31, 2020 2019 2018 Shares of common stock issued to settle RSUs (1) 746,132 466,535 407,529 Less: shares of common stock withheld for income and payroll taxes (209,173) (132,136) (115,784) Net shares of common stock issued 536,959 334,399 291,745 ____________________________________________ (1) During the years ended December 31, 2020, 2019, and 2018, the Company issued shares of common stock to settle RSUs that related to awards granted in previous years. The Company and a majority of grant recipients mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings in accordance with the Company’s Equity Plan and individual award agreements. The total fair value of employee RSUs that vested during the years ended December 31, 2020, 2019, and 2018, was $12.5 million, $10.2 million, and $9.9 million, respectively. Director Shares In 2020, 2019, and 2018, the Company issued 267,576, 96,719, and 63,741 shares, respectively, of its common stock to its non-employee directors under the Equity Plan. For the years ended December 31, 2020, 2019, and 2018, the Company recorded $990,000, $1.2 million, and $1.7 million, respectively, of compensation expense related to director shares and RSUs issued. All shares issued to non-employee directors fully vest on December 31 of the year granted. Employee Stock Purchase Plan Under the Company’s Employee Stock Purchase Plan (“ESPP”), eligible employees may purchase shares of the Company’s common stock through payroll deductions of up to 15 percent of eligible compensation, without accruing in excess of $25,000 in value from purchases for each calendar year. The purchase price of the stock is 85 percent of the lower of the fair market value of the stock on either the first or last day of the purchase period. The ESPP is intended to qualify under Section 423 of the IRC. The Company had approximately 834,246 shares of its common stock available for issuance under the ESPP as of December 31, 2020. There were 464,757, 314,868, and 199,464 shares issued under the ESPP in 2020, 2019, and 2018, respectively. Total proceeds to the Company for the issuance of these shares was $1.5 million for the year ended December 31, 2020, and $3.2 million for each of the years ended 2019 and 2018. The fair value of ESPP grants is measured at the date of grant using the Black-Scholes option-pricing model. Expected volatility is calculated based on the Company’s historical daily common stock price, and the risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with a six-month vesting period. The fair value of ESPP shares issued during the periods reported were estimated using the following weighted-average assumptions: For the Years Ended December 31, 2020 2019 2018 Risk free interest rate 0.8 % 2.3 % 1.8 % Dividend yield 0.7 % 0.7 % 0.4 % Volatility factor of the expected market price of the Company’s common stock 166.2 % 56.6 % 55.9 % Expected life (in years) 0.5 0.5 0.5 The Company expensed $874,000 for the year ended December 31, 2020, and $1.1 million for each of the years ended December 31, 2019, and 2018, based on the estimated fair value of the ESPP grants. 401(k) Plan The Company has a defined contribution plan (the “401(k) Plan”) that is subject to the Employee Retirement Income Security Act of 1974. The 401(k) Plan allows eligible employees to contribute a maximum of 60 percent of their base salaries up to the contribution limits established under the IRC. For employees hired before December 31, 2014, the Company matches 100 percent of each employee’s contribution in cash on a dollar for dollar basis, up to six percent of the employee’s base salary and performance bonus, and may make additional contributions at its discretion. The Company matches 150 percent of contributions made by employees hired after December 31, 2014, up to six percent of the employee’s base salary and performance bonus in lieu of pension plan benefits, and may make additional contributions at its discretion. Please refer to Note 8 – Pension Benefits for additional discussion of pension benefits. The Company’s matching contributions to the 401(k) Plan were $4.2 million, $5.1 million, and $4.9 million for the years ended December 31, 2020, 2019, and 2018, respectively.

Pension Benefits

Pension Benefits	12 Months Ended
	Dec. 31, 2020
Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract]
Pension Benefits	Note 8 – Pension Benefits The Company has a non-contributory defined benefit pension plan covering employees who meet age and service requirements and who began employment with the Company prior to January 1, 2016 (“Qualified Pension Plan”). The Company also has a supplemental non-contributory pension plan covering certain management employees (“Nonqualified Pension Plan” and together with the Qualified Pension Plan, “Pension Plans”). The Company froze the Pension Plans to new participants, effective as of January 1, 2016. Employees participating in the Pension Plans prior to the plans being frozen will continue to earn benefits. Obligations and Funded Status for the Pension Plans The Company recognizes the funded status (i.e. the difference between the fair value of plan assets and the projected benefit obligation) of the Company’s Pension Plans in the accompanying balance sheets as either an asset or a liability and recognizes a corresponding adjustment within the other comprehensive income (loss), net of tax, line item in the accompanying statements of comprehensive income (loss). The projected benefit obligation is the actuarial present value of the benefits earned to date by plan participants based on employee service and compensation including the effect of assumed future salary increases. The accumulated benefit obligation uses the same factors as the projected benefit obligation, but excludes the effects of assumed future salary increases. The Company’s measurement date for plan assets and obligations is December 31. For the Years Ended December 31, 2020 2019 (in thousands) Change in benefit obligation: Projected benefit obligation at beginning of year $ 70,843 $ 66,086 Service cost 4,516 5,582 Interest cost 2,358 2,791 Actuarial loss 7,483 2,035 Benefits paid (905) (5,651) Settlements (10,702) — Projected benefit obligation at end of year 73,593 70,843 Change in plan assets: Fair value of plan assets at beginning of year 35,634 30,100 Actual return on plan assets 2,837 3,985 Employer contribution 6,030 7,200 Benefits paid (905) (5,651) Settlements (10,702) — Fair value of plan assets at end of year 32,894 35,634 Funded status at end of year $ (40,699) $ (35,209) The Company’s underfunded status for the Pension Plans as of December 31, 2020, and 2019, was $40.7 million and $35.2 million, respectively, and is recognized in the accompanying balance sheets within the other noncurrent liabilities line item. There are no plan assets in the Nonqualified Pension Plan. Accumulated Benefit Obligation in Excess of Plan Assets for the Pension Plans As of December 31, 2020 2019 (in thousands) Projected benefit obligation $ 73,593 $ 70,843 Accumulated benefit obligation $ 63,934 $ 60,877 Less: fair value of plan assets (32,894) (35,634) Underfunded accumulated benefit obligation $ 31,040 $ 25,243 Pension expense is determined based upon the annual service cost of benefits (the actuarial cost of benefits earned during a period) and the interest cost on those liabilities, less the expected return on plan assets. The expected long-term rate of return on plan assets is applied to a calculated value of plan assets that recognizes changes in fair value over a five-year period. This practice is intended to reduce year-to-year volatility in pension expense, but it can have the effect of delaying recognition of differences between actual returns on assets and expected returns based on long-term rate of return assumptions. Amortization of the unrecognized net gain or loss resulting from actual experience different from that assumed and from changes in assumptions (excluding asset gains and losses not yet reflected in market-related value) is included as a component of net periodic benefit cost for the year. If, as of the beginning of the year, the unrecognized net gain or loss exceeds 10 percent of the greater of the projected benefit obligation and the market-related value of plan assets, then the amortization is the excess divided by the average remaining service period of participating employees expected to receive benefits under the plan. The pre-tax amounts not yet recognized in net periodic pension costs, but rather recognized in the accumulated other comprehensive loss line item within the accompanying balance sheets as of December 31, 2020, and 2019, were as follows: As of December 31, 2020 2019 (in thousands) Unrecognized actuarial losses $ 17,328 $ 14,406 Unrecognized prior service costs 14 31 Accumulated other comprehensive loss $ 17,342 $ 14,437 The pension liability adjustments recognized in other comprehensive income (loss) during 2020, 2019, and 2018, were as follows: For the Years Ended December 31, 2020 2019 2018 (in thousands) Net actuarial gain (loss) $ (6,381) $ 377 $ 4,329 Amortization of prior service cost 17 17 18 Amortization of net actuarial loss 950 958 1,327 Settlements 2,509 — — Total pension liability adjustment, pre-tax (2,905) 1,352 5,674 Tax (expense) benefit 626 (291) (4,265) Cumulative effect of accounting change — — 2,969 Total pension liability adjustment, net $ (2,279) $ 1,061 $ 4,378 Components of Net Periodic Benefit Cost for the Pension Plans For the Years Ended December 31, 2020 2019 2018 (in thousands) Components of net periodic benefit cost: Service cost $ 4,516 $ 5,582 $ 6,730 Interest cost 2,358 2,791 2,622 Expected return on plan assets that reduces periodic pension benefit cost (1,735) (1,574) (1,862) Amortization of prior service cost 17 17 18 Amortization of net actuarial loss 950 958 1,327 Net periodic benefit cost 6,106 7,774 8,835 Settlements 2,509 — — Total net benefit cost $ 8,615 $ 7,774 $ 8,835 Pension Plan Assumptions The weighted-average assumptions used to measure the Company’s projected benefit obligation are as follows: As of December 31, 2020 2019 Projected benefit obligation: Discount rate 2.9% 3.6% Rate of compensation increase 4.4% 4.5% The weighted-average assumptions used to measure the Company’s net periodic benefit cost are as follows: For the Years Ended December 31, 2020 2019 2018 Net periodic benefit cost: Discount rate 3.6% 4.4% 3.8% Expected return on plan assets (1) 5.3% 5.0% 5.5% Rate of compensation increase 4.5% 6.2% 6.2% ____________________________________________ (1) There is no assumed expected return on plan assets for the Nonqualified Pension Plan because there are no plan assets in the Nonqualified Pension Plan. The Company’s pension investment policy includes various guidelines and procedures designed to ensure that assets are prudently invested in a manner necessary to meet the future benefit obligation of the Pension Plans. The policy prohibits the direct investment of plan assets in the Company’s securities. The Qualified Pension Plan’s investment horizon is long-term and accordingly the target asset allocations encompass a strategic, long-term perspective of capital markets, expected risk and return behavior and perceived future economic conditions. The key investment principles of diversification, assessment of risk, and targeting the optimal expected returns for given levels of risk are applied. The Qualified Pension Plan’s investment portfolio contains a diversified blend of investments, which may reflect varying rates of return. The investments are further diversified within each asset classification. This portfolio diversification provides protection against a single security or class of securities having a disproportionate impact on aggregate investment performance. The actual asset allocations are reviewed and rebalanced on a periodic basis to maintain the target allocations. The weighted-average asset allocation of the Qualified Pension Plan is as follows: Target As of December 31, Asset Category 2021 2020 2019 Equity securities 36.0 % 37.0 % 36.9 % Fixed income securities 37.0 % 24.9 % 38.1 % Other securities 27.0 % 38.1 % 25.0 % Total 100.0 % 100.0 % 100.0 % There is no asset allocation of the Nonqualified Pension Plan since there are no plan assets in the plan. An expected return on plan assets of 5.3 percent, 5.0 percent, and 5.5 percent was used to calculate the Company’s net periodic pension cost under the Qualified Pension Plan for the years ended December 31, 2020, 2019, and 2018 respectively. The expected long-term rate of return assumption of the Qualified Pension Plan is based upon the target asset allocation and is determined using forward-looking assumptions in the context of historical returns and volatilities for each asset class, as well as correlations among asset classes. The Company evaluates the expected rate of return on plan assets assumption on an annual basis. Pension Plan Assets The fair values of the Company’s Qualified Pension Plan assets as of December 31, 2020, and 2019, utilizing the fair value hierarchy discussed in Note 11 – Fair Value Measurements are as follows: Fair Value Measurements Using: Actual Asset Allocation (1) Total Level 1 Inputs Level 2 Inputs Level 3 Inputs (in thousands) As of December 31, 2020 Equity securities: Domestic (2) 18.7 % $ 6,149 $ 4,165 $ 1,984 $ — International (3) 18.3 % 6,010 6,010 — — Total equity securities 37.0 % 12,159 10,175 1,984 — Fixed income securities: Core fixed income (4) 16.6 % 5,447 5,447 — — Floating rate corporate loans (5) 8.3 % 2,755 2,755 — — Total fixed income securities 24.9 % 8,202 8,202 — — Other securities: Real estate (6) 5.7 % 1,870 — — 1,870 Collective investment trusts (7) 4.6 % 1,498 — 1,498 — Hedge fund (8) 27.8 % 9,165 5,299 — 3,866 Total other securities 38.1 % 12,533 5,299 1,498 5,736 Total investments 100.0 % $ 32,894 $ 23,676 $ 3,482 $ 5,736 As of December 31, 2019 Equity securities: Domestic (2) 17.3 % $ 6,176 $ 4,130 $ 2,046 $ — International (3) 19.6 % 6,958 6,958 — — Total equity securities 36.9 % 13,134 11,088 2,046 — Fixed income securities: Core fixed income (4) 31.4 % 11,199 11,199 — — Floating rate corporate loans (5) 6.7 % 2,379 2,379 — — Total fixed income securities 38.1 % 13,578 13,578 — — Other securities: Real estate (6) 5.4 % 1,929 — — 1,929 Collective investment trusts (7) 3.3 % 1,168 — 1,168 — Hedge fund (8) 16.3 % 5,825 2,006 — 3,819 Total other securities 25.0 % 8,922 2,006 1,168 5,748 Total investments 100.0 % $ 35,634 $ 26,672 $ 3,214 $ 5,748 ____________________________________________ (1) Percentages may not calculate due to rounding. (2) Level 1 equity securities consist of United States large and small capitalization companies, which are actively traded securities that can be sold upon demand. Level 2 equity securities are investments in a collective investment fund that is valued at net asset value based on the value of the underlying investments and total units outstanding on a daily basis. The objective of these funds is to approximate the S&P 500 by investing in one or more collective investment funds. (3) International equity securities consists of a well-diversified portfolio of holdings of mostly large issuers organized in developed countries with liquid markets, commingled with investments in equity securities of issuers located in emerging markets that are believed to have strong sustainable financial productivity at attractive valuations. (4) The objective of core fixed income funds is to achieve value added from sector or issue selection by constructing a portfolio to approximate the investment results of the Barclay’s Capital Aggregate Bond Index with a modest amount of variability in duration around the index. (5) Investments consist of floating rate bank loans. The interest rates on these loans are typically reset on a periodic basis to account for changes in the level of interest rates. (6) The investment objective of direct real estate is to provide current income with the potential for long-term capital appreciation. Ownership in real estate entails a long-term time horizon, periodic valuations, and potentially low liquidity. (7) Collective investment trusts invest in short-term investments and are valued at the net asset value of the collective investment trust. The net asset value, as provided by the trustee, is used as a practical expedient to estimate fair value. The net asset value is based on the fair value of the underlying investments held by the fund less its liabilities. (8) The hedge fund portfolio includes investments in actively traded global mutual funds that focus on alternative investments and a hedge fund of funds that invests both long and short using a variety of investment strategies. Included below is a summary of the changes in Level 3 plan assets (in thousands): Balance at January 1, 2019 $ 5,507 Purchases — Realized gain on assets 190 Unrealized gain on assets 51 Disposition — Balance at December 31, 2019 $ 5,748 Purchases — Realized gain on assets 526 Unrealized gain on assets 41 Disposition (579) Balance at December 31, 2020 $ 5,736 Contributions The Company contributed $6.0 million, $7.2 million, and $8.1 million to the Pension Plans for the years ended December 31, 2020, 2019, and 2018, respectively. The Company expects to make a $7.0 million contribution to the Pension Plans in 2021. Benefit Payments The Pension Plans made actual benefit payments of $11.6 million, $5.7 million, and $8.0 million in the years ended December 31, 2020, 2019, and 2018, respectively. Expected benefit payments over the next 10 years are as follows: For the Years Ending December 31, Amount (in thousands) 2021 $ 9,564 2022 $ 3,769 2023 $ 5,390 2024 $ 4,765 2025 $ 5,996 2026 through 2030 $ 24,132

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2020
Earnings Per Share [Abstract]
Earnings Per Share [Text Block]	Note 9 - Earnings Per Share Basic net income or loss per common share is calculated by dividing net income or loss available to common stockholders by the basic weighted-average number of common shares outstanding for the respective period. Diluted net income or loss per common share is calculated by dividing net income or loss available to common stockholders by the diluted weighted-average number of common shares outstanding, which includes the effect of potentially dilutive securities. As of December 31, 2019, and 2018, potentially dilutive securities for this calculation consisted primarily of non-vested RSUs, contingent PSUs, and shares into which the 2021 Senior Convertible Notes were convertible, which were measured using the treasury stock method. Shares of the Company’s common stock traded at an average closing price below the $40.50 conversion price for the years ended December 31, 2019, and 2018, therefore, the 2021 Senior Convertible Notes had no dilutive impact. In connection with the offering of the 2021 Senior Convertible Notes, the Company entered into capped call transactions with affiliates of the underwriters that would effectively prevent dilution upon settlement up to the $60.00 cap price. The capped call transactions will always be anti-dilutive and therefore will never be reflected in diluted net income or loss per share. On April 29, 2020, pursuant to the Third Supplemental Indenture, the Company elected to satisfy any conversion obligation with respect to the 2021 Senior Convertible Notes solely in cash. As a result, the Company’s 2021 Senior Secured Convertible Notes are no longer convertible into shares of the Company’s common stock and thus, were not considered to be a potentially dilutive instrument as of December 31, 2020. Please refer to Note 5 – Long-Term Debt for additional discussion. On June 17, 2020, the Company issued warrants to purchase up to an aggregate of approximately 5.9 million shares, or approximately five percent of its outstanding common stock, at an exercise price of $0.01 per share, as discussed in Note 5 – Long-Term Debt . The Warrant Agreement dated as of June 17, 2020 (“Warrant Agreement”), states that the warrants are only exercisable upon the Triggering Date, as defined in Note 11 – Fair Value Measurements . The warrants were not exercisable for the year ended December 31, 2020, and therefore had no dilutive impact. The Triggering Date occurred on January 14, 2021, and the warrants became exercisable at the election of the holders. The warrants may be exercised either in full or from time to time in part, until their expiration on June 30, 2023. Please refer to Note 11 – Fair Value Measurements for additional detail regarding the terms of the warrants. As of December 31, 2020, potentially dilutive securities for this calculation consist primarily of non-vested RSUs, contingent PSUs, and warrants, which were measured using the treasury stock method. PSUs represent the right to receive, upon settlement of the PSUs after the completion of the three Note 7 – Compensation Plans under the heading Performance Share Units . When the Company recognizes a net loss from continuing operations, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted net loss per common share. The following table details the weighted-average anti-dilutive securities for the years presented: For the Years Ended December 31, 2020 2019 2018 (in thousands) Anti-dilutive 265 684 — The following table sets forth the calculations of basic and diluted net income (loss) per common share: For the Years Ended December 31, 2020 2019 2018 (in thousands, except per share data) Net income (loss) $ (764,614) $ (187,001) $ 508,407 Basic weighted-average common shares outstanding 113,730 112,544 111,912 Dilutive effect of non-vested RSUs and contingent PSUs — — 1,590 Diluted weighted-average common shares outstanding 113,730 112,544 113,502 Basic net income (loss) per common share $ (6.72) $ (1.66) $ 4.54 Diluted net income (loss) per common share $ (6.72) $ (1.66) $ 4.48

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2020
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Derivative Financial Instruments	Note 10 – Derivative Financial Instruments Summary of Oil, Gas, and NGL Derivative Contracts in Place The Company regularly enters into commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in commodity prices and the associated impact on cash flows. As of December 31, 2020, all derivative counterparties were members of the Company’s Credit Agreement lender group and all contracts were entered into for other-than-trading purposes. The Company’s commodity derivative contracts consist of swap and collar arrangements for oil production, and swap arrangements for gas and NGL production. In a typical commodity swap agreement, if the agreed upon published third-party index price (“index price”) is lower than the swap fixed price, the Company receives the difference between the index price and the agreed upon swap fixed price. If the index price is higher than the swap fixed price, the Company pays the difference. For collar arrangements, the Company receives the difference between an agreed upon index price and the floor price if the index price is below the floor price. The Company pays the difference between the agreed upon ceiling price and the index price if the index price is above the ceiling price. No amounts are paid or received if the index price is between the floor and ceiling prices. The Company has entered into fixed price oil basis swaps in order to mitigate exposure to adverse pricing differentials between certain industry benchmark prices and the actual physical pricing points where the Company’s production volumes are sold. Currently, the Company has basis swap contracts with fixed price differentials between NYMEX WTI and WTI Midland for a portion of its Midland Basin production with sales contracts that settle at WTI Midland prices, NYMEX WTI and Intercontinental Exchange Brent Crude (“ICE Brent”) for a portion of its Midland Basin oil production with sales contracts that settle at ICE Brent prices, and between NYMEX WTI and Argus WTI Houston Magellan East Houston Terminal ("MEH”) for a portion of its South Texas production with sales contracts that settle at Argus WTI Houston MEH prices. The Company has also entered into crude oil swap contracts to fix the differential in pricing between the NYMEX calendar month average and the physical crude oil delivery month (“Roll Differential”) in which the Company pays the periodic variable Roll Differential and receives a weighted-average fixed price differential. The weighted-average fixed price differential represents the amount of net addition (reduction) to delivery month prices for the notional volumes covered by the swap contracts. As of December 31, 2020, the Company had commodity derivative contracts outstanding through the fourth quarter of 2023 as summarized in the tables below. Oil Swaps Contract Period NYMEX WTI Volumes Weighted-Average (MBbl) (per Bbl) First quarter 2021 3,613 $ 42.91 Second quarter 2021 5,072 $ 39.90 Third quarter 2021 4,862 $ 40.10 Fourth quarter 2021 4,744 $ 39.85 2022 6,601 $ 43.99 2023 1,190 $ 45.20 Total 26,082 Oil Collars Contract Period NYMEX WTI Volumes Weighted-Average Floor Price Weighted-Average Ceiling Price (MBbl) (per Bbl) (per Bbl) First quarter 2021 551 $ 48.97 $ 51.96 Total 551 Oil Basis Swaps Contract Period WTI Midland-NYMEX WTI Volumes Weighted-Average Contract Price (1) NYMEX WTI-ICE Brent Volumes Weighted-Average Contract Price (2) WTI Houston MEH-NYMEX WTI Volumes Weighted-Average Contract Price (3) (MBbl) (per Bbl) (MBbl) (per Bbl) (MBbl) (per Bbl) First quarter 2021 3,223 $ 0.79 900 $ (7.86) 173 $ 0.60 Second quarter 2021 3,385 $ 0.78 910 $ (7.86) 493 $ 0.60 Third quarter 2021 3,574 $ 0.74 920 $ (7.86) 356 $ 0.60 Fourth quarter 2021 3,824 $ 0.71 920 $ (7.86) 466 $ 0.60 2022 9,500 $ 1.15 3,650 $ (7.78) — $ — Total 23,506 7,300 1,488 ____________________________________________ (1) Represents the price differential between WTI Midland (Midland, Texas) and NYMEX WTI (Cushing, Oklahoma). (2) Represents the price differential between NYMEX WTI (Cushing, Oklahoma) and ICE Brent (North Sea). (3) Represents the price differential between Argus WTI Houston MEH (Houston, Texas) and NYMEX WTI (Cushing, Oklahoma). Oil Roll Differential Swaps Contract Period NYMEX WTI Volumes Weighted-Average Contract Price (MBbl) (per Bbl) First quarter 2021 3,367 $ (0.30) Second quarter 2021 4,065 $ (0.24) Third quarter 2021 3,708 $ (0.25) Fourth quarter 2021 3,283 $ (0.24) 2022 6,002 $ (0.04) Total 20,425 Gas Swaps Contract Period IF HSC Volumes Weighted-Average Contract Price WAHA Volumes Weighted-Average Contract Price (BBtu) (per MMBtu) (BBtu) (per MMBtu) First quarter 2021 11,592 $ 2.48 6,544 $ 1.76 Second quarter 2021 13,672 $ 2.45 7,230 $ 1.76 Third quarter 2021 12,575 $ 2.40 8,086 $ 1.88 Fourth quarter 2021 12,412 $ 2.41 7,627 $ 1.82 2022 21,119 $ 2.48 10,066 $ 2.30 Total (1) 71,370 39,553 ____________________________________________ (1) The Company has natural gas swaps in place that settle against Inside FERC Houston Ship Channel (“IF HSC”), Inside FERC West Texas (“IF WAHA”), and Platt’s Gas Daily West Texas (“GD WAHA”). As of December 31, 2020, WAHA volumes were comprised of 59 percent IF WAHA and 41 percent GD WAHA. NGL Swaps OPIS Propane Mont Belvieu Non-TET Contract Period Volumes Weighted-Average Contract Price (MBbl) (per Bbl) First quarter 2021 614 $ 21.58 Second quarter 2021 707 $ 21.26 Third quarter 2021 735 $ 21.26 Fourth quarter 2021 714 $ 21.30 2022 116 $ 21.21 Total 2,886 Commodity Derivative Contracts Entered Into Subsequent to December 31, 2020 Subsequent to December 31, 2020, the Company entered into the following fixed price commodity derivative contracts: Oil Swaps Index Start Date Through Date Volumes Weighted-Average Contract Price NYMEX WTI First quarter 2021 Third quarter 2021 1,048 $ 51.91 NYMEX WTI First quarter 2022 Fourth quarter 2022 1,222 $ 48.50 Oil Collars Index Start Date Through Date Volumes Weighted-Average Floor Price Weighted-Average Ceiling Price NYMEX WTI First quarter 2022 Fourth quarter 2022 1,095 $ 50.00 $ 53.28 Oil Basis Swaps Index Start Date Through Date Volumes Weighted-Average Contract Price WTI Midland-NYMEX WTI First quarter 2021 Third quarter 2021 1,095 $ 0.95 WTI Houston MEH-NYMEX WTI First quarter 2022 Fourth quarter 2022 1,329 $ 1.25 Oil Roll Differential Swaps Index Start Date Through Date Volumes Weighted-Average Contract Price NYMEX WTI First quarter 2021 Fourth quarter 2021 2,213 $ 0.30 NYMEX WTI First quarter 2022 Fourth quarter 2022 5,276 $ 0.27 Gas Swaps Index Start Date Through Date Volumes Weighted-Average Contract Price IF HSC First quarter 2022 Fourth quarter 2022 7,813 $ 2.64 IF WAHA First quarter 2022 Fourth quarter 2022 3,650 $ 2.30 NGL Swaps Index Start Date Through Date Volumes Weighted-Average Contract Price OPIS Propane Mont Belvieu Non-TET First quarter 2021 Fourth quarter 2021 440 $ 27.72 OPIS Propane Mont Belvieu Non-TET First quarter 2022 First quarter 2022 115 $ 24.78 OPIS Normal Butane Mont Belvieu Non-TET First quarter 2021 Fourth quarter 2021 143 $ 30.87 NGL Collars Index Start Date Through Date Volumes Weighted-Average Floor Price Weighted-Average Ceiling Price OPIS Propane Mont Belvieu Non-TET First quarter 2022 Fourth quarter 2022 234 $ 22.05 $ 27.30 Derivative Assets and Liabilities Fair Value The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities, with the exception of derivative instruments that meet the “normal purchase normal sale” exclusion. The Company does not designate its commodity derivative contracts as hedging instruments. The fair value of the commodity derivative contracts at December 31, 2020, and 2019, was a net liability of $168.2 million and a net asset of $21.5 million, respectively. The following table details the fair value of commodity derivative contracts recorded in the accompanying balance sheets, by category: As of December 31, 2020 As of December 31, 2019 (in thousands) Derivative assets: Current assets $ 31,203 $ 55,184 Noncurrent assets 23,150 20,624 Total derivative assets $ 54,353 $ 75,808 Derivative liabilities: Current liabilities $ 200,189 $ 50,846 Noncurrent liabilities 22,331 3,444 Total derivative liabilities $ 222,520 $ 54,290 Offsetting of Derivative Assets and Liabilities As of December 31, 2020, and 2019, all derivative instruments held by the Company were subject to master netting arrangements with various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between it and the counterparty, at the election of both parties, for transactions that settle on the same date and in the same currency. The Company’s agreements also provide that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to not offset these positions in its accompanying balance sheets. The following table provides a reconciliation between the gross assets and liabilities reflected on the accompanying balance sheets and the potential effects of master netting arrangements on the fair value of the Company’s commodity derivative contracts: Derivative Assets Derivative Liabilities As of December 31, As of December 31, 2020 2019 2020 2019 (in thousands) Gross amounts presented in the accompanying balance sheets $ 54,353 $ 75,808 $ (222,520) $ (54,290) Amounts not offset in the accompanying balance sheets (53,598) (35,075) 53,598 35,075 Net amounts $ 755 $ 40,733 $ (168,922) $ (19,215) The Company recognizes all gains and losses from changes in commodity derivative fair values immediately in earnings rather than deferring such amounts in accumulated other comprehensive income (loss). The Company had no commodity derivative contracts designated as hedging instruments for the years ended December 31, 2020, 2019, and 2018. Please refer to Note 11 – Fair Value Measurements for more information regarding the Company’s derivative instruments, including its valuation techniques. The following table summarizes the commodity components of the derivative settlement (gain) loss, as well as the components of the net derivative (gain) loss line item presented in the accompanying statements of operations: For the Years Ended December 31, 2020 2019 2018 (in thousands) Derivative settlement (gain) loss: Oil contracts $ (331,559) $ 19,685 $ 68,860 Gas contracts (11,898) (23,008) 13,029 NGL contracts (7,804) (35,899) 53,914 Total derivative settlement (gain) loss: $ (351,261) $ (39,222) $ 135,803 Net derivative (gain) loss: Oil contracts $ (205,180) $ 172,055 $ (192,002) Gas contracts 30,038 (41,205) 35,411 NGL contracts 13,566 (33,311) (5,241) Total net derivative (gain) loss: $ (161,576) $ 97,539 $ (161,832) Credit Related Contingent Features As of December 31, 2020, and through the filing of this report, all of the Company’s derivative counterparties were members of the Company’s Credit Agreement lender group. Under the Credit Agreement, the Company is required to provide mortgage liens on assets having a value equal to at least 85 percent of the total PV-9, as defined in the Credit Agreement, of the Company’s proved oil and gas properties evaluated in the most recent reserve report. Collateral securing indebtedness under the Credit Agreement also secures the Company’s derivative agreement obligations.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2020
Fair Value Disclosures [Abstract]
Fair Value Disclosures [Text Block]	Note 11 – Fair Value Measurements The Company follows fair value measurement accounting guidance for all assets and liabilities measured at fair value. This guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The fair value hierarchy for grouping these assets and liabilities is based on the significance level of the following inputs: • Level 1 – quoted prices in active markets for identical assets or liabilities • Level 2 – quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable • Level 3 – significant inputs to the valuation model are unobservable The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they are classified within the fair value hierarchy as of December 31, 2020: Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 54,353 $ — Liabilities: Derivatives (1) $ — $ 222,520 $ — ____________________________________________ (1) This represents a financial asset or liability that is measured at fair value on a recurring basis. The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they are classified within the fair value hierarchy as of December 31, 2019: Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 75,808 $ — Liabilities: Derivatives (1) $ — $ 54,290 $ — ____________________________________________ (1) This represents a financial asset or liability that is measured at fair value on a recurring basis. Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The following is a description of the valuation methodologies used by the Company as well as the general classification of such instruments pursuant to the above fair value hierarchy. Please refer to Note 1 – Summary of Significant Accounting Policies for additional information on the Company’s policies for determining fair value for the categories discussed below. Derivatives The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivatives. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration forward commodity price curves, counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The commodity derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity derivative markets are highly active. Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. However, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. The Company monitors the credit ratings of its counterparties and may require counterparties to post collateral if their ratings deteriorate. In some instances, the Company will attempt to novate the trade to a more stable counterparty. Valuation adjustments are necessary to reflect the effect of the Company’s credit quality on the fair value of any commodity derivative liability position. This adjustment takes into account any credit enhancements, such as collateral margin that the Company may have posted with a counterparty, as well as any letters of credit between the parties. The methodology to determine this adjustment is consistent with how the Company evaluates counterparty credit risk, taking into account the Company’s credit rating, current revolving credit facility margins, and any change in such margins since the last measurement date. The methods described above may result in a fair value estimate that may not be indicative of net realizable value or may not be reflective of future fair values and cash flows. While the Company believes that the valuation methods utilized are appropriate and consistent with authoritative accounting guidance and other marketplace participants, the Company recognizes that third parties may use different methodologies or assumptions to determine the fair value of certain financial instruments that could result in a different estimate of fair value at the reporting date. Refer to Note 10 – Derivative Financial Instruments for more information regarding the Company’s derivative instruments. Oil and Gas Properties and Other Property and Equipment The Company had no assets included in total property and equipment, net, measured at fair value as of December 31, 2020, or December 31, 2019. For the year ended December 31, 2020, the Company recorded impairment expense of $956.7 million related to its South Texas proved oil and gas properties and related support facilities due to the decrease in commodity price forecasts at the end of the first quarter of 2020, specifically decreases in oil and NGL prices. The Company used a discount rate of 11 percent in its calculation of the present value of expected future cash flows based on the prevailing market-based weighted average cost of capital as of March 31, 2020. No proved property impairment expense was recorded during the years ended December 31, 2019, or 2018. The following table presents impairment of proved properties expense and abandonment and impairment of unproved properties expense recorded for the periods presented: For the Years Ended December 31, 2020 2019 2018 (in millions) Impairment of proved oil and gas properties and related support equipment $ 956.7 $ — $ — Abandonment and impairment of unproved properties (1) 59.3 33.8 49.9 Impairment $ 1,016.0 $ 33.8 $ 49.9 ____________________________________________ (1) These impairments related to actual and anticipated lease expirations, as well as actual and anticipated losses on acreage due to title defects, changes in development plans, and other inherent acreage risks. The balances in the unproved oil and gas properties line item on the accompanying balance sheets as of December 31, 2020, 2019, and 2018, are recorded at carrying value. Please refer to Note 1 – Summary of Significant Accounting Policies for information on the Company’s policies for determining fair value of its oil and gas producing properties and related impairment expense. Long-Term Debt The following table reflects the fair value of the Company’s senior note obligations measured using Level 1 inputs based on quoted secondary market trading prices. These notes were not presented at fair value on the accompanying balance sheets as of December 31, 2020, or 2019, as they were recorded at carrying value, net of any unamortized discounts and deferred financing costs. Please refer to Note 5 – Long-Term Debt for additional information. As of December 31, 2020 2019 Principal Amount Fair Value Principal Amount Fair Value (in thousands) 1.50% Senior Secured Convertible Notes due 2021 (1) $ 65,485 $ 61,449 $ — $ — 10.0% Senior Secured Notes due 2025 $ 446,675 $ 482,887 $ — $ — 6.125% Senior Unsecured Notes due 2022 $ 212,403 $ 205,379 $ 476,796 $ 481,564 5.0% Senior Unsecured Notes due 2024 $ 277,034 $ 240,072 $ 500,000 $ 479,815 5.625% Senior Unsecured Notes due 2025 $ 349,118 $ 289,401 $ 500,000 $ 475,835 6.75% Senior Unsecured Notes due 2026 $ 419,235 $ 342,385 $ 500,000 $ 494,860 6.625% Senior Unsecured Notes due 2027 $ 416,791 $ 331,220 $ 500,000 $ 493,750 1.50% Senior Convertible Notes due 2021 (1) $ — $ — $ 172,500 $ 164,430 ___________________________________________ (1) The Company’s 2021 Senior Convertible Notes became secured in the second quarter of 2020 upon the closing of the Exchange Offers. Please refer to Note 5 – Long-Term Debt for additional information. The carrying value of the Company’s revolving credit facility approximates its fair value, as the applicable interest rates are floating, based on prevailing market rates. Warrants As discussed in Note 5 – Long-Term Debt , on June 17, 2020, the Company issued warrants to purchase up to an aggregate of approximately 5.9 million shares, or approximately five percent of its outstanding common stock, at an exercise price of $0.01 per share. The warrants are exercisable any time from and after the Triggering Date, as subsequently defined, until June 30, 2023. The Triggering Date is defined by the Warrant Agreement as the first trading day following five consecutive trading days on which the product of the number of shares of common stock issued and outstanding on four of the five trading days multiplied by the closing price per share of common stock for each such trading day exceeds $1.0 billion (“Triggering Date”). The warrants issued are indexed to the Company’s common stock and are required to be settled through physical settlement or net share settlement if exercised. The warrants were not exercisable during the year ended December 31, 2020. The Triggering Date occurred on January 14, 2021, and the warrants became exercisable at the election of the holders. The warrants may be exercised either in full or from time to time in part, until their expiration on June 30, 2023.

Leases

Leases	12 Months Ended
	Dec. 31, 2020
Lessee Disclosure [Abstract]
Leases	Note 12 - Leases Topic 842 requires lessees to recognize operating and finance leases with terms greater than 12 months on the balance sheet. As of December 31, 2020, and 2019, the Company did not have any agreements in place that were classified as finance leases under Topic 842. Arrangements classified as operating leases are included on the accompanying balance sheets within the other noncurrent assets, other current liabilities, and other noncurrent liabilities line items. For any agreement that contains both lease and non-lease components, such as a service arrangement that also includes an identifiable ROU asset, the Company’s policy for all asset classes is to combine lease and non-lease components together and account for the arrangement as a single lease. Aside from the recognition of ROU assets and corresponding lease liabilities on the accompanying balance sheets, Topic 842 does not have a material impact on the timing or classification of costs incurred for those agreements considered to be leases. As outlined in Topic 842, a ROU asset represents a lessee’s right to use an underlying asset for the lease term, while the associated lease liability represents the lessee’s obligations to make lease payments. At the commencement date, which is the date on which a lessor makes an underlying asset available for use by a lessee, a lease ROU asset and corresponding lease liability is recognized based on the present value of the future lease payments. The initial measurement of lease payments may also be adjusted for certain items, including options that are reasonably certain to be exercised, such as options to purchase the asset at the end of the lease term, or options to extend or early terminate the lease. Excluded from the initial measurement of a ROU asset and corresponding lease liability are certain variable lease payments, such as payments made that vary depending on actual usage or performance. The Company evaluates a contractual arrangement at its inception to determine if it is a lease or contains an identifiable lease component as defined by Topic 842. When evaluating a contract to determine appropriate classification and recognition under Topic 842, significant judgment may be necessary to determine, among other criteria, if an embedded leasing arrangement exists, the length of the term, classification as either an operating or financing lease, which options are reasonably likely to be exercised, fair value of the underlying ROU asset or assets, upfront costs, and future lease payments that are included or excluded in the initial measurement of the ROU asset. Certain assumptions and judgments made by the Company when evaluating a contract that meets the definition of a lease under Topic 842 include: • Discount Rate - Unless implicitly defined, the Company determines the present value of future lease payments using an estimated incremental borrowing rate based on a yield curve analysis that factors in certain assumptions, including the term of the lease and credit rating of the Company at lease inception. The weighted-average discount rate used to determine the operating lease liability at December 31, 2020, and 2019, was 7.0 percent and 6.6 percent, respectively. • Lease Term - The Company evaluates each contract containing a lease arrangement at inception to determine the length of the lease term when recognizing a ROU asset and corresponding lease liability. When determining the lease term, options available to extend or early terminate the arrangement are evaluated and included when it is reasonably certain an option will be exercised. Because of the Company’s intent to maintain financial and operational flexibility, there are no available options to extend that the Company is reasonably certain it will exercise. Additionally, based on expectations for those agreements with early termination options, there are no leases in which material early termination options are reasonably certain to be exercised by the Company. Exercising an early termination option may result in an early termination penalty depending on the terms of the underlying agreement. Currently, the Company has operating leases for asset classes that include office space, office equipment, drilling rigs, midstream agreements, vehicles, and equipment rentals used in field operations. For those operating leases included on the accompanying balance sheets, which only includes leases with terms greater than 12 months at commencement, remaining lease terms range from less than one year to approximately five years. The weighted-average lease term remaining for these leases is approximately three years as of each of the years ended December 31, 2020, and 2019. Certain leases also contain optional extension periods that allow for terms to be extended for up to an additional 10 years. An early termination option also exists for certain leases, some of which allow for the Company to terminate a lease within one year. Subsequent to initial measurement, costs associated with the Company’s operating leases are either expensed or capitalized depending on how the underlying ROU asset is utilized and in accordance with GAAP requirements. For example, costs associated with drilling rigs and completion crews that are considered ROU assets are typically capitalized as part of the development of the Company’s oil and gas properties. Please refer to Note 1 – Summary of Significant Accounting Policies for additional information on its accounting policies for oil and gas development and producing activities. When calculating the Company’s ROU asset and liability for a contractual arrangement that qualifies as an operating lease, the Company considers all of the necessary payments made or that are expected to be made upon commencement of the lease. As discussed above, excluded from the initial measurement are certain variable lease payments, which for the Company’s drilling rigs, completion crews, and midstream agreements, may be a significant component of the total lease costs. The following table reflects the components of the Company’s total costs, whether capitalized or expensed, related to operating leases, including short-term leases, and variable lease payments made for leases with initial lease terms greater than 12 months, for the years ended December 31, 2020, and 2019. This total does not reflect amounts that may be reimbursed by other third parties in the normal course of business, such as non-operating working interest owners. For the Years Ended December 31, 2020 2019 (in thousands) Operating lease cost $ 17,980 $ 35,570 Short-term lease cost (1) 143,892 301,373 Variable lease cost (2) 70,858 106,006 Total lease cost $ 232,730 $ 442,949 ____________________________________________ (1) Costs associated with short-term lease agreements relate primarily to operational activities where underlying lease terms are less than one year. This amount includes drilling and completion activities and field equipment rentals, most of which are contracted for 12 months or less. It is expected that this amount will fluctuate primarily with the number of drilling rigs and completion crews the Company is operating under short-term agreements. (2) Variable lease payments include additional payments made that were not included in the initial measurement of the ROU asset and corresponding liability for lease agreements with terms longer than 12 months. Variable lease payments relate to the actual volumes transported under certain midstream agreements, actual usage associated with drilling rigs, completion crews, and vehicles, and variable utility costs associated with the Company’s leased office space. Fluctuations in variable lease payments are driven by actual volumes delivered and the number of drilling rigs and completion crews operating under long-term agreements. ROU assets obtained in exchange for new operating lease liabilities totaled $745,000 and $25.4 million for the twelve months ended December 31, 2020, and 2019, respectively. Cash paid for amounts included in the measurement of lease liabilities for the years ended December 31, 2020, and 2019, were as follows: For the Years Ended December 31, 2020 2019 (in thousands) Operating cash flows from operating leases $ 12,046 $ 12,074 Investing cash flows from operating leases $ 7,313 $ 24,129 Maturities for the Company’s operating lease liabilities included on the accompanying balance sheets as of December 31, 2020, were as follows: As of December 31, 2020 (in thousands) 2021 $ 12,781 2022 5,891 2023 3,591 2024 2,081 2025 1,222 Thereafter 417 Total Lease payments $ 25,983 Less: Imputed interest (1) (2,426) Total $ 23,557 ____________________________________________ (1) The weighted-average discount rate used to determine the operating lease liability as of December 31, 2020, was 7.0 percent. Amounts recorded on the accompanying balance sheets for operating leases as of December 31, 2020, and 2019, were as follows: As of December 31, 2020 2019 (in thousands) Other noncurrent assets $ 21,701 $ 39,717 Other current liabilities $ 11,659 $ 19,189 Other noncurrent liabilities $ 11,898 $ 23,137 As of December 31, 2020, and through the filing of this report, the Company has no material lease arrangements which are scheduled to commence in the future.

Accounts Receivable and Account

Accounts Receivable and Accounts Payable and Accrued Expenses	12 Months Ended
	Dec. 31, 2020
Accounts Receivable and Accounts Payable and Accrued Expenses [Abstract]
Accounts Receivable and Accounts Payable and Accrued Expenses [Text Block]	Note 13 – Accounts Receivable and Accounts Payable and Accrued Expenses Accounts receivable are comprised of the following accruals: As of December 31, 2020 2019 (in thousands) Oil, gas, and NGL production revenue $ 108,928 $ 146,308 Amounts due from joint interest owners 31,514 22,681 State severance tax refunds 2,301 4,069 Derivative settlements 16,348 6,868 Other 3,364 4,806 Total accounts receivable $ 162,455 $ 184,732 Accounts payable and accrued expenses are comprised of the following accruals: As of December 31, 2020 2019 (in thousands) Drilling and lease operating cost accruals $ 65,365 $ 96,925 Trade accounts payable 63,006 52,094 Revenue and severance tax payable 105,233 109,847 Property taxes 20,584 24,535 Compensation 30,907 41,540 Derivative settlements 1,146 5,851 Interest 52,802 44,175 Other 32,627 27,041 Total accounts payable and accrued expenses $ 371,670 $ 402,008

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2020
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note 14 – Asset Retirement Obligations Please refer to Asset Retirement Obligations in Note 1 – Summary of Significant Accounting Policies for a discussion of the initial and subsequent measurements of asset retirement obligation liabilities and the significant assumptions used in the estimates. The following is a reconciliation of the Company’s total asset retirement obligation liability as of December 31, 2020, and 2019: As of December 31, 2020 2019 (in thousands) Beginning asset retirement obligations $ 86,846 $ 94,194 Liabilities incurred (1) 1,018 3,927 Liabilities settled (2) (1,404) (4,105) Accretion expense 4,034 4,016 Revision to estimated cash flows (5,169) (11,186) Ending asset retirement obligations (3) $ 85,325 $ 86,846 ____________________________________________ (1) Reflects liabilities incurred through drilling activities and acquisitions of drilled wells. (2) Reflects liabilities settled through plugging and abandonment activities and divestitures of properties. (3) Balances as of December 31, 2020, and 2019, included $2.0 million and $2.7 million, respectively, related to the Company’s current asset retirement obligation liability, which is recorded in the accounts payable and accrued expenses line item on the accompanying balance sheets.

Suspended Well Costs

Suspended Well Costs	12 Months Ended
	Dec. 31, 2020
Extractive Industries [Abstract]
Suspended Well Costs [Text Block]	Note 15 – Suspended Well Costs The following table reflects the net changes in capitalized exploratory well costs during 2020, 2019, and 2018. The table does not include amounts that were capitalized and either subsequently expensed or reclassified to producing well costs in the same year: For the Years Ended December 31, 2020 2019 2018 (in thousands) Beginning balance $ 11,925 $ 11,197 $ 49,446 Additions to capitalized exploratory well costs pending the determination of proved reserves 3,346 11,925 11,197 Divestitures — — (109) Reclassifications based on the determination of proved reserves (9,573) (11,197) (49,337) Capitalized exploratory well costs charged to expense — — — Ending balance $ 5,698 $ 11,925 $ 11,197 As of December 31, 2020, there were no material exploratory well costs that were capitalized for more than one year.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2020
Accounting Policies [Abstract]
Basis of Presentation [Policy Text Block]	Basis of Presentation The accompanying consolidated financial statements include the accounts of the Company and have been prepared in accordance with GAAP and the instructions to Form 10-K and Regulation S-X. Intercompany accounts and transactions have been eliminated. In connection with the preparation of the accompanying consolidated financial statements, the Company evaluated events subsequent to the balance sheet date of December 31, 2020, through the filing of this report. Additionally, certain prior period amounts have been reclassified to conform to current period presentation in the accompanying consolidated financial statements.
Use of Estimates in the Preparation of the Financial Statements [Policy Text Block]	Use of Estimates in the Preparation of Financial Statements The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of proved oil and gas reserves, assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of proved oil and gas reserve quantities provide the basis for the calculation of DD&A expense, impairment of proved and unproved oil and gas properties, and asset retirement obligations, each of which represents a significant component of the accompanying consolidated financial statements.
Cash and Cash Equivalents [Policy Text Block]	Cash and Cash Equivalents The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments.
Accounts Receivable [Policy Text Block]	Accounts Receivable The Company’s accounts receivable primarily consists of receivables due from oil, gas, and NGL purchasers and from joint interest owners on properties the Company operates. For receivables due from joint interest owners, the Company generally has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, the Company’s oil, gas, and NGL receivables are collected within 30 to 90 days and the Company has had minimal bad debts. Although diversified among many companies, collectibility is dependent upon the financial wherewithal of each individual company and is influenced by the general economic conditions of the industry. Receivables are not collateralized. Please refer to Note 13 – Accounts Receivable and Accounts Payable and Accrued Expenses for additional disclosure.
Concentration of Credit Risk and Major Customers [Policy Text Block]	Concentration of Credit Risk and Major Customers The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy related industries. The creditworthiness of customers and other counterparties is subject to regular review. The Company does not believe the loss of any single purchaser of its production would materially impact its operating results, as oil, gas, and NGLs are products with well-established markets and numerous purchasers in the Company’s operating areas. The following major customers and entities under common control accounted for 10 percent or more of the Company’s total oil, gas, and NGL production revenue for at least one of the periods presented: For the Years Ended December 31, 2020 2019 2018 Major customer #1 (1) — % 18 % 18 % Major customer #2 (1) 20 % 14 % 5 % Major customer #3 (1) 24 % 13 % 7 % Major customer #4 (1) 6 % 9 % 10 % Major customer #5 (1) 15 % 4 % — % Group #1 of entities under common control (2) 5 % 13 % 18 % Group #2 of entities under common control (2) 7 % 11 % 12 % ____________________________________________ (1) These major customers are purchasers of a portion of the Company’s production from its Midland Basin assets and South Texas assets. (2) In the aggregate, these groups of entities under common control represented purchasers of more than 10% of total oil, gas, and NGL production revenue for at least one of the periods presented; however, no individual entity comprising either group was a purchaser of more than 10% of the Company’s total oil, gas, and NGL production revenue. The Company generally contracts with the affiliates of the lenders under its Credit Agreement as its derivative counterparties, and the Company’s policy is that each counterparty must have certain minimum investment grade senior unsecured debt ratings. The Company maintains its primary bank accounts with a large, multinational bank that has branch locations in the Company’s areas of operations. The Company’s policy is to diversify its concentration of cash and cash equivalent investments among multiple institutions and investment products to limit the amount of credit exposure to any single institution or investment.
Oil and Gas Producing Activities [Policy Text Block]	Proved properties . The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method, the costs of development wells are capitalized whether those wells are successful or unsuccessful. Capitalized drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities in the field, are depleted on an asset group basis (properties aggregated based on geographical and geological characteristics) using the units-of-production method based on estimated proved developed oil and gas reserves. Similarly, proved leasehold costs are depleted on the same asset group basis; however, the units-of-production method is based on estimated total proved oil and gas reserves. The computation of DD&A expense takes into consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging equipment.
Oil and Gas Properties Costs [Policy Text Block]	Capitalized drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities in the field, are depleted on an asset group basis (properties aggregated based on geographical and geological characteristics) using the units-of-production method based on estimated proved developed oil and gas reserves. Similarly, proved leasehold costs are depleted on the same asset group basis; however, the units-of-production method is based on estimated total proved oil and gas reserves. The computation of DD&A expense takes into consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging equipment. Proved oil and gas property costs are evaluated for impairment on a pool-by-pool basis and reduced to fair value when there is an indication that associated carrying costs may not be recoverable. The Company uses Level 3 inputs and the income valuation technique, which converts future cash flows to a single present value amount, to measure the fair value of proved properties using a discount rate, price and cost forecasts, and certain reserve risk-adjustment factors, as selected by the Company’s management. The Company uses a discount rate that represents a current market-based weighted average cost of capital. The discount rate typically ranges from 10 percent to 15 percent. The prices for oil and gas are forecasted based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLs are forecasted using OPIS Mont Belvieu pricing, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. Certain undeveloped reserve estimates are also risk-adjusted given the risk to related projected cash flows due to performance and exploitation uncertainties. The partial sale of a proved property within an existing field is accounted for as a normal retirement and no net gain or loss on divestiture activity is recognized as long as the treatment does not significantly affect the units-of-production depletion rate. The sale of a partial interest in an individual proved property is accounted for as a recovery of cost. A net gain or loss on divestiture activity is recognized in the accompanying statements of operations for all other sales of proved properties. Unproved properties . The unproved oil and gas properties line item on the accompanying consolidated balance sheets (“accompanying balance sheets”) consists of the costs incurred to acquire unproved leases. Leasehold costs allocated to those leases, or partial leases that have associated proved reserves recorded, are reclassified to proved properties and depleted on an asset group basis using the units-of-production method based on estimated total proved oil and gas reserves. Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. Lease acquisition costs that are not individually significant are aggregated by asset group and the portion of such costs estimated to be nonproductive prior to lease expiration are recognized as a valuation allowance and amortized over the appropriate period. The estimate of what could be nonproductive is based on historical trends or other information, including current drilling plans and the Company’s intent to renew leases. To measure the fair value of unproved properties, the Company uses a market approach, which takes into account the following significant assumptions: remaining lease terms, future development plans, risk-weighted potential resource recovery, estimated reserve values, and estimated acreage value based on price(s) received for similar, recent acreage transactions by the Company or other market participants. For the sale of unproved properties where the original cost has been partially or fully amortized by providing a valuation allowance on an asset group basis, neither a gain nor loss is recognized unless the sales price exceeds the original cost of the property, in which case a gain shall be recognized in the accompanying statements of operations in the amount of such excess.
Property, Plant and Equipment, Impairment [Policy Text Block]	Proved oil and gas property costs are evaluated for impairment on a pool-by-pool basis and reduced to fair value when there is an indication that associated carrying costs may not be recoverable. The Company uses Level 3 inputs and the income valuation technique, which converts future cash flows to a single present value amount, to measure the fair value of proved properties using a discount rate, price and cost forecasts, and certain reserve risk-adjustment factors, as selected by the Company’s management. The Company uses a discount rate that represents a current market-based weighted average cost of capital. The discount rate typically ranges from 10 percent to 15 percent. The prices for oil and gas are forecasted based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLs are forecasted using OPIS Mont Belvieu pricing, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. Certain undeveloped reserve estimates are also risk-adjusted given the risk to related projected cash flows due to performance and exploitation uncertainties. The partial sale of a proved property within an existing field is accounted for as a normal retirement and no net gain or loss on divestiture activity is recognized as long as the treatment does not significantly affect the units-of-production depletion rate. The sale of a partial interest in an individual proved property is accounted for as a recovery of cost. A net gain or loss on divestiture activity is recognized in the accompanying statements of operations for all other sales of proved properties. Unproved properties . The unproved oil and gas properties line item on the accompanying consolidated balance sheets (“accompanying balance sheets”) consists of the costs incurred to acquire unproved leases. Leasehold costs allocated to those leases, or partial leases that have associated proved reserves recorded, are reclassified to proved properties and depleted on an asset group basis using the units-of-production method based on estimated total proved oil and gas reserves. Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. Lease acquisition costs that are not individually significant are aggregated by asset group and the portion of such costs estimated to be
Exploratory [Policy Text Block]	Exploratory . Exploratory geological and geophysical, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage are expensed as incurred. Under the successful efforts method, exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are found, exploratory well costs will be capitalized as proved properties and will be accounted for following the successful efforts method of accounting described above. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. The application of the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either development or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes. Once a well is drilled, the determination that economic proved reserves have been discovered may take considerable time and judgment. Exploratory dry hole costs are included in the cash flows from investing activities section as part of capital expenditures within the accompanying statements of cash flows.
Other Property and Equipment [Policy Text Block]	Other Property and Equipment Other property and equipment such as facilities, office furniture and equipment, buildings, and computer hardware and software are recorded at cost. The Company capitalizes certain software costs incurred during the application development stage. The application development stage generally includes software design, configuration, testing, and installation activities. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed when incurred. Depreciation is calculated using either the straight-line method over the estimated useful lives of the assets, which range from 3 to 30 years, or the unit of output method when appropriate. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts. Other property and equipment costs are evaluated for impairment and reduced to fair value when there is an indication the carrying costs may not be recoverable. To measure the fair value of other property and equipment, the Company uses an income valuation technique or market approach depending on the quality of information available to support management’s assumptions and the circumstances. The valuation includes consideration of the proved and unproved assets supported by the property and equipment, future cash flows associated with the assets, and fixed costs necessary to operate and maintain the assets.
Asset Retirement Obligations [Policy Text Block]	Asset Retirement Obligations The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties, including facilities requiring decommissioning. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is drilled or acquired, or a facility is constructed. The increase in carrying value is included in the proved oil and gas properties line item in the accompanying balance sheets. The Company depletes the amount added to proved oil and gas property costs and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective long-lived assets. Cash paid to settle asset retirement obligations is included in the cash flows from operating activities section of the accompanying statements of cash flows. The Company’s estimated asset retirement obligation liability is based on historical experience in plugging and abandoning wells, estimated economic lives, estimated plugging and abandonment cost, and federal and state regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. The credit-adjusted risk-free rates used to discount the Company’s plugging and abandonment liabilities range from 5.5 percent to 12 percent. In periods subsequent to initial measurement of the liability, the Company must recognize period-to-period changes in the liability resulting from the passage of time, revisions to either the amount of the original estimate of undiscounted cash flows or economic life, or changes in inflation factors or the Company’s credit-adjusted risk-free rate as market conditions warrant. Please refer to Note 14 – Asset Retirement Obligations for a reconciliation of the Company’s total asset retirement obligation liability as of December 31, 2020, and 2019.
Derivatives Financial Instruments [Policy Text Block]	Derivative Financial Instruments The Company periodically enters into commodity derivative instruments to mitigate a portion of its exposure to potentially adverse market changes in commodity prices for its expected future oil, natural gas, and NGL production and the associated impact on cash flows. These instruments typically include commodity price swaps and costless collars, as well as, basis differential and roll differential swaps. Commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities, with the exception of derivative instruments that meet the “normal purchase normal sale” exclusion. The Company does not designate its commodity derivative contracts as hedging instruments. Accordingly, the Company reflects changes in the fair value of its derivative instruments in its accompanying statements of operations as they occur. Gains and losses on derivatives are included within the cash flows from operating activities section of the accompanying statements of cash flows. For additional discussion on derivatives, please refer to Note 10 – Derivative Financial Instruments .
Revenue Recognition [Policy Text Block]	Revenue Recognition The Company derives revenue primarily from the sale of produced oil, gas, and NGLs. Revenue is recognized at the point in time when custody and title (“control”) of the product transfers to the purchaser, which may differ depending on the applicable contractual terms. Revenue accruals are recorded monthly and are based on estimated production delivered to a purchaser and the expected price to be received. Variances between estimates and the actual amounts received are recorded in the month payment is received. Please refer to Note 2 - Revenue from Contracts with Customers for additional discussion.
Stock-based Compensation [Policy Text Block]	Stock-Based Compensation At December 31, 2020, the Company had stock-based employee compensation plans that included RSUs and PSUs issued to employees, RSUs and restricted stock issued to non-employee directors, and an employee stock purchase plan available to eligible employees. These are more fully described in Note 7 – Compensation Plans. The Company records expense associated with the fair value of stock-based compensation in accordance with authoritative accounting guidance, which is based on the estimated fair value of these awards determined at the time of grant, and is included within the general and administrative and exploration expense line items in the accompanying statements of operations. For stock-based compensation awards containing non-market based performance conditions, the Company evaluates the probability of the number of shares that are expected to vest, and then adjusts the expense to reflect the number of shares expected to vest and the cumulative vesting period met to date. Further, the Company accounts for forfeitures of stock-based compensation awards as they occur.
Income Taxes [Policy Text Block]	Income Taxes The Company accounts for deferred income taxes whereby deferred tax assets and liabilities are recognized based on the tax effects of temporary differences between the carrying amounts on the accompanying consolidated financial statements and the tax basis of assets and liabilities, as measured using current enacted tax rates. These differences will result in taxable income or deductions in future years when the reported amounts of the assets or liabilities are recorded or settled, respectively. The Company records deferred tax assets and associated valuation allowances, when appropriate, to reflect amounts more likely than not to be realized based upon Company analysis. The cumulative effect of enacted tax rate changes on the net balance of reported amounts of assets and liabilities is recognized in the period of enactment. Please refer to Note 4 – Income Taxes for additional discussion.
Earnings Per Share [Policy Text Block]	Earnings per Share The Company uses the treasury stock method to determine the effect of potentially dilutive instruments. Please refer to Note 9 - Earnings Per Share for additional discussion.
Comprehensive Income (Loss) [Policy Text Block]	Comprehensive Income (Loss) Comprehensive income (loss) is used to refer to net income (loss) plus other comprehensive income (loss). Other comprehensive income (loss) is comprised of revenues, expenses, gains, and losses that under GAAP are reported as separate components of stockholders’ equity instead of net income (loss). Comprehensive income (loss) is presented net of income taxes in the accompanying consolidated statements of comprehensive income (loss) (“accompanying statements of comprehensive income (loss)”). The Company’s policy for releasing income tax effects within accumulated other comprehensive loss is an incremental, unit-of-account approach. Please refer to Note 8 – Pension Benefits for detail on the changes in the balances of components comprising other comprehensive income (loss).
Fair Value of Financial Instruments [Policy Text Block]	Fair Value of Financial Instruments The Company’s financial instruments including cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The recorded value of the Company’s revolving credit facility approximates its fair value as it bears interest at a floating rate that approximates a current market rate. The Company had a $93.0 million balance under its revolving credit facility as of December 31, 2020, compared with a $122.5 million balance as of December 31, 2019. The Company’s Senior Notes, as defined in Note 5 – Long-Term Debt in Part II, Item 8 of this report, are recorded at cost, net of any unamortized discount and deferred financing costs, and their respective fair values are disclosed in Note 11 – Fair Value Measurements. The Company’s warrants were recorded at fair value upon issuance, with no recurring fair value measurement required. Additionally, the Company has derivative financial instruments that are recorded at fair value. Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would realize upon the sale or refinancing of such instruments. Derivatives The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivatives. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration forward commodity price curves, counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The commodity derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity derivative markets are highly active. Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. However, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. The Company monitors the credit ratings of its counterparties and may require counterparties to post collateral if their ratings deteriorate. In some instances, the Company will attempt to novate the trade to a more stable counterparty. Valuation adjustments are necessary to reflect the effect of the Company’s credit quality on the fair value of any commodity derivative liability position. This adjustment takes into account any credit enhancements, such as collateral margin that the Company may have posted with a counterparty, as well as any letters of credit between the parties. The methodology to determine this adjustment is consistent with how the Company evaluates counterparty credit risk, taking into account the Company’s credit rating, current revolving credit facility margins, and any change in such margins since the last measurement date. The methods described above may result in a fair value estimate that may not be indicative of net realizable value or may not be reflective of future fair values and cash flows. While the Company believes that the valuation methods utilized are appropriate and consistent with authoritative accounting guidance and other marketplace participants, the Company recognizes that third parties may use different methodologies or assumptions to determine the fair value of certain financial instruments that could result in a different estimate of fair value at the reporting date.
Industry Segment and Geographic Information [Policy Text Block]	Industry Segment and Geographic Information The Company operates in the exploration and production segment of the oil and gas industry, onshore in the United States. The Company reports as a single industry segment.
Off-Balance Sheet Arrangements [Policy Text Block]	Off-Balance Sheet Arrangements The Company has not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or SPEs, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. The Company evaluates its transactions to determine if any variable interest entities exist. If it is determined that the Company is the primary beneficiary of a variable interest entity, that entity is consolidated. The Company has not been involved in any unconsolidated SPE transactions in 2020 or 2019.
Recently Issued Accounting Standards [Policy Text Block]	Recently Issued Accounting Standards In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, Leases (Topic 842) , followed by other related ASUs that provided targeted improvements and additional practical expedient options (collectively “ASU 2016-02” or “Topic 842”). The Company adopted ASU 2016-02 on January 1, 2019, using the modified retrospective method. The Company elected as part of its adoption to also use the optional transition methodology whereby lease accounting for previously reported periods continues to be reported in accordance with historical accounting guidance for leases in effect for those prior periods. Policy elections and practical expedients the Company implemented in connection with the adoption of ASU 2016-02 include (a) excluding from the balance sheet leases with terms that are less than one year, (b) for agreements that contain both lease and non-lease components, combining these components together and accounting for them as a single lease, (c) the package of practical expedients, which among other requirements, allows the Company to avoid reassessing contracts that commenced prior to adoption that were properly evaluated under legacy GAAP, and (d) excluding land easements that existed or expired before adoption of ASU 2016-02. The scope of ASU 2016-02 does not apply to leases used in the exploration or use of minerals, oil, natural gas, or other similar non-regenerative resources. Upon adoption on January 1, 2019, the Company recognized approximately $50.0 million in right-of-use (“ROU”) assets and related lease liabilities for its operating leases. There was no cumulative effect adjustment to retained earnings upon the adoption of this guidance. Please refer to Note 12 - Leases for additional discussion. In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments , followed by other related ASUs that provided targeted improvements (collectively “ASU 2016-13”). ASU 2016-13 provides financial statement users with more decision-useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. The Company adopted ASU 2016-13 on January 1, 2020, using the modified retrospective method, and there was no material impact to the Company’s accompanying consolidated financial statements or related disclosures. In August 2018, the FASB issued ASU No. 2018-15, Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”). ASU 2018-15 aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The Company adopted ASU 2018-15 on January 1, 2020, with prospective application, and there was no material impact to the Company’s accompanying consolidated financial statements or related disclosures. In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes (“ASU 2019-12”). ASU 2019-12 was issued as a means to reduce the complexity of accounting for income taxes for those entities that fall within the scope of the accounting standard. The guidance is to be applied using a prospective method, excluding amendments related to franchise taxes, which should be applied on either a retrospective basis for all periods presented or a modified retrospective basis through a cumulative-effect adjustment to retained earnings as of the beginning of the fiscal year of adoption. The Company adopted ASU 2019-12 on January 1, 2020, and there was no material impact on the Company’s accompanying consolidated financial statements or related disclosures. In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”) followed by ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), issued in January 2021 to provide clarifying guidance regarding the scope of Topic 848. ASU 2020-04 was issued to provide optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. Generally, the guidance is to be applied as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020, or prospectively from a date within an interim period that includes or is subsequent to March 12, 2020, up to the date that the financial statements are available to be issued. ASU 2020-04 and ASU 2021-01 are effective for all entities through December 31, 2022. As of December 31, 2020, the Company has not elected to use the optional guidance and continues to evaluate the options provided by ASU 2020-04 and ASU 2021-01. Please refer to Note 5 – Long-Term Debt for discussion of the use of the LIBOR in connection with borrowings under the Credit Agreement. In August 2020, the FASB issued ASU No. 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40) (“ASU 2020-06”). ASU 2020-06 was issued to reduce the complexity associated with accounting for certain financial instruments with characteristics of liabilities and equity. The guidance is to be applied using either a modified retrospective or a fully retrospective method. ASU 2020-06 is effective for fiscal years beginning after December 15, 2021, with early adoption permitted. The Company plans to adopt ASU 2020-06 on January 1, 2022, and does not expect a material impact on the Company’s accompanying consolidated financial statements or related disclosures. There are no other ASUs applicable to the Company that would have a material effect on the Company’s consolidated financial statements and related disclosures that have been issued but not yet adopted by the Company as of December 31, 2020, and through the filing of this report.
Pension Benefits [Policy Text Block]	The Company recognizes the funded status (i.e. the difference between the fair value of plan assets and the projected benefit obligation) of the Company’s Pension Plans in the accompanying balance sheets as either an asset or a liability and recognizes a corresponding adjustment within the other comprehensive income (loss), net of tax, line item in the accompanying statements of comprehensive income (loss). The projected benefit obligation is the actuarial present value of the benefits earned to date by plan participants based on employee service and compensation including the effect of assumed future salary increases. The accumulated benefit obligation uses the same factors as the projected benefit obligation, but excludes the effects of assumed future salary increases. The Company’s measurement date for plan assets and obligations is December 31.
Leases [Policy Text Block]	Arrangements classified as operating leases are included on the accompanying balance sheets within the other noncurrent assets, other current liabilities, and other noncurrent liabilities line items. For any agreement that contains both lease and non-lease components, such as a service arrangement that also includes an identifiable ROU asset, the Company’s policy for all asset classes is to combine lease and non-lease components together and account for the arrangement as a single lease. Aside from the recognition of ROU assets and corresponding lease liabilities on the accompanying balance sheets, Topic 842 does not have a material impact on the timing or classification of costs incurred for those agreements considered to be leases. As outlined in Topic 842, a ROU asset represents a lessee’s right to use an underlying asset for the lease term, while the associated lease liability represents the lessee’s obligations to make lease payments. At the commencement date, which is the date on which a lessor makes an underlying asset available for use by a lessee, a lease ROU asset and corresponding lease liability is recognized based on the present value of the future lease payments. The initial measurement of lease payments may also be adjusted for certain items, including options that are reasonably certain to be exercised, such as options to purchase the asset at the end of the lease term, or options to extend or early terminate the lease. Excluded from the initial measurement of a ROU asset and corresponding lease liability are certain variable lease payments, such as payments made that vary depending on actual usage or performance. The Company evaluates a contractual arrangement at its inception to determine if it is a lease or contains an identifiable lease component as defined by Topic 842. When evaluating a contract to determine appropriate classification and recognition under Topic 842, significant judgment may be necessary to determine, among other criteria, if an embedded leasing arrangement exists, the length of the term, classification as either an operating or financing lease, which options are reasonably likely to be exercised, fair value of the underlying ROU asset or assets, upfront costs, and future lease payments that are included or excluded in the initial measurement of the ROU asset. Certain assumptions and judgments made by the Company when evaluating a contract that meets the definition of a lease under Topic 842 include: • Discount Rate - Unless implicitly defined, the Company determines the present value of future lease payments using an estimated incremental borrowing rate based on a yield curve analysis that factors in certain assumptions, including the term of the lease and credit rating of the Company at lease inception. The weighted-average discount rate used to determine the operating lease liability at December 31, 2020, and 2019, was 7.0 percent and 6.6 percent, respectively. • Lease Term - The Company evaluates each contract containing a lease arrangement at inception to determine the length of the lease term when recognizing a ROU asset and corresponding lease liability. When determining the lease term, options available to extend or early terminate the arrangement are evaluated and included when it is reasonably certain an option will be exercised. Because of the Company’s intent to maintain financial and operational flexibility, there are no available options to extend that the Company is reasonably certain it will exercise. Additionally, based on expectations for those agreements with early termination options, there are no leases in which material early termination options are reasonably certain to be exercised by the Company. Exercising an early termination option may result in an early termination penalty depending on the terms of the underlying agreement.

Fair Value Measures and Disclos

Fair Value Measures and Disclosures (Policies)	12 Months Ended
	Dec. 31, 2020
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments [Policy Text Block]	Fair Value of Financial Instruments The Company’s financial instruments including cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The recorded value of the Company’s revolving credit facility approximates its fair value as it bears interest at a floating rate that approximates a current market rate. The Company had a $93.0 million balance under its revolving credit facility as of December 31, 2020, compared with a $122.5 million balance as of December 31, 2019. The Company’s Senior Notes, as defined in Note 5 – Long-Term Debt in Part II, Item 8 of this report, are recorded at cost, net of any unamortized discount and deferred financing costs, and their respective fair values are disclosed in Note 11 – Fair Value Measurements. The Company’s warrants were recorded at fair value upon issuance, with no recurring fair value measurement required. Additionally, the Company has derivative financial instruments that are recorded at fair value. Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would realize upon the sale or refinancing of such instruments. Derivatives The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivatives. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration forward commodity price curves, counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The commodity derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity derivative markets are highly active. Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. However, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. The Company monitors the credit ratings of its counterparties and may require counterparties to post collateral if their ratings deteriorate. In some instances, the Company will attempt to novate the trade to a more stable counterparty. Valuation adjustments are necessary to reflect the effect of the Company’s credit quality on the fair value of any commodity derivative liability position. This adjustment takes into account any credit enhancements, such as collateral margin that the Company may have posted with a counterparty, as well as any letters of credit between the parties. The methodology to determine this adjustment is consistent with how the Company evaluates counterparty credit risk, taking into account the Company’s credit rating, current revolving credit facility margins, and any change in such margins since the last measurement date. The methods described above may result in a fair value estimate that may not be indicative of net realizable value or may not be reflective of future fair values and cash flows. While the Company believes that the valuation methods utilized are appropriate and consistent with authoritative accounting guidance and other marketplace participants, the Company recognizes that third parties may use different methodologies or assumptions to determine the fair value of certain financial instruments that could result in a different estimate of fair value at the reporting date.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2020
Accounting Policies [Abstract]
Schedule of Major Customers [Table Text Block]	The following major customers and entities under common control accounted for 10 percent or more of the Company’s total oil, gas, and NGL production revenue for at least one of the periods presented: For the Years Ended December 31, 2020 2019 2018 Major customer #1 (1) — % 18 % 18 % Major customer #2 (1) 20 % 14 % 5 % Major customer #3 (1) 24 % 13 % 7 % Major customer #4 (1) 6 % 9 % 10 % Major customer #5 (1) 15 % 4 % — % Group #1 of entities under common control (2) 5 % 13 % 18 % Group #2 of entities under common control (2) 7 % 11 % 12 % ____________________________________________ (1) These major customers are purchasers of a portion of the Company’s production from its Midland Basin assets and South Texas assets. (2) In the aggregate, these groups of entities under common control represented purchasers of more than 10% of total oil, gas, and NGL production revenue for at least one of the periods presented; however, no individual entity comprising either group was a purchaser of more than 10% of the Company’s total oil, gas, and NGL production revenue.

Revenue from Contracts with C_2

Revenue from Contracts with Customers (Tables)	12 Months Ended
	Dec. 31, 2020
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue [Table Text Block]	The tables below present oil, gas, and NGL production revenue by product type for each of the Company’s operating areas for the years ended December 31, 2020, 2019, and 2018: For the year ended December 31, 2020 Midland Basin South Texas Total (in thousands) Oil production revenue $ 802,494 $ 51,074 $ 853,568 Gas production revenue 76,759 110,700 187,459 NGL production revenue 324 84,837 85,161 Total $ 879,577 $ 246,611 $ 1,126,188 Relative percentage 78 % 22 % 100 % ____________________________________________ Note: Amounts may not calculate due to rounding. For the year ended December 31, 2019 Midland Basin South Texas Total (in thousands) Oil production revenue $ 1,119,786 $ 63,426 $ 1,183,212 Gas production revenue 75,827 186,702 262,529 NGL production revenue 123 139,886 140,009 Total $ 1,195,736 $ 390,014 $ 1,585,750 Relative percentage 75 % 25 % 100 % ____________________________________________ Note: Amounts may not calculate due to rounding. For the year ended December 31, 2018 Midland Basin South Texas Rocky Mountain (1) Total (in thousands) Oil production revenue $ 938,004 $ 72,821 $ 54,851 $ 1,065,676 Gas production revenue 125,603 227,252 1,595 354,450 NGL production revenue 1,000 214,441 790 216,231 Total $ 1,064,607 $ 514,514 $ 57,236 $ 1,636,357 Relative percentage 65 % 32 % 3 % 100 % ____________________________________________ Note: Amounts may not calculate due to rounding. (1) Following the divestiture of the Company’s remaining assets in the Rocky Mountain region during the first half of 2018, there has been no production revenue from this region after the second quarter of 2018.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Schedule of components of provision for income taxes [Table Text Block]	The provision for income taxes consists of the following: For the Years Ended December 31, 2020 2019 2018 (in thousands) Current portion of income tax (expense) benefit Federal $ — $ 3,826 $ — State (449) (1,618) (1,662) Deferred portion of income tax (expense) benefit 192,540 41,835 (141,708) Income tax (expense) benefit $ 192,091 $ 44,043 $ (143,370) Effective tax rate 20.1 % 19.1 % 22.0 %
Schedule of components of net deferred income tax liabilities [Table Text Block]	The components of the net deferred tax liabilities are as follows: As of December 31, 2020 2019 (in thousands) Deferred tax liabilities Oil and gas properties excluding asset retirement obligation liabilities $ 83,816 $ 224,686 Derivative assets — 4,646 Other 10,054 12,361 Total deferred tax liabilities 93,870 241,693 Deferred tax assets Derivative liabilities 36,311 — Debt discount and deferred financing costs 23,925 — Asset retirement obligation liabilities 18,424 19,658 Credit carryover 7,543 11,270 Pension 7,183 5,971 Federal and state tax net operating loss carryovers 3,898 4,172 Stock compensation 2,701 3,503 Other liabilities 7,273 10,803 Total deferred tax assets 107,258 55,377 Valuation allowance (13,388) (3,070) Net deferred tax assets 93,870 52,307 Total net deferred tax liabilities $ — $ 189,386 Current federal income tax refundable $ — $ 3,885 Current state income tax payable $ 853 $ 1,404
Schedule of effective income tax rate reconciliation [Table Text Block]	Recorded income tax expense or benefit differs from the amount that would be provided by applying the statutory United States federal income tax rate to income or loss before income taxes. These differences primarily relate to the effect of state income taxes, excess tax benefits and deficiencies from stock-based compensation awards, tax limitations on compensation of covered individuals, changes in valuation allowances, the cumulative impact of other smaller permanent differences, and can also reflect the cumulative effect of an enacted tax rate change, in the period of enactment, on the Company’s net deferred tax asset and liability balance. These differences are reported as follows: For the Years Ended December 31, 2020 2019 2018 (in thousands) Federal statutory tax (expense) benefit $ 200,908 $ 48,519 $ (136,873) (Increase) decrease in tax resulting from: State tax (expense) benefit (net of federal benefit) 5,722 (260) (2,771) Change in valuation allowance (10,318) 13 (105) Employee share-based compensation (2,578) (3,346) (2,508) Other (1,643) (883) (1,113) Income tax (expense) benefit $ 192,091 $ 44,043 $ (143,370)

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
Schedule of Long-term Debt Instruments [Table Text Block]	The following table summarizes the Company’s total outstanding balance on its revolving credit facility, Senior Secured Notes net of unamortized discount and deferred financing costs, and Senior Unsecured Notes, net of unamortized deferred financing costs, as of December 31, 2020, and 2019: As of December 31, 2020 As of December 31, 2019 (in thousands) Revolving credit facility $ 93,000 $ 122,500 Senior Secured Notes (1) 460,656 — Senior Unsecured Notes (1) 1,660,663 2,610,298 Total $ 2,214,319 $ 2,732,798 ____________________________________________ (1) Senior Secured Notes and Senior Unsecured Notes are defined below. As of December 31, 2020 Principal Amount Unamortized Debt Discount Unamortized Deferred Financing Costs Net (in thousands) 10.0% Senior Secured Notes due 2025 $ 446,675 $ 37,943 $ 11,558 $ 397,174 1.50% Senior Secured Convertible Notes due 2021 (1) 65,485 1,828 175 63,482 Total $ 512,160 $ 39,771 $ 11,733 $ 460,656 ____________________________________________ (1) As discussed above, as required by the 2021 Notes Indenture and as permitted by the Credit Agreement, as the Company issued Permitted Second Lien Debt upon the closing of the Exchange Offers, its remaining 2021 Senior Convertible Notes contemporaneously became secured. As of December 31, 2020 As of December 31, 2019 Principal Amount Unamortized Deferred Financing Costs Principal Amount, Net Principal Amount Unamortized Deferred Financing Costs Principal Amount, Net (in thousands) 6.125% Senior Notes due 2022 $ 212,403 $ 855 $ 211,548 $ 476,796 $ 2,920 $ 473,876 5.0% Senior Notes due 2024 277,034 1,576 275,458 500,000 3,766 496,234 5.625% Senior Notes due 2025 349,118 2,792 346,326 500,000 4,903 495,097 6.75% Senior Notes due 2026 419,235 3,970 415,265 500,000 5,571 494,429 6.625% Senior Notes due 2027 416,791 4,725 412,066 500,000 6,601 493,399 1.50% Senior Convertible Notes due 2021 (1)(2) — — — 172,500 15,237 157,263 Total $ 1,674,581 $ 13,918 $ 1,660,663 $ 2,649,296 $ 38,998 $ 2,610,298 ____________________________________________ (1) Unamortized deferred financing costs attributable to the 2021 Senior Convertible Notes include $13.9 million related to the unamortized debt discount as of December 31, 2019. (2) As discussed above, as required by the 2021 Notes Indenture and as permitted by the Credit Agreement, as the Company issued Permitted Second Lien Debt upon the closing of the Exchange Offers, its remaining 2021 Senior Convertible Notes contemporaneously became secured. Title of Senior Unsecured Notes Tendered Principal Amount of Senior Unsecured Notes Tendered (in thousands) 6.125% Senior Notes due 2022 $ 141,701 5.0% Senior Notes due 2024 155,339 5.625% Senior Notes due 2025 150,882 6.75% Senior Notes due 2026 80,765 6.625% Senior Notes due 2027 83,209 Total $ 611,896
Borrowing Base Utilization Grid, Credit Facility [Table Text Block]	Borrowing Base Utilization Percentage <25% ≥25% <50% ≥50% <75% ≥75% <90% ≥90% Eurodollar Loans (1) 1.750 % 2.000 % 2.500 % 2.750 % 3.000 % ABR Loans or Swingline Loans 0.750 % 1.000 % 1.500 % 1.750 % 2.000 % Commitment Fee Rate 0.375 % 0.375 % 0.500 % 0.500 % 0.500 % ____________________________________________ (1) The Credit Agreement specifies that if LIBOR is no longer a widely used benchmark rate, or if it is no longer used for determining interest rates for loans in the United States, a replacement interest rate that fairly reflects the cost to the lenders of funding loans shall be established by the Administrative Agent, as defined in the Credit Agreement, in consultation with the Company. Please refer to Note 1 – Summary of Significant Accounting Policies for discussion of FASB ASU 2020-04, which provides guidance related to reference rate reform .
Schedule of Credit Agreement Facilities [Table Text Block]	The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Credit Agreement as of February 4, 2021, December 31, 2020, and December 31, 2019: As of February 4, 2021 As of December 31, 2020 As of December 31, 2019 (in thousands) Revolving credit facility (1) $ 121,500 $ 93,000 $ 122,500 Letters of credit (2) 42,000 42,000 — Available borrowing capacity 936,500 965,000 1,077,500 Total aggregate lender commitment amount $ 1,100,000 $ 1,100,000 $ 1,200,000 ____________________________________________ (1) Unamortized deferred financing costs attributable to the revolving credit facility are presented as a component of the other noncurrent assets line item on the accompanying balance sheets and totaled $4.3 million and $5.9 million as of December 31, 2020, and 2019, respectively. These costs are being amortized over the term of the revolving credit facility on a straight-line basis. (2) Letters of credit outstanding reduce the amount available under the revolving credit facility on a dollar-for-dollar basis.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Schedule of contractual obligation, five years [Table Text Block]	As of December 31, 2020, the annual minimum payments for the next five years and total minimum payments thereafter are presented below: For the Years Ending December 31, Amount (in thousands) 2021 $ 86,776 2022 79,919 2023 45,474 2024 12,455 2025 11,463 Thereafter 13,233 Total $ 249,320

Compensation Plans (Tables)

Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2020
Share-based Payment Arrangement [Abstract]
Schedule of non-vested PSUs	A summary of the status and activity of non-vested PSUs is presented in the following table: For the Years Ended December 31, 2020 2019 2018 PSUs (1) Weighted-Average Grant-Date Fair Value PSUs (1) Weighted-Average Grant-Date Fair Value PSUs (1) Weighted-Average Grant-Date Fair Value Non-vested at beginning of year 2,022,585 $ 16.87 1,711,259 $ 20.68 1,533,491 $ 22.97 Granted — $ — 793,125 $ 12.80 572,924 $ 24.45 Vested (792,572) $ 15.85 (346,021) $ 26.32 (233,102) $ 44.25 Forfeited (399,549) $ 17.56 (135,778) $ 16.98 (162,054) $ 21.79 Non-vested at end of year 830,464 $ 17.52 2,022,585 $ 16.87 1,711,259 $ 20.68 ____________________________________________ (1) The number of shares of common stock assumes a multiplier of one. The actual final number of shares of common stock to be issued will range from zero to two times the number of PSUs awarded depending on the three
Schedule of non-vested RSUs	A summary of the status and activity of non-vested RSUs granted to employees is presented in the following table: For the Years Ended December 31, 2020 2019 2018 RSUs Weighted- RSUs Weighted- RSUs Weighted- Non-vested at beginning of year 1,532,131 $ 16.01 1,243,163 $ 21.50 1,244,262 $ 20.25 Granted 1,458,869 $ 5.98 978,932 $ 12.36 583,552 $ 25.77 Vested (746,132) $ 16.74 (466,535) $ 21.94 (407,529) $ 24.30 Forfeited (147,008) $ 15.34 (223,429) $ 18.16 (177,122) $ 17.26 Non-vested at end of year 2,097,860 $ 8.83 1,532,131 $ 16.01 1,243,163 $ 21.50
Schedule of shares settled, restricted stock units	A summary of the shares of common stock issued to settle employee RSUs is presented in the table below: For the Years Ended December 31, 2020 2019 2018 Shares of common stock issued to settle RSUs (1) 746,132 466,535 407,529 Less: shares of common stock withheld for income and payroll taxes (209,173) (132,136) (115,784) Net shares of common stock issued 536,959 334,399 291,745 ____________________________________________ (1) During the years ended December 31, 2020, 2019, and 2018, the Company issued shares of common stock to settle RSUs that related to awards granted in previous years. The Company and a majority of grant recipients mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings in accordance with the Company’s Equity Plan and individual award agreements.
Schedule of employee stock purchase plan	The fair value of ESPP shares issued during the periods reported were estimated using the following weighted-average assumptions: For the Years Ended December 31, 2020 2019 2018 Risk free interest rate 0.8 % 2.3 % 1.8 % Dividend yield 0.7 % 0.7 % 0.4 % Volatility factor of the expected market price of the Company’s common stock 166.2 % 56.6 % 55.9 % Expected life (in years) 0.5 0.5 0.5

Pension Benefits (Tables)

Pension Benefits (Tables)	12 Months Ended
	Dec. 31, 2020
Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract]
Schedule of net funded status [Table Text Block]	For the Years Ended December 31, 2020 2019 (in thousands) Change in benefit obligation: Projected benefit obligation at beginning of year $ 70,843 $ 66,086 Service cost 4,516 5,582 Interest cost 2,358 2,791 Actuarial loss 7,483 2,035 Benefits paid (905) (5,651) Settlements (10,702) — Projected benefit obligation at end of year 73,593 70,843 Change in plan assets: Fair value of plan assets at beginning of year 35,634 30,100 Actual return on plan assets 2,837 3,985 Employer contribution 6,030 7,200 Benefits paid (905) (5,651) Settlements (10,702) — Fair value of plan assets at end of year 32,894 35,634 Funded status at end of year $ (40,699) $ (35,209)
Schedule of accumulated benefit obligation in excess of plan assets [Table Text Block]	Accumulated Benefit Obligation in Excess of Plan Assets for the Pension Plans As of December 31, 2020 2019 (in thousands) Projected benefit obligation $ 73,593 $ 70,843 Accumulated benefit obligation $ 63,934 $ 60,877 Less: fair value of plan assets (32,894) (35,634) Underfunded accumulated benefit obligation $ 31,040 $ 25,243
Schedule of net periodic pension costs not yet recognized [Table Text Block]	The pre-tax amounts not yet recognized in net periodic pension costs, but rather recognized in the accumulated other comprehensive loss line item within the accompanying balance sheets as of December 31, 2020, and 2019, were as follows: As of December 31, 2020 2019 (in thousands) Unrecognized actuarial losses $ 17,328 $ 14,406 Unrecognized prior service costs 14 31 Accumulated other comprehensive loss $ 17,342 $ 14,437
Schedule of pension liability adjustments recognized in other comprehensive income (loss) [Table Text Block]	The pension liability adjustments recognized in other comprehensive income (loss) during 2020, 2019, and 2018, were as follows: For the Years Ended December 31, 2020 2019 2018 (in thousands) Net actuarial gain (loss) $ (6,381) $ 377 $ 4,329 Amortization of prior service cost 17 17 18 Amortization of net actuarial loss 950 958 1,327 Settlements 2,509 — — Total pension liability adjustment, pre-tax (2,905) 1,352 5,674 Tax (expense) benefit 626 (291) (4,265) Cumulative effect of accounting change — — 2,969 Total pension liability adjustment, net $ (2,279) $ 1,061 $ 4,378
Components of net periodic benefit cost for the pension plans [Table Text Block]	Components of Net Periodic Benefit Cost for the Pension Plans For the Years Ended December 31, 2020 2019 2018 (in thousands) Components of net periodic benefit cost: Service cost $ 4,516 $ 5,582 $ 6,730 Interest cost 2,358 2,791 2,622 Expected return on plan assets that reduces periodic pension benefit cost (1,735) (1,574) (1,862) Amortization of prior service cost 17 17 18 Amortization of net actuarial loss 950 958 1,327 Net periodic benefit cost 6,106 7,774 8,835 Settlements 2,509 — — Total net benefit cost $ 8,615 $ 7,774 $ 8,835
Schedule of weighted-average pension plan assumptions [Table Text Block]	The weighted-average assumptions used to measure the Company’s projected benefit obligation are as follows: As of December 31, 2020 2019 Projected benefit obligation: Discount rate 2.9% 3.6% Rate of compensation increase 4.4% 4.5% The weighted-average assumptions used to measure the Company’s net periodic benefit cost are as follows: For the Years Ended December 31, 2020 2019 2018 Net periodic benefit cost: Discount rate 3.6% 4.4% 3.8% Expected return on plan assets (1) 5.3% 5.0% 5.5% Rate of compensation increase 4.5% 6.2% 6.2% ____________________________________________ (1) There is no assumed expected return on plan assets for the Nonqualified Pension Plan because there are no plan assets in the Nonqualified Pension Plan.
Schedule of weighted-average asset allocation of the Qualified Pension Plan [Table Text Block]	The weighted-average asset allocation of the Qualified Pension Plan is as follows: Target As of December 31, Asset Category 2021 2020 2019 Equity securities 36.0 % 37.0 % 36.9 % Fixed income securities 37.0 % 24.9 % 38.1 % Other securities 27.0 % 38.1 % 25.0 % Total 100.0 % 100.0 % 100.0 %
Schedule of fair values of the Qualified Pension Plan assets [Table Text Block]	The fair values of the Company’s Qualified Pension Plan assets as of December 31, 2020, and 2019, utilizing the fair value hierarchy discussed in Note 11 – Fair Value Measurements are as follows: Fair Value Measurements Using: Actual Asset Allocation (1) Total Level 1 Inputs Level 2 Inputs Level 3 Inputs (in thousands) As of December 31, 2020 Equity securities: Domestic (2) 18.7 % $ 6,149 $ 4,165 $ 1,984 $ — International (3) 18.3 % 6,010 6,010 — — Total equity securities 37.0 % 12,159 10,175 1,984 — Fixed income securities: Core fixed income (4) 16.6 % 5,447 5,447 — — Floating rate corporate loans (5) 8.3 % 2,755 2,755 — — Total fixed income securities 24.9 % 8,202 8,202 — — Other securities: Real estate (6) 5.7 % 1,870 — — 1,870 Collective investment trusts (7) 4.6 % 1,498 — 1,498 — Hedge fund (8) 27.8 % 9,165 5,299 — 3,866 Total other securities 38.1 % 12,533 5,299 1,498 5,736 Total investments 100.0 % $ 32,894 $ 23,676 $ 3,482 $ 5,736 As of December 31, 2019 Equity securities: Domestic (2) 17.3 % $ 6,176 $ 4,130 $ 2,046 $ — International (3) 19.6 % 6,958 6,958 — — Total equity securities 36.9 % 13,134 11,088 2,046 — Fixed income securities: Core fixed income (4) 31.4 % 11,199 11,199 — — Floating rate corporate loans (5) 6.7 % 2,379 2,379 — — Total fixed income securities 38.1 % 13,578 13,578 — — Other securities: Real estate (6) 5.4 % 1,929 — — 1,929 Collective investment trusts (7) 3.3 % 1,168 — 1,168 — Hedge fund (8) 16.3 % 5,825 2,006 — 3,819 Total other securities 25.0 % 8,922 2,006 1,168 5,748 Total investments 100.0 % $ 35,634 $ 26,672 $ 3,214 $ 5,748 ____________________________________________ (1) Percentages may not calculate due to rounding. (2) Level 1 equity securities consist of United States large and small capitalization companies, which are actively traded securities that can be sold upon demand. Level 2 equity securities are investments in a collective investment fund that is valued at net asset value based on the value of the underlying investments and total units outstanding on a daily basis. The objective of these funds is to approximate the S&P 500 by investing in one or more collective investment funds. (3) International equity securities consists of a well-diversified portfolio of holdings of mostly large issuers organized in developed countries with liquid markets, commingled with investments in equity securities of issuers located in emerging markets that are believed to have strong sustainable financial productivity at attractive valuations. (4) The objective of core fixed income funds is to achieve value added from sector or issue selection by constructing a portfolio to approximate the investment results of the Barclay’s Capital Aggregate Bond Index with a modest amount of variability in duration around the index. (5) Investments consist of floating rate bank loans. The interest rates on these loans are typically reset on a periodic basis to account for changes in the level of interest rates. (6) The investment objective of direct real estate is to provide current income with the potential for long-term capital appreciation. Ownership in real estate entails a long-term time horizon, periodic valuations, and potentially low liquidity. (7) Collective investment trusts invest in short-term investments and are valued at the net asset value of the collective investment trust. The net asset value, as provided by the trustee, is used as a practical expedient to estimate fair value. The net asset value is based on the fair value of the underlying investments held by the fund less its liabilities. (8) The hedge fund portfolio includes investments in actively traded global mutual funds that focus on alternative investments and a hedge fund of funds that invests both long and short using a variety of investment strategies.
Schedule of changes in Level 3 plan assets [Table Text Block]	Included below is a summary of the changes in Level 3 plan assets (in thousands): Balance at January 1, 2019 $ 5,507 Purchases — Realized gain on assets 190 Unrealized gain on assets 51 Disposition — Balance at December 31, 2019 $ 5,748 Purchases — Realized gain on assets 526 Unrealized gain on assets 41 Disposition (579) Balance at December 31, 2020 $ 5,736
Schedule of expected benefit payments [Table Text Block]	Expected benefit payments over the next 10 years are as follows: For the Years Ending December 31, Amount (in thousands) 2021 $ 9,564 2022 $ 3,769 2023 $ 5,390 2024 $ 4,765 2025 $ 5,996 2026 through 2030 $ 24,132

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2020
Earnings Per Share [Abstract]
Schedule of weighted-average anti-dilutive securities	The following table details the weighted-average anti-dilutive securities for the years presented: For the Years Ended December 31, 2020 2019 2018 (in thousands) Anti-dilutive 265 684 —
Schedule of calculations of basic and diluted net income (loss) per common share	The following table sets forth the calculations of basic and diluted net income (loss) per common share: For the Years Ended December 31, 2020 2019 2018 (in thousands, except per share data) Net income (loss) $ (764,614) $ (187,001) $ 508,407 Basic weighted-average common shares outstanding 113,730 112,544 111,912 Dilutive effect of non-vested RSUs and contingent PSUs — — 1,590 Diluted weighted-average common shares outstanding 113,730 112,544 113,502 Basic net income (loss) per common share $ (6.72) $ (1.66) $ 4.54 Diluted net income (loss) per common share $ (6.72) $ (1.66) $ 4.48

Derivative Financial Instrume_2

Derivative Financial Instruments (Tables)	2 Months Ended	12 Months Ended
	Feb. 17, 2021	Dec. 31, 2020
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Schedule of commodity derivative contracts outstanding	Commodity Derivative Contracts Entered Into Subsequent to December 31, 2020 Subsequent to December 31, 2020, the Company entered into the following fixed price commodity derivative contracts: Oil Swaps Index Start Date Through Date Volumes Weighted-Average Contract Price NYMEX WTI First quarter 2021 Third quarter 2021 1,048 $ 51.91 NYMEX WTI First quarter 2022 Fourth quarter 2022 1,222 $ 48.50 Oil Collars Index Start Date Through Date Volumes Weighted-Average Floor Price Weighted-Average Ceiling Price NYMEX WTI First quarter 2022 Fourth quarter 2022 1,095 $ 50.00 $ 53.28 Oil Basis Swaps Index Start Date Through Date Volumes Weighted-Average Contract Price WTI Midland-NYMEX WTI First quarter 2021 Third quarter 2021 1,095 $ 0.95 WTI Houston MEH-NYMEX WTI First quarter 2022 Fourth quarter 2022 1,329 $ 1.25 Oil Roll Differential Swaps Index Start Date Through Date Volumes Weighted-Average Contract Price NYMEX WTI First quarter 2021 Fourth quarter 2021 2,213 $ 0.30 NYMEX WTI First quarter 2022 Fourth quarter 2022 5,276 $ 0.27 Gas Swaps Index Start Date Through Date Volumes Weighted-Average Contract Price IF HSC First quarter 2022 Fourth quarter 2022 7,813 $ 2.64 IF WAHA First quarter 2022 Fourth quarter 2022 3,650 $ 2.30 NGL Swaps Index Start Date Through Date Volumes Weighted-Average Contract Price OPIS Propane Mont Belvieu Non-TET First quarter 2021 Fourth quarter 2021 440 $ 27.72 OPIS Propane Mont Belvieu Non-TET First quarter 2022 First quarter 2022 115 $ 24.78 OPIS Normal Butane Mont Belvieu Non-TET First quarter 2021 Fourth quarter 2021 143 $ 30.87 NGL Collars Index Start Date Through Date Volumes Weighted-Average Floor Price Weighted-Average Ceiling Price OPIS Propane Mont Belvieu Non-TET First quarter 2022 Fourth quarter 2022 234 $ 22.05 $ 27.30	Oil Swaps Contract Period NYMEX WTI Volumes Weighted-Average (MBbl) (per Bbl) First quarter 2021 3,613 $ 42.91 Second quarter 2021 5,072 $ 39.90 Third quarter 2021 4,862 $ 40.10 Fourth quarter 2021 4,744 $ 39.85 2022 6,601 $ 43.99 2023 1,190 $ 45.20 Total 26,082 Oil Collars Contract Period NYMEX WTI Volumes Weighted-Average Floor Price Weighted-Average Ceiling Price (MBbl) (per Bbl) (per Bbl) First quarter 2021 551 $ 48.97 $ 51.96 Total 551 Oil Basis Swaps Contract Period WTI Midland-NYMEX WTI Volumes Weighted-Average Contract Price (1) NYMEX WTI-ICE Brent Volumes Weighted-Average Contract Price (2) WTI Houston MEH-NYMEX WTI Volumes Weighted-Average Contract Price (3) (MBbl) (per Bbl) (MBbl) (per Bbl) (MBbl) (per Bbl) First quarter 2021 3,223 $ 0.79 900 $ (7.86) 173 $ 0.60 Second quarter 2021 3,385 $ 0.78 910 $ (7.86) 493 $ 0.60 Third quarter 2021 3,574 $ 0.74 920 $ (7.86) 356 $ 0.60 Fourth quarter 2021 3,824 $ 0.71 920 $ (7.86) 466 $ 0.60 2022 9,500 $ 1.15 3,650 $ (7.78) — $ — Total 23,506 7,300 1,488 ____________________________________________ (1) Represents the price differential between WTI Midland (Midland, Texas) and NYMEX WTI (Cushing, Oklahoma). (2) Represents the price differential between NYMEX WTI (Cushing, Oklahoma) and ICE Brent (North Sea). (3) Represents the price differential between Argus WTI Houston MEH (Houston, Texas) and NYMEX WTI (Cushing, Oklahoma). Oil Roll Differential Swaps Contract Period NYMEX WTI Volumes Weighted-Average Contract Price (MBbl) (per Bbl) First quarter 2021 3,367 $ (0.30) Second quarter 2021 4,065 $ (0.24) Third quarter 2021 3,708 $ (0.25) Fourth quarter 2021 3,283 $ (0.24) 2022 6,002 $ (0.04) Total 20,425 Gas Swaps Contract Period IF HSC Volumes Weighted-Average Contract Price WAHA Volumes Weighted-Average Contract Price (BBtu) (per MMBtu) (BBtu) (per MMBtu) First quarter 2021 11,592 $ 2.48 6,544 $ 1.76 Second quarter 2021 13,672 $ 2.45 7,230 $ 1.76 Third quarter 2021 12,575 $ 2.40 8,086 $ 1.88 Fourth quarter 2021 12,412 $ 2.41 7,627 $ 1.82 2022 21,119 $ 2.48 10,066 $ 2.30 Total (1) 71,370 39,553 ____________________________________________ (1) The Company has natural gas swaps in place that settle against Inside FERC Houston Ship Channel (“IF HSC”), Inside FERC West Texas (“IF WAHA”), and Platt’s Gas Daily West Texas (“GD WAHA”). As of December 31, 2020, WAHA volumes were comprised of 59 percent IF WAHA and 41 percent GD WAHA. NGL Swaps OPIS Propane Mont Belvieu Non-TET Contract Period Volumes Weighted-Average Contract Price (MBbl) (per Bbl) First quarter 2021 614 $ 21.58 Second quarter 2021 707 $ 21.26 Third quarter 2021 735 $ 21.26 Fourth quarter 2021 714 $ 21.30 2022 116 $ 21.21 Total 2,886
Schedule of fair value of derivatives in accompanying balance sheets		The following table details the fair value of commodity derivative contracts recorded in the accompanying balance sheets, by category: As of December 31, 2020 As of December 31, 2019 (in thousands) Derivative assets: Current assets $ 31,203 $ 55,184 Noncurrent assets 23,150 20,624 Total derivative assets $ 54,353 $ 75,808 Derivative liabilities: Current liabilities $ 200,189 $ 50,846 Noncurrent liabilities 22,331 3,444 Total derivative liabilities $ 222,520 $ 54,290
Schedule of the potential effects of master netting arrangements		The following table provides a reconciliation between the gross assets and liabilities reflected on the accompanying balance sheets and the potential effects of master netting arrangements on the fair value of the Company’s commodity derivative contracts: Derivative Assets Derivative Liabilities As of December 31, As of December 31, 2020 2019 2020 2019 (in thousands) Gross amounts presented in the accompanying balance sheets $ 54,353 $ 75,808 $ (222,520) $ (54,290) Amounts not offset in the accompanying balance sheets (53,598) (35,075) 53,598 35,075 Net amounts $ 755 $ 40,733 $ (168,922) $ (19,215)
Schedule of gains and losses on derivative instruments in the statement of operations		The following table summarizes the commodity components of the derivative settlement (gain) loss, as well as the components of the net derivative (gain) loss line item presented in the accompanying statements of operations: For the Years Ended December 31, 2020 2019 2018 (in thousands) Derivative settlement (gain) loss: Oil contracts $ (331,559) $ 19,685 $ 68,860 Gas contracts (11,898) (23,008) 13,029 NGL contracts (7,804) (35,899) 53,914 Total derivative settlement (gain) loss: $ (351,261) $ (39,222) $ 135,803 Net derivative (gain) loss: Oil contracts $ (205,180) $ 172,055 $ (192,002) Gas contracts 30,038 (41,205) 35,411 NGL contracts 13,566 (33,311) (5,241) Total net derivative (gain) loss: $ (161,576) $ 97,539 $ (161,832)

Fair Value Measurements (Tables

Fair Value Measurements (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 is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they are classified within the fair value hierarchy as of December 31, 2020: Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 54,353 $ — Liabilities: Derivatives (1) $ — $ 222,520 $ — ____________________________________________ (1) This represents a financial asset or liability that is measured at fair value on a recurring basis. The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they are classified within the fair value hierarchy as of December 31, 2019: Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 75,808 $ — Liabilities: Derivatives (1) $ — $ 54,290 $ — ____________________________________________ (1) This represents a financial asset or liability that is measured at fair value on a recurring basis.
Impairment of Oil and Gas Properties [Table Text Block]	The following table presents impairment of proved properties expense and abandonment and impairment of unproved properties expense recorded for the periods presented: For the Years Ended December 31, 2020 2019 2018 (in millions) Impairment of proved oil and gas properties and related support equipment $ 956.7 $ — $ — Abandonment and impairment of unproved properties (1) 59.3 33.8 49.9 Impairment $ 1,016.0 $ 33.8 $ 49.9 ____________________________________________ (1) These impairments related to actual and anticipated lease expirations, as well as actual and anticipated losses on acreage due to title defects, changes in development plans, and other inherent acreage risks. The balances in the unproved oil and gas properties line item on the accompanying balance sheets as of December 31, 2020, 2019, and 2018, are recorded at carrying value. Please refer to Note 1 – Summary of Significant Accounting Policies for information on the Company’s policies for determining fair value of its oil and gas producing properties and related impairment expense.
Long Term Debt Fair Value [Table Text Block]	The following table reflects the fair value of the Company’s senior note obligations measured using Level 1 inputs based on quoted secondary market trading prices. These notes were not presented at fair value on the accompanying balance sheets as of December 31, 2020, or 2019, as they were recorded at carrying value, net of any unamortized discounts and deferred financing costs. Please refer to Note 5 – Long-Term Debt for additional information. As of December 31, 2020 2019 Principal Amount Fair Value Principal Amount Fair Value (in thousands) 1.50% Senior Secured Convertible Notes due 2021 (1) $ 65,485 $ 61,449 $ — $ — 10.0% Senior Secured Notes due 2025 $ 446,675 $ 482,887 $ — $ — 6.125% Senior Unsecured Notes due 2022 $ 212,403 $ 205,379 $ 476,796 $ 481,564 5.0% Senior Unsecured Notes due 2024 $ 277,034 $ 240,072 $ 500,000 $ 479,815 5.625% Senior Unsecured Notes due 2025 $ 349,118 $ 289,401 $ 500,000 $ 475,835 6.75% Senior Unsecured Notes due 2026 $ 419,235 $ 342,385 $ 500,000 $ 494,860 6.625% Senior Unsecured Notes due 2027 $ 416,791 $ 331,220 $ 500,000 $ 493,750 1.50% Senior Convertible Notes due 2021 (1) $ — $ — $ 172,500 $ 164,430 ___________________________________________ (1) The Company’s 2021 Senior Convertible Notes became secured in the second quarter of 2020 upon the closing of the Exchange Offers. Please refer to Note 5 – Long-Term Debt for additional information.

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2020
Lessee Disclosure [Abstract]
Components of total lease cost [Table Text Block]	The following table reflects the components of the Company’s total costs, whether capitalized or expensed, related to operating leases, including short-term leases, and variable lease payments made for leases with initial lease terms greater than 12 months, for the years ended December 31, 2020, and 2019. This total does not reflect amounts that may be reimbursed by other third parties in the normal course of business, such as non-operating working interest owners. For the Years Ended December 31, 2020 2019 (in thousands) Operating lease cost $ 17,980 $ 35,570 Short-term lease cost (1) 143,892 301,373 Variable lease cost (2) 70,858 106,006 Total lease cost $ 232,730 $ 442,949 ____________________________________________ (1) Costs associated with short-term lease agreements relate primarily to operational activities where underlying lease terms are less than one year. This amount includes drilling and completion activities and field equipment rentals, most of which are contracted for 12 months or less. It is expected that this amount will fluctuate primarily with the number of drilling rigs and completion crews the Company is operating under short-term agreements. (2) Variable lease payments include additional payments made that were not included in the initial measurement of the ROU asset and corresponding liability for lease agreements with terms longer than 12 months. Variable lease payments relate to the actual volumes transported under certain midstream agreements, actual usage associated with drilling rigs, completion crews, and vehicles, and variable utility costs associated with the Company’s leased office space. Fluctuations in variable lease payments are driven by actual volumes delivered and the number of drilling rigs and completion crews operating under long-term agreements. ROU assets obtained in exchange for new operating lease liabilities totaled $745,000 and $25.4 million for the twelve months ended December 31, 2020, and 2019, respectively. Cash paid for amounts included in the measurement of lease liabilities for the years ended December 31, 2020, and 2019, were as follows: For the Years Ended December 31, 2020 2019 (in thousands) Operating cash flows from operating leases $ 12,046 $ 12,074 Investing cash flows from operating leases $ 7,313 $ 24,129
Operating lease liability maturities [Table Text Block]	Maturities for the Company’s operating lease liabilities included on the accompanying balance sheets as of December 31, 2020, were as follows: As of December 31, 2020 (in thousands) 2021 $ 12,781 2022 5,891 2023 3,591 2024 2,081 2025 1,222 Thereafter 417 Total Lease payments $ 25,983 Less: Imputed interest (1) (2,426) Total $ 23,557 ____________________________________________ (1) The weighted-average discount rate used to determine the operating lease liability as of December 31, 2020, was 7.0 percent.
Balance sheet information related to operating leases [Table Text Block]	Amounts recorded on the accompanying balance sheets for operating leases as of December 31, 2020, and 2019, were as follows: As of December 31, 2020 2019 (in thousands) Other noncurrent assets $ 21,701 $ 39,717 Other current liabilities $ 11,659 $ 19,189 Other noncurrent liabilities $ 11,898 $ 23,137

Accounts Receivable and Accou_2

Accounts Receivable and Accounts Payable and Accrued Expenses (Tables)	12 Months Ended
	Dec. 31, 2020
Accounts Receivable and Accounts Payable and Accrued Expenses [Abstract]
Schedule of Accounts Receivable [Table Text Block]	Accounts receivable are comprised of the following accruals: As of December 31, 2020 2019 (in thousands) Oil, gas, and NGL production revenue $ 108,928 $ 146,308 Amounts due from joint interest owners 31,514 22,681 State severance tax refunds 2,301 4,069 Derivative settlements 16,348 6,868 Other 3,364 4,806 Total accounts receivable $ 162,455 $ 184,732
Schedule of Accounts Payable and Accrued Expenses [Table Text Block]	Accounts payable and accrued expenses are comprised of the following accruals: As of December 31, 2020 2019 (in thousands) Drilling and lease operating cost accruals $ 65,365 $ 96,925 Trade accounts payable 63,006 52,094 Revenue and severance tax payable 105,233 109,847 Property taxes 20,584 24,535 Compensation 30,907 41,540 Derivative settlements 1,146 5,851 Interest 52,802 44,175 Other 32,627 27,041 Total accounts payable and accrued expenses $ 371,670 $ 402,008

Reconciliation of Asset Retirem

Reconciliation of Asset Retirement Obligation Liability (Tables)	12 Months Ended
	Dec. 31, 2020
Asset Retirement Obligation [Abstract]
Schedule of change in asset retirement obligation liability [Table Text Block]	The following is a reconciliation of the Company’s total asset retirement obligation liability as of December 31, 2020, and 2019: As of December 31, 2020 2019 (in thousands) Beginning asset retirement obligations $ 86,846 $ 94,194 Liabilities incurred (1) 1,018 3,927 Liabilities settled (2) (1,404) (4,105) Accretion expense 4,034 4,016 Revision to estimated cash flows (5,169) (11,186) Ending asset retirement obligations (3) $ 85,325 $ 86,846 ____________________________________________ (1) Reflects liabilities incurred through drilling activities and acquisitions of drilled wells. (2) Reflects liabilities settled through plugging and abandonment activities and divestitures of properties. (3) Balances as of December 31, 2020, and 2019, included $2.0 million and $2.7 million, respectively, related to the Company’s current asset retirement obligation liability, which is recorded in the accounts payable and accrued expenses line item on the accompanying balance sheets.

Suspended Well Costs (Tables)

Suspended Well Costs (Tables)	12 Months Ended
	Dec. 31, 2020
Extractive Industries [Abstract]
Net changes in capitalized exploratory well costs [Table Text Block]	The following table reflects the net changes in capitalized exploratory well costs during 2020, 2019, and 2018. The table does not include amounts that were capitalized and either subsequently expensed or reclassified to producing well costs in the same year: For the Years Ended December 31, 2020 2019 2018 (in thousands) Beginning balance $ 11,925 $ 11,197 $ 49,446 Additions to capitalized exploratory well costs pending the determination of proved reserves 3,346 11,925 11,197 Divestitures — — (109) Reclassifications based on the determination of proved reserves (9,573) (11,197) (49,337) Capitalized exploratory well costs charged to expense — — — Ending balance $ 5,698 $ 11,925 $ 11,197

Summary of Significant Accoun_4

Summary of Significant Accounting Policies Other (Details)	Dec. 31, 2020USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018
Concentration of Credit Risk and Major Customers [Abstract]
Entity-Wide Revenue, Major Customer, Percentage		100.00%	100.00%	100.00%
Number of individual entities within groups of entities under common ownership that represent more than 10 percent of total production revenue		0
Line of Credit [Member]
Long-term Debt, Unclassified [Abstract]
Revolving credit facility	$ 93,000,000	$ 93,000,000	$ 122,500,000
Oil and Gas Properties [Member]
Impairment of Proved, Unproved, and Other Properties [Abstract]
Period of New York Mercantile Exchange Strip Pricing Used for Price Forecast	5 years
Measurement Input, Discount Rate [Member] | Fair Value, Nonrecurring [Member] | Oil and Gas Properties [Member]
Impairment of Proved, Unproved, and Other Properties [Abstract]
Fair value assumptions, measurement input	0.11	0.11
Customer Concentration Risk [Member] | Oil, gas, and NGL revenue [Member] | Major customer one [Member]
Concentration of Credit Risk and Major Customers [Abstract]
Entity-Wide Revenue, Major Customer, Percentage		0.00%	18.00%	18.00%
Customer Concentration Risk [Member] | Oil, gas, and NGL revenue [Member] | Major customer two [Member]
Concentration of Credit Risk and Major Customers [Abstract]
Entity-Wide Revenue, Major Customer, Percentage		20.00%	14.00%	5.00%
Customer Concentration Risk [Member] | Oil, gas, and NGL revenue [Member] | Major customer three [Member]
Concentration of Credit Risk and Major Customers [Abstract]
Entity-Wide Revenue, Major Customer, Percentage		24.00%	13.00%	7.00%
Customer Concentration Risk [Member] | Oil, gas, and NGL revenue [Member] | Major customer four [Member]
Concentration of Credit Risk and Major Customers [Abstract]
Entity-Wide Revenue, Major Customer, Percentage		6.00%	9.00%	10.00%
Customer Concentration Risk [Member] | Oil, gas, and NGL revenue [Member] | Major customer five [Member]
Concentration of Credit Risk and Major Customers [Abstract]
Entity-Wide Revenue, Major Customer, Percentage		15.00%	4.00%	0.00%
Customer Concentration Risk [Member] | Oil, gas, and NGL revenue [Member] | Group one of entities under common control [Member]
Concentration of Credit Risk and Major Customers [Abstract]
Entity-Wide Revenue, Major Customer, Percentage		5.00%	13.00%	18.00%
Customer Concentration Risk [Member] | Oil, gas, and NGL revenue [Member] | Group two of entities under common control [Member]
Concentration of Credit Risk and Major Customers [Abstract]
Entity-Wide Revenue, Major Customer, Percentage		7.00%	11.00%	12.00%
Minimum [Member]
Revenues [Abstract]
Revenue receipt, days after sale		30
Minimum [Member] | Property, Plant and Equipment, Other Types [Member]
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment, Estimated Useful Lives		3 years
Minimum [Member] | Measurement Input, Discount Rate [Member] | Fair Value, Nonrecurring [Member] | Oil and Gas Properties [Member]
Impairment of Proved, Unproved, and Other Properties [Abstract]
Fair value assumptions, measurement input	0.10	0.10
Minimum [Member] | Measurement Input, Credit adjusted risk free rate [Member] | Asset Retirement Obligation Costs [Member]
Impairment of Proved, Unproved, and Other Properties [Abstract]
Fair value assumptions, measurement input	0.055	0.055
Maximum [Member]
Revenues [Abstract]
Revenue receipt, days after sale		90
Maximum [Member] | Property, Plant and Equipment, Other Types [Member]
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment, Estimated Useful Lives		30 years
Maximum [Member] | Measurement Input, Discount Rate [Member] | Fair Value, Nonrecurring [Member] | Oil and Gas Properties [Member]
Impairment of Proved, Unproved, and Other Properties [Abstract]
Fair value assumptions, measurement input	0.15	0.15
Maximum [Member] | Measurement Input, Credit adjusted risk free rate [Member] | Asset Retirement Obligation Costs [Member]
Impairment of Proved, Unproved, and Other Properties [Abstract]
Fair value assumptions, measurement input	0.12	0.12

Summary of Significant Accoun_5

Summary of Significant Accounting Policies ASU Adjustment (Details) - USD ($) $ in Thousands	Jan. 01, 2019	Dec. 31, 2020	Dec. 31, 2019
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Right-of-use assets obtained in exchange for new operating lease liabilities		$ 745	$ 25,400
Accounting Standards Update 2016-02 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Right-of-use assets obtained in exchange for new operating lease liabilities	$ 50,000

Revenue from Contracts with C_3

Revenue from Contracts with Customers Disaggregation of oil, gas, and NGL production revenue (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	$ 1,126,188	$ 1,585,750	$ 1,636,357
Concentration Risk, Percentage	100.00%	100.00%	100.00%
Revenue, Remaining Performance Obligation, Amount	$ 0
Midland Basin [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	879,577	$ 1,195,736	$ 1,064,607
South Texas [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	$ 246,611	$ 390,014	514,514
Rocky Mountain [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax			$ 57,236
Revenue Benchmark [Member] | Geographic Concentration Risk [Member] | Midland Basin [Member]
Segment Reporting Information [Line Items]
Concentration Risk, Percentage	78.00%	75.00%	65.00%
Revenue Benchmark [Member] | Geographic Concentration Risk [Member] | South Texas [Member]
Segment Reporting Information [Line Items]
Concentration Risk, Percentage	22.00%	25.00%	32.00%
Revenue Benchmark [Member] | Geographic Concentration Risk [Member] | Rocky Mountain [Member]
Segment Reporting Information [Line Items]
Concentration Risk, Percentage			3.00%
Oil production revenue [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	$ 853,568	$ 1,183,212	$ 1,065,676
Oil production revenue [Member] | Midland Basin [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	802,494	1,119,786	938,004
Oil production revenue [Member] | South Texas [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	51,074	63,426	72,821
Oil production revenue [Member] | Rocky Mountain [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax			54,851
Gas production revenue [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	187,459	262,529	354,450
Gas production revenue [Member] | Midland Basin [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	76,759	75,827	125,603
Gas production revenue [Member] | South Texas [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	110,700	186,702	227,252
Gas production revenue [Member] | Rocky Mountain [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax			1,595
NGL production revenue [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	85,161	140,009	216,231
NGL production revenue [Member] | Midland Basin [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	324	123	1,000
NGL production revenue [Member] | South Texas [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	$ 84,837	$ 139,886	214,441
NGL production revenue [Member] | Rocky Mountain [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax			$ 790

Revenue from Contracts with C_4

Revenue from Contracts with Customers Accounts Receivable from Customers (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Accounts Receivable
Accounts receivable	$ 162,455	$ 184,732
Oil, gas, and NGL production revenue [Member]
Accounts Receivable
Accounts receivable	$ 108,928	$ 146,308
Minimum [Member]
Accounts Receivable
Revenue receipt, days after sale	30
Maximum [Member]
Accounts Receivable
Revenue receipt, days after sale	90

Nonmonetary Transactions (Detai

Nonmonetary Transactions (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020USD ($)a	Dec. 31, 2019USD ($)a	Dec. 31, 2018USD ($)a
Nonmonetary Transactions [Abstract]
Acreage Exchanged | a	535	2,200	2,650
Carrying value of properties exchanged	$ 6.5	$ 73.4	$ 95.1
Basis of Accounting for Assets Transferred	carryover	carryover	carryover
Gain (Loss) Recognized on Transfer	$ 0	$ 0	$ 0

Asset Acquisitions (Details)

Asset Acquisitions (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2020USD ($)a	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)a
Asset Acquisitions [Abstract]
Net acres acquired | a	380		1,030
Payments to acquire oil and gas property and equipment | $	$ 7,873	$ 2,581	$ 33,255

Divestitures and Assets Held fo

Divestitures and Assets Held for Sale (Details) $ in Thousands	Mar. 26, 2018a	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net gain on divestiture activity		$ 91	$ 862	$ 426,917
Net proceeds from the sale of oil and gas properties		$ 92	$ 13,059	748,509
Disposal group, disposed of by sale, not discontinued operations | PRB Divestiture 2018 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net Acreage Divested | a	112,000
Net gain on divestiture activity				410,600
Net proceeds from the sale of oil and gas properties				492,200
Disposal group, disposed of by sale, not discontinued operations | Divide County Divestiture and Halff East Divestiture 2018 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net gain on divestiture activity				15,400
Net proceeds from the sale of oil and gas properties				252,200
Disposal group, disposed of by sale, not discontinued operations | Divide County Divestiture 2018 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loss before income taxes				$ (29,000)

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Components of the provision for income taxes
Current Federal Tax Expense (Benefit)	$ 0	$ 3,826	$ 0
Current State and Local Tax Expense (Benefit)	(449)	(1,618)	(1,662)
Deferred portion of income tax (expense) benefit	192,540	41,835	(141,708)
Income tax (expense) benefit	$ 192,091	$ 44,043	$ (143,370)
Effective tax rate (as a percent)	20.10%	19.10%	22.00%
Deferred income taxes [Abstract]
Deferred tax liabilities, oil and gas properties	$ 83,816	$ 224,686
Deferred tax liabilities, derivatives assets	0	4,646
Deferred tax liabilities, other	10,054	12,361
Total deferred tax liabilities	93,870	241,693
Derivative tax assets, derivative liabilities	36,311	0
Derivative tax assets, debt discount and deferred financing costs	23,925	0
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Asset Retirement Obligations	18,424	19,658
Deferred tax assets, credit carryover	7,543	11,270
Deferred tax assets, pension	7,183	5,971
Deferred tax assets, federal and state tax net operating loss carryovers	3,898	4,172
Deferred tax assets, stock compensation	2,701	3,503
Deferred tax assets, other liabilities	7,273	10,803
Total deferred tax assets	107,258	55,377
Deferred tax assets, valuation allowance	(13,388)	(3,070)
Net deferred tax assets	93,870	52,307
Total net deferred tax liabilities	0	189,386
State and local jurisdiction [Member]
Deferred income taxes [Abstract]
Current state income tax payable	853	1,404
Net operating loss carryforwards	4,900
Internal Revenue Service (IRS) [Member] | Domestic tax authority [Member]
Deferred income taxes [Abstract]
Current federal income tax refundable	0	$ 3,885
Internal Revenue Service (IRS) [Member] | Domestic tax authority [Member] | Research and development tax credit carryforward [Member]
Deferred income taxes [Abstract]
Deferred tax assets, credit carryover	$ 7,500

Income Taxes Reconciliation of

Income Taxes Reconciliation of Tax Expense (Benefit) and Other (Details) - USD ($)	Jul. 09, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount		$ 200,908,000	$ 48,519,000	$ (136,873,000)
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount		5,722,000	(260,000)	(2,771,000)
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount		(10,318,000)	13,000	(105,000)
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Share-based Payment Arrangement, Amount		(2,578,000)	(3,346,000)	(2,508,000)
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount		(1,643,000)	(883,000)	(1,113,000)
Income tax (expense) benefit		192,091,000	44,043,000	(143,370,000)
Proceeds from income tax refunds	$ 7,600,000
Unrecognized tax benefits [Roll Forward]
Unrecognized tax benefits		$ 446,000	$ 446,000	$ 446,000

Long-term Debt (Details)

Long-term Debt (Details) - USD ($) shares in Thousands, $ in Thousands	Jun. 17, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Long-term Debt [Line Items]
Revolving credit facility and Senior Notes, net		$ 2,214,319	$ 2,732,798
Class of Warrant or Right, Number of Securities Called by Warrants or Rights	5,900
Net gain on extinguishment of debt		$ 280,081	$ 0	$ (26,740)
Senior Secured Notes, Senior Unsecured Notes, and 1.50% Senior Unsecured Convertible Notes Due 2021 [Member]
Long-term Debt [Line Items]
Net gain on extinguishment of debt	$ 227,300

Revolving Credit Facility (Deta

Revolving Credit Facility (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Mar. 31, 2020	Dec. 31, 2020	Feb. 04, 2021	Dec. 31, 2019
Line of Credit Facility [Line Items]
Revolving credit facility	$ 93,000		$ 93,000		$ 122,500
Debt Instrument, Covenant Description			(a) total funded debt, as defined in the Credit Agreement, to 12-month trailing adjusted EBITDAX ratio cannot be greater than 4.00 to 1.00 on the last day of each fiscal quarter; and (b) adjusted current ratio, as defined in the Credit Agreement, cannot be less than 1.00 to 1.00 as of the last day of any fiscal quarter.
Line of Credit [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, maximum loan amount	2,500,000		$ 2,500,000
Line of credit agreement, current borrowing base	1,100,000		1,100,000
Line of credit agreement, aggregate lender commitment amount	$ 1,100,000		1,100,000		1,200,000
Line of Credit Facility, Dividend Restrictions	12.0 million	50.0 million
Revolving credit facility	$ 93,000		93,000		122,500
Letters of credit	42,000		42,000		0
Available borrowing capacity	965,000		965,000		1,077,500
Credit facility, unamortized deferred financing costs	$ 4,300		$ 4,300		$ 5,900
Line of Credit [Member] | Subsequent Event [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, aggregate lender commitment amount				$ 1,100,000
Revolving credit facility				121,500
Letters of credit				42,000
Available borrowing capacity				$ 936,500
Line of Credit [Member] | Borrowing Base Utilization of 25 Percent [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, unused capacity, commitment fee rate	0.375%
Line of Credit [Member] | Borrowing Base Utilization of 25 Percent [Member] | Eurodollar [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, basis spread on variable rate	1.75%
Line of Credit [Member] | Borrowing Base Utilization of 25 Percent [Member] | Debt Instrument Variable Rate, Alternative Base Rate, And Swingline Loans [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, basis spread on variable rate	0.75%
Line of Credit [Member] | Borrowing Base Utilization Of 25 Percent Or More But Less Than 50 Percent [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, unused capacity, commitment fee rate	0.375%
Line of Credit [Member] | Borrowing Base Utilization Of 25 Percent Or More But Less Than 50 Percent [Member] | Eurodollar [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, basis spread on variable rate	2.00%
Line of Credit [Member] | Borrowing Base Utilization Of 25 Percent Or More But Less Than 50 Percent [Member] | Debt Instrument Variable Rate, Alternative Base Rate, And Swingline Loans [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, basis spread on variable rate	1.00%
Line of Credit [Member] | Borrowing Base Utilization Of 50 Percent Or More But Less Than 75 Percent [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, unused capacity, commitment fee rate	0.50%
Line of Credit [Member] | Borrowing Base Utilization Of 50 Percent Or More But Less Than 75 Percent [Member] | Eurodollar [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, basis spread on variable rate	2.50%
Line of Credit [Member] | Borrowing Base Utilization Of 50 Percent Or More But Less Than 75 Percent [Member] | Debt Instrument Variable Rate, Alternative Base Rate, And Swingline Loans [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, basis spread on variable rate	1.50%
Line of Credit [Member] | Borrowing Base Utilization Of 75 Percent Or More But Less Than 90 Percent [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, unused capacity, commitment fee rate	0.50%
Line of Credit [Member] | Borrowing Base Utilization Of 75 Percent Or More But Less Than 90 Percent [Member] | Eurodollar [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, basis spread on variable rate	2.75%
Line of Credit [Member] | Borrowing Base Utilization Of 75 Percent Or More But Less Than 90 Percent [Member] | Debt Instrument Variable Rate, Alternative Base Rate, And Swingline Loans [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, basis spread on variable rate	1.75%
Line of Credit [Member] | Borrowing Base Utilization Of 90 Percent Or More [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, unused capacity, commitment fee rate	0.50%
Line of Credit [Member] | Borrowing Base Utilization Of 90 Percent Or More [Member] | Eurodollar [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, basis spread on variable rate	3.00%
Line of Credit [Member] | Borrowing Base Utilization Of 90 Percent Or More [Member] | Debt Instrument Variable Rate, Alternative Base Rate, And Swingline Loans [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, basis spread on variable rate	2.00%

Senior Secured Notes (Details)

Senior Secured Notes (Details)	12 Months Ended
	Dec. 31, 2020USD ($)$ / shares	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Jun. 17, 2020USD ($)	May 05, 2020USD ($)	Aug. 12, 2016USD ($)
Senior Notes [Line Items]
Senior Notes, net	$ 2,121,319,000	$ 2,610,298,000
Permitted Second Lien Debt	1,000,000,000
Increase to Permitted Second Lien Debt					$ 827,500,000
Permitted Second Lien Debt, Remaining Borrowing Capacity	380,800,000
Senior Secured Notes
Senior Notes [Line Items]
Principal amount	512,160,000
Senior Notes, unamortized debt discount	39,771,000
Unamortized deferred financing costs	(11,733,000)
Senior Notes, net	$ 460,656,000	0
10.0% Senior Secured Notes due 2025 [Member]
Senior Notes [Line Items]
Senior Notes, interest rate, stated percentage	10.00%
Principal amount	$ 446,675,000	0		$ 446,700,000
Senior Notes, unamortized debt discount	37,943,000
Unamortized deferred financing costs	(11,558,000)
Senior Notes, net	397,174,000
Senior Notes debt issuance costs	$ 13,100,000
Debt Instrument, Senior Notes, Initial Fair Value				$ 405,000,000
1.50% Senior Secured Convertible Notes Due 2021 [Member]
Senior Notes [Line Items]
Senior Notes, interest rate, stated percentage	1.50%
Principal amount	$ 65,485,000	$ 0
Senior Notes, unamortized debt discount	1,828,000
Unamortized deferred financing costs	(175,000)
Senior Notes, net	63,482,000
Senior Convertible Notes, interest expense	$ 7,700,000
Senior Convertible Notes, conversion rate	24.6914
Senior Convertible Notes, principal amount of note	$ 1,000
Senior Convertible Notes, conversion price | $ / shares	$ 40.50
1.50% Senior Unsecured Convertible Notes Due 2021 [Member]
Senior Notes [Line Items]
Senior Notes, interest rate, stated percentage	1.50%	1.50%
Principal amount	$ 0	$ 172,500,000				$ 172,500,000
Senior Notes, unamortized debt discount		13,900,000
Unamortized deferred financing costs	0	(15,237,000)
Senior Notes, net	$ 0	157,263,000
Senior Notes debt issuance costs						$ 5,900,000
Senior Convertible Notes, interest expense		$ 11,000,000	$ 10,500,000

Senior Unsecured Notes (Details

Senior Unsecured Notes (Details) - USD ($) $ / shares in Units, $ in Thousands	Jun. 17, 2020	May 05, 2020	Aug. 20, 2018	Sep. 12, 2016	Aug. 12, 2016	May 21, 2015	Nov. 17, 2014	May 20, 2013	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2016
Senior Notes [Line Items]
Senior Notes, net									$ 2,121,319	$ 2,610,298
Net gain on extinguishment of debt									280,081	0	$ (26,740)
Senior Unsecured Notes [Member]
Senior Notes [Line Items]
Senior Notes, net									1,660,663	2,610,298
Unamortized deferred financing costs									(13,918)	(38,998)
Principal amount									1,674,581	$ 2,649,296
Senior Unsecured Notes, Repurchased face amount	$ 611,896
Senior Unsecured Notes, Redemption Price, Percentage		80.00%
Senior Unsecured Notes and 1.50% Senior Unsecured Convertible Notes Due 2021 [Member]
Senior Notes [Line Items]
Interest Paid, Senior Unsecured Notes, Accrued and Unpaid	8,900
Senior Unsecured Notes and 1.50% Senior Unsecured Convertible Notes Due 2021 [Member] | Accelerated Unamortized Deferred Financing Costs [Member]
Senior Notes [Line Items]
Write off of Deferred Debt Issuance Cost	5,600
Senior Unsecured Notes and 1.50% Senior Unsecured Convertible Notes Due 2021 [Member] | Accelerated Unamortized Debt Discount [Member]
Senior Notes [Line Items]
Write off of Deferred Debt Issuance Cost	6,100
6.125% Senior Unsecured Notes Due 2022 and 5.0% Senior Unsecured Notes Due 2024 [Member]
Senior Notes [Line Items]
Senior Unsecured Notes, Repurchased face amount									190,300
Senior Unsecured Notes, Repurchase Amount									136,500
Senior Unsecured Notes, Repurchase Discount									(53,800)
Net gain on extinguishment of debt									52,800
6.125% Senior Unsecured Notes Due 2022 and 5.0% Senior Unsecured Notes Due 2024 [Member] | Accelerated Unamortized Deferred Financing Costs [Member]
Senior Notes [Line Items]
Write off of Deferred Debt Issuance Cost									$ 1,000
1.50% Senior Unsecured Convertible Notes Due 2021 [Member]
Senior Notes [Line Items]
Senior Notes, interest rate, stated percentage									1.50%	1.50%
Senior Notes, net									$ 0	$ 157,263
Unamortized deferred financing costs									0	(15,237)
Principal amount					$ 172,500				$ 0	172,500
Senior Unsecured Notes, Repurchased face amount	107,000
Repayments of Senior Unsecured Notes	$ 53,500
Proceeds from Senior Unsecured Notes, Net of debt issuance costs					166,600
Senior Notes debt issuance costs					5,900
Senior Unsecured Convertible Notes, Initial fair value of liability component					$ 132,300
Senior Unsecured Convertible Notes, Effective interest rate					7.25%
Senior Unsecured Convertible Notes, Initial value of equity component					$ 40,200
Senior Unsecured Convertible Notes, Net carrying amount, Equity component										33,600
Senior Convertible Notes, interest expense										11,000	10,500
Capped call, Transaction costs					$ 24,200
Capped Call, Cap Price					$ 60
Senior Notes, unamortized debt discount										$ 13,900
6.125% Senior Unsecured Notes Due 2022 [Member]
Senior Notes [Line Items]
Senior Notes, interest rate, stated percentage	6.125%						6.125%		6.125%	6.125%
Senior Notes, net									$ 211,548	$ 473,876
Unamortized deferred financing costs									(855)	(2,920)
Principal amount							$ 600,000		212,403	$ 476,796
Senior Unsecured Notes, Repurchased face amount	$ 141,701								122,700		85,000	$ 38,200
Senior Unsecured Notes, Repurchase Amount									$ 94,200		$ 88,100	$ 24,300
Proceeds from Senior Unsecured Notes, Net of debt issuance costs							590,000
Senior Notes debt issuance costs							$ 10,000
5.0% Senior Unsecured Notes Due 2024 [Member]
Senior Notes [Line Items]
Senior Notes, interest rate, stated percentage	5.00%							5.00%	5.00%	5.00%
Senior Notes, net									$ 275,458	$ 496,234
Unamortized deferred financing costs									(1,576)	(3,766)
Principal amount								$ 500,000	277,034	$ 500,000
Senior Unsecured Notes, Repurchased face amount	$ 155,339								67,600
Senior Unsecured Notes, Repurchase Amount									$ 42,300
Proceeds from Senior Unsecured Notes, Net of debt issuance costs								490,200
Senior Notes debt issuance costs								$ 9,800
5.625% Senior Unsecured Notes Due 2025 [Member]
Senior Notes [Line Items]
Senior Notes, interest rate, stated percentage	5.625%					5.625%			5.625%	5.625%
Senior Notes, net									$ 346,326	$ 495,097
Unamortized deferred financing costs									(2,792)	(4,903)
Principal amount						$ 500,000			$ 349,118	$ 500,000
Senior Unsecured Notes, Repurchased face amount	$ 150,882
Proceeds from Senior Unsecured Notes, Net of debt issuance costs						491,000
Senior Notes debt issuance costs						$ 9,000
6.75% Senior Unsecured Notes Due 2026 [Member]
Senior Notes [Line Items]
Senior Notes, interest rate, stated percentage	6.75%			6.75%					6.75%	6.75%
Senior Notes, net									$ 415,265	$ 494,429
Unamortized deferred financing costs									(3,970)	(5,571)
Principal amount				$ 500,000					$ 419,235	$ 500,000
Senior Unsecured Notes, Repurchased face amount	$ 80,765
Proceeds from Senior Unsecured Notes, Net of debt issuance costs				491,600
Senior Notes debt issuance costs				$ 8,400
6.625% Senior Unsecured Notes Due 2027 [Member]
Senior Notes [Line Items]
Senior Notes, interest rate, stated percentage	6.625%		6.625%						6.625%	6.625%
Senior Notes, net									$ 412,066	$ 493,399
Unamortized deferred financing costs									(4,725)	(6,601)
Principal amount			$ 500,000						$ 416,791	$ 500,000
Senior Unsecured Notes, Repurchased face amount	$ 83,209
Proceeds from Senior Unsecured Notes, Net of debt issuance costs			492,100
Senior Notes debt issuance costs			$ 7,900

Capitalized Interest (Details)

Capitalized Interest (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Debt Disclosure [Abstract]
Capitalized interest costs	$ 15.8	$ 18.5	$ 20.6

Commitments (Details)

Commitments (Details) Bcf in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2020USD ($)BcfMMBbls	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Feb. 17, 2021USD ($)
Commitments and Contingencies
Contractual obligation, due in 2021	$ 86,776
Contractual obligation, due in 2022	79,919
Contractual obligation, due in 2023	45,474
Contractual obligation, due in 2024	12,455
Contractual obligation, due in 2025	11,463
Contractual obligation, due thereafter	13,233
Contractual obligation	$ 249,320
Crude oil pipeline commitment [Member]
Commitments and Contingencies
Oil and gas delivery commitments, remaining minimum contractual volumes | MMBbls	16
Natural gas pipeline commitment [Member]
Commitments and Contingencies
Oil and gas delivery commitments, remaining minimum contractual volumes | Bcf	257
Crude Oil Pipeline Commitment Excluded from Remaining Deficiency Payment Amount [Member]
Commitments and Contingencies
Oil and gas delivery commitments, remaining minimum contractual volumes | MMBbls	11.9
Drilling Rig Leasing Contracts [Member]
Commitments and Contingencies
Contractual obligation	$ 5,900
Drilling Rig Leasing Contracts [Member] | Subsequent Event [Member]
Commitments and Contingencies
Contractual obligation				$ 19,900
Early Termination Penalty for Rig Contract Cancellation				$ 11,600
PipelineCommitments [Member]
Commitments and Contingencies
Contractual obligation	161,600
Office Space Leases [Member]
Commitments and Contingencies
Contractual obligation	22,100
Operating leases, rent expense, net of sublease income	5,400	$ 5,500	$ 4,500
Electricity Purchase Agreement [Member]
Commitments and Contingencies
Contractual obligation	45,400
Other miscellaneous contracts and leases [Member]
Commitments and Contingencies
Contractual obligation	$ 14,300
Water pipeline commitment [Member]
Commitments and Contingencies
Water delivery commitments, remaining minimum contractual volumes | MMBbls	17
Minimum [Member]
Commitments and Contingencies
Potential Penalty for not Meeting Minimum Drilling and Completion Requirements	$ 0
Potential Penalty for not Meeting Minimum Drilling and Completion Counts	0
Minimum [Member] | Completion Service Commitment [Member]
Commitments and Contingencies
Potential Penalty for not Meeting Minimum Completion Service Arrangement Requirements	0
Minimum [Member] | Sand Sourcing Commitment [Member]
Commitments and Contingencies
Potential Penalty for not Meeting Minimum Sand Sourcing Requirements	0
Maximum [Member]
Commitments and Contingencies
Potential Penalty for not Meeting Minimum Drilling and Completion Requirements	26,900
Potential Penalty for not Meeting Minimum Drilling and Completion Counts	11,500
Maximum [Member] | Completion Service Commitment [Member]
Commitments and Contingencies
Potential Penalty for not Meeting Minimum Completion Service Arrangement Requirements	10,100
Maximum [Member] | Sand Sourcing Commitment [Member]
Commitments and Contingencies
Potential Penalty for not Meeting Minimum Sand Sourcing Requirements	$ 10,000

Compensation Plans_ Stock Based

Compensation Plans: Stock Based (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2020USD ($)shares$ / shares	Dec. 31, 2019USD ($)$ / sharesshares	Dec. 31, 2018USD ($)$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for grant	3,800,000
Impact outright issuance of one share has on number of available shares	1
Performance Shares (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum impact of issuance of one performance share award on available shares under the equity incentive plan	2
Multiplier applied to PSU awards at settlement	0.9	0	0
Award vesting period	3 years
Retirement vesting Increment	6 months
Retirement increment vesting period	6 months
TSR multiplier cap	1
Stock-based compensation expense | $	$ 4.4	$ 10.9	$ 10.3
Unrecognized stock based compensation expense | $	$ 4.4
Non-vested at beginning of year (in shares)	2,022,585	1,711,259	1,533,491
Non-vested outstanding at the beginning of the period (in dollars per share) | $ / shares	$ 16.87	$ 20.68	$ 22.97
Granted (in shares)	0	793,125	572,924
Granted (in dollars per share) | $ / shares	$ 0	$ 12.80	$ 24.45
Vested (in shares)	(792,572)	(346,021)	(233,102)
Vested (in dollars per share) | $ / shares	$ 15.85	$ 26.32	$ 44.25
Forfeited (in shares)	(399,549)	(135,778)	(162,054)
Forfeited (in dollars per share) | $ / shares	$ 17.56	$ 16.98	$ 21.79
Non-vested at end of year (in shares)	830,464	2,022,585	1,711,259
Non-vested outstanding at the end of the period (in dollars per share) | $ / shares	$ 17.52	$ 16.87	$ 20.68
Multiplier assumed	1
Fair value of PSUs/RSUs granted in period | $		$ 10.2	$ 14
Shares held for settlement of income and payroll tax obligations (in shares)	215,451
Shares Issued in Period	485,060	0	0
Fair value of PSUs/RSUs Vested in Period | $	$ 12.6	$ 9.1	$ 10.3
Performance Shares (PSUs) | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Multiplier applied to PSU awards at settlement	0
Performance Shares (PSUs) | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Multiplier applied to PSU awards at settlement	2
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Retirement vesting Increment	6 months
Retirement increment vesting period	6 months
Stock-based compensation expense | $	$ 8.7	$ 11.1	$ 10.8
Unrecognized stock based compensation expense | $	$ 14.7
Non-vested at beginning of year (in shares)	1,532,131	1,243,163	1,244,262
Non-vested outstanding at the beginning of the period (in dollars per share) | $ / shares	$ 16.01	$ 21.50	$ 20.25
Granted (in shares)	1,458,869	978,932	583,552
Granted (in dollars per share) | $ / shares	$ 5.98	$ 12.36	$ 25.77
Vested (in shares)	(746,132)	(466,535)	(407,529)
Vested (in dollars per share) | $ / shares	$ 16.74	$ 21.94	$ 24.30
Forfeited (in shares)	(147,008)	(223,429)	(177,122)
Forfeited (in dollars per share) | $ / shares	$ 15.34	$ 18.16	$ 17.26
Non-vested at end of year (in shares)	2,097,860	1,532,131	1,243,163
Non-vested outstanding at the end of the period (in dollars per share) | $ / shares	$ 8.83	$ 16.01	$ 21.50
Fair value of PSUs/RSUs granted in period | $	$ 8.7	$ 12.1	$ 15
Shares held for settlement of income and payroll tax obligations (in shares)	209,173	132,136	115,784
Shares Issued in Period	536,959	334,399	291,745
Fair value of PSUs/RSUs Vested in Period | $	$ 12.5	$ 10.2	$ 9.9
Number of Shares Represented by Each RSU	1
Restricted Stock, Shares Settled Gross of Shares for Tax Withholdings	746,132	466,535	407,529

Director Shares (Details)

Director Shares (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Shares Issued to the Board of Directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	$ 990	$ 1,200	$ 1,700
Director [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares issued to directors	267,576	96,719	63,741

Employee Stock Purchase Plan (D

Employee Stock Purchase Plan (Details) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for grant	3,800,000
Employee Stock Purchase Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum employee subscription rate	15.00%
Maximum employee subscription	$ 25,000
Purchase price of common stock, percent	85.00%
Shares available for grant	834,246
Issuance of common stock under Employee Stock Purchase Plan (Shares)	464,757	314,868	199,464
Proceeds from issuance of shares under incentive and share-based compensation plans, excluding stock options	$ 1,500,000	$ 3,200,000	$ 3,200,000
Risk free interest rate	0.80%	2.30%	1.80%
Dividend yield	0.70%	0.70%	0.40%
Volatility factor of the expected market price of the Company's common stock	166.20%	56.60%	55.90%
Expected life (in years)	6 months	6 months	6 months
Stock-based compensation expense	$ 874,000	$ 1,100,000	$ 1,100,000

401(k) Plan (Details)

401(k) Plan (Details) - 401K Plan [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Defined Contribution Plan, maximum annual contributions per employee, percent	60.00%
Defined Contribution Plan, matching contributions	$ 4.2	$ 5.1	$ 4.9
Prior to 2014 [Member]
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Defined Contribution Plan, employer matching contribution, percent of match	100.00%
Defined Contribution Plan, employer matching contribution, percent of employees' gross pay	6.00%
After 2014 [Member]
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Defined Contribution Plan, employer matching contribution, percent of match	150.00%
Defined Contribution Plan, employer matching contribution, percent of employees' gross pay	6.00%

Pension Benefits (Details)

Pension Benefits (Details) - USD ($)		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Jan. 01, 2018	Dec. 31, 2017
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Defined Benefit Plan, service cost		$ 4,516,000	$ 5,582,000	$ 6,730,000
Defined Benefit Plan, interest cost		2,358,000	2,791,000	2,622,000
Defined Benefit Plan, actuarial loss		7,483,000	2,035,000
Defined Benefit Plan, benefits paid		(905,000)	(5,651,000)
Defined Benefit Plan, settlements		(10,702,000)	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, fair value of plan assets at beginning of year		35,634,000	30,100,000
Defined Benefit Plan, actual return on plan assets		2,837,000	3,985,000
Defined Benefit Plan, employer contribution		6,030,000	7,200,000	8,100,000
Defined Benefit Plan, benefits paid excluding settlements		(905,000)	(5,651,000)
Defined Benefit Plan, settlements		(10,702,000)	0
Defined Benefit Plan, fair value of plan assets at end of year		32,894,000	35,634,000	30,100,000
Defined Benefit Plan, funded status at end of year		(40,699,000)	(35,209,000)
Defined Benefit Plan, Plan with Accumulated Benefit Obligation in Excess of Plan Assets [Abstract]
Defined Benefit Plan, projected benefit obligation		73,593,000	70,843,000	66,086,000
Defined Benefit Plan, accumulated benefit obligation		63,934,000	60,877,000
Defined Benefit Plan, fair value of plan assets		32,894,000	35,634,000
Defined Benefit Plan, underfunded accumulated benefit obligation		$ 31,040,000	25,243,000
Defined Benefit Plan, unrecognized net gain (loss) amortization threshold		10.00%
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income [Abstract]
Defined Benefit Plan, unrecognized actuarial losses		$ 17,328,000	14,406,000
Defined Benefit Plan, unrecognized prior service costs		14,000	31,000
Defined Benefit Plan, accumulated other comprehensive loss		17,342,000	14,437,000
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Other Comprehensive Income (Loss), Defined Benefit Plan, net actuarial gain (loss)		(6,381,000)	377,000	4,329,000
Other Comprehensive Income (Loss), Defined Benefit Plan, amortization of prior service cost		17,000	17,000	18,000
Other Comprehensive Income (Loss), Defined Benefit Plan, amortization of net actuarial loss		950,000	958,000	1,327,000
Other Comprehensive Income (Loss), Defined Benefit Plan, settlements		2,509,000	0	0
Other Comprehensive Income (Loss), Defined Benefit Plan, total pension liability adjustment, pre-tax		(2,905,000)	1,352,000	5,674,000
Other Comprehensive Income (Loss), Defined Benefit Plan, tax (expense) benefit		626,000	(291,000)	(4,265,000)
Stockholders' Equity Attributable to Parent		2,016,160,000	2,748,994,000	2,920,322,000		$ 2,394,608,000
Other Comprehensive Income (Loss), Defined Benefit Plan, total pension liability adjustment, net	[1]	(2,279,000)	1,061,000	4,378,000
Components of Net Periodic Benefit Costs for Both Pension Plans
Defined Benefit Plan, service cost		4,516,000	5,582,000	6,730,000
Defined Benefit Plan, interest cost		2,358,000	2,791,000	2,622,000
Defined Benefit Plan, expected return on plan assets that reduces periodic pension benefit cost		(1,735,000)	(1,574,000)	(1,862,000)
Defined Benefit Plan, amortization of prior service cost		17,000	17,000	18,000
Defined Benefit Plan, amortization of net actuarial loss		950,000	958,000	1,327,000
Defined Benefit Plan, net periodic benefit cost		6,106,000	7,774,000	8,835,000
Defined Benefit Plan, settlements		2,509,000	0	0
Defined Benefit Plan, Total Net Benefit Cost		$ 8,615,000	$ 7,774,000	$ 8,835,000
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation and Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, discount rate		2.90%	3.60%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, rate of compensation increase		4.40%	4.50%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, discount rate		3.60%	4.40%	3.80%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, expected return on plan assets		5.30%	5.00%	5.50%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, rate of compensation increase		4.50%	6.20%	6.20%
Defined Benefit Plan, Expected Future Employer Contributions [Abstract]
Defined Benefit Plan, Expected Future Contributions in Next Fiscal Year		$ 7,000,000
Future Benefit Payments
Defined Benefit Plan, Expected Future Benefit Payments in Year One		9,564,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Two		3,769,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Three		5,390,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Four		4,765,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Five		5,996,000
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter		24,132,000
Defined Benefit Plan, Plan Assets, Benefits Paid		$ (11,600,000)	$ (5,700,000)	$ (8,000,000)
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		100.00%
Cumulative Effect, Period of Adoption, Adjustment
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Stockholders' Equity Attributable to Parent					$ 0
Nonqualified Plan [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, fair value of plan assets at beginning of year		$ 0	0
Defined Benefit Plan, fair value of plan assets at end of year		$ 0	$ 0	$ 0
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation and Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, expected return on plan assets		0.00%	0.00%	0.00%
Defined Benefit Plan, Equity Securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, fair value of plan assets at beginning of year		$ 13,134,000
Defined Benefit Plan, fair value of plan assets at end of year		$ 12,159,000	$ 13,134,000
Future Benefit Payments
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		36.00%
Fixed Income Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, fair value of plan assets at beginning of year		$ 13,578,000
Defined Benefit Plan, fair value of plan assets at end of year		$ 8,202,000	13,578,000
Future Benefit Payments
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		37.00%
Other Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, fair value of plan assets at beginning of year		$ 8,922,000
Defined Benefit Plan, fair value of plan assets at end of year		$ 12,533,000	8,922,000
Future Benefit Payments
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		27.00%
Accounting Standards Update 2018-02 [Member] | Cumulative Effect, Period of Adoption, Adjustment
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Stockholders' Equity Attributable to Parent		$ 0	$ 0	$ 2,969,000
[1]	(1) Please refer to Note 8 – Pension Benefits for additional discussion of the pension liability adjustment.

Pension Benefits Fair Value of

Pension Benefits Fair Value of Plan Assets in Heirarchy (Details) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	100.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	100.00%	100.00%
Defined Benefit Plan, Plan Assets, Amount	$ 32,894,000	$ 35,634,000	$ 30,100,000
Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	23,676,000	26,672,000
Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	3,482,000	3,214,000
Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	5,736,000	5,748,000	5,507,000
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases	0	0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Realized Gain on Assets	526,000	190,000
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Unrealized Gain on Assets	41,000	51,000
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Disposition	$ (579,000)	$ 0
Defined Benefit Plan, Equity Securities, US
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	18.70%	17.30%
Defined Benefit Plan, Plan Assets, Amount	$ 6,149,000	$ 6,176,000
Defined Benefit Plan, Equity Securities, US | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	4,165,000	4,130,000
Defined Benefit Plan, Equity Securities, US | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	1,984,000	2,046,000
Defined Benefit Plan, Equity Securities, US | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	$ 0	$ 0
Defined Benefit Plan, Equity Securities, Non-US
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	18.30%	19.60%
Defined Benefit Plan, Plan Assets, Amount	$ 6,010,000	$ 6,958,000
Defined Benefit Plan, Equity Securities, Non-US | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	6,010,000	6,958,000
Defined Benefit Plan, Equity Securities, Non-US | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Defined Benefit Plan, Equity Securities, Non-US | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	$ 0	$ 0
Defined Benefit Plan, Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	36.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	37.00%	36.90%
Defined Benefit Plan, Plan Assets, Amount	$ 12,159,000	$ 13,134,000
Defined Benefit Plan, Equity Securities | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	10,175,000	11,088,000
Defined Benefit Plan, Equity Securities | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	1,984,000	2,046,000
Defined Benefit Plan, Equity Securities | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	$ 0	$ 0
Core fixed income [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	16.60%	31.40%
Defined Benefit Plan, Plan Assets, Amount	$ 5,447,000	$ 11,199,000
Core fixed income [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	5,447,000	11,199,000
Core fixed income [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Core fixed income [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	$ 0	$ 0
Corporate Debt Securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	8.30%	6.70%
Defined Benefit Plan, Plan Assets, Amount	$ 2,755,000	$ 2,379,000
Corporate Debt Securities | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	2,755,000	2,379,000
Corporate Debt Securities | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Corporate Debt Securities | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	$ 0	$ 0
Total fixed income securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	37.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	24.90%	38.10%
Defined Benefit Plan, Plan Assets, Amount	$ 8,202,000	$ 13,578,000
Total fixed income securities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	8,202,000	13,578,000
Total fixed income securities [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Total fixed income securities [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	$ 0	$ 0
Defined Benefit Plan, Real Estate
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	5.70%	5.40%
Defined Benefit Plan, Plan Assets, Amount	$ 1,870,000	$ 1,929,000
Defined Benefit Plan, Real Estate | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Defined Benefit Plan, Real Estate | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Defined Benefit Plan, Real Estate | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	$ 1,870,000	$ 1,929,000
Defined Benefit Plan, Common Collective Trust
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	4.60%	3.30%
Defined Benefit Plan, Plan Assets, Amount	$ 1,498,000	$ 1,168,000
Defined Benefit Plan, Common Collective Trust | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Defined Benefit Plan, Common Collective Trust | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	1,498,000	1,168,000
Defined Benefit Plan, Common Collective Trust | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	$ 0	$ 0
Hedge fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	27.80%	16.30%
Defined Benefit Plan, Plan Assets, Amount	$ 9,165,000	$ 5,825,000
Hedge fund [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	5,299,000	2,006,000
Hedge fund [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Hedge fund [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	$ 3,866,000	$ 3,819,000
Total other securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	27.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	38.10%	25.00%
Defined Benefit Plan, Plan Assets, Amount	$ 12,533,000	$ 8,922,000
Total other securities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	5,299,000	2,006,000
Total other securities [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	1,498,000	1,168,000
Total other securities [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	5,736,000	5,748,000
Nonqualified Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	$ 0	$ 0	$ 0

Earnings Per Share (Details)

Earnings Per Share (Details) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2020USD ($)$ / sharesshares	Dec. 31, 2019USD ($)$ / sharesshares	Dec. 31, 2018USD ($)$ / sharesshares	Jun. 17, 2020$ / sharesshares	Aug. 12, 2016$ / shares
Earnings Per Share Reconciliation [Abstract]
Net income (loss) | $	$ (764,614)	$ (187,001)	$ 508,407
Basic weighted-average common shares outstanding	113,730	112,544	111,912
Dilutive effect of non-vested RSUs and contingent PSUs	0	0	1,590
Diluted weighted-average common shares outstanding	113,730	112,544	113,502
Basic net income (loss) per common share | $ / shares	$ (6.72)	$ (1.66)	$ 4.54
Diluted net income (loss) per common share | $ / shares	$ (6.72)	$ (1.66)	$ 4.48
Class of Warrant or Right, Number of Securities Called by Warrants or Rights				5,900
Exercise price of warrants | $ / shares				$ 0.01
Incremental Common Shares Attributable to Dilutive Effect of Warrants	0
Anti-dilutive shares excluded from earnings per share	265	684	0
1.50% Senior Unsecured Convertible Notes Due 2021 [Member]
Earnings Per Share Reconciliation [Abstract]
Capped Call, Cap Price | $ / shares					$ 60
Performance Shares (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Multiplier applied to PSU awards at settlement	0.9	0	0
Minimum [Member] | Performance Shares (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Multiplier applied to PSU awards at settlement	0
Maximum [Member] | Performance Shares (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Multiplier applied to PSU awards at settlement	2

Derivative Financial Instrume_3

Derivative Financial Instruments (Details) bbl in Thousands, BTU in Billions	Feb. 17, 2021BTU$ / Barrels$ / EnergyContentbbl	Dec. 31, 2020BTU$ / Barrels$ / EnergyContentbbl
NYMEX Oil Swap Contract First Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		3,613
Derivative, Swap Type, Average Fixed Price | $ / Barrels		42.91
NYMEX Oil Swap Contract Second Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		5,072
Derivative, Swap Type, Average Fixed Price | $ / Barrels		39.90
NYMEX Oil Swap Contract Third Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		4,862
Derivative, Swap Type, Average Fixed Price | $ / Barrels		40.10
NYMEX Oil Swap Contract Fourth Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		4,744
Derivative, Swap Type, Average Fixed Price | $ / Barrels		39.85
NYMEX Oil Swap Contract, 2022 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		6,601
Derivative, Swap Type, Average Fixed Price | $ / Barrels		43.99
NYMEX Oil Swap Contract, 2023 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		1,190
Derivative, Swap Type, Average Fixed Price | $ / Barrels		45.20
NYMEX Oil Swap Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		26,082
NYMEX Oil Collar Contract First Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		551
Derivative, Floor Price | $ / Barrels		48.97
Derivative, Ceiling Price | $ / Barrels		51.96
NYMEX Oil Collar Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		551
NYMEX Oil Roll Differential Swap Contract First Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		3,367
Derivative, Oil Roll Differential Swap, Weighted-Average Contract Price | $ / Barrels		(0.30)
NYMEX Oil Roll Differential Swap Contract Second Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		4,065
Derivative, Oil Roll Differential Swap, Weighted-Average Contract Price | $ / Barrels		(0.24)
NYMEX Oil Roll Differential Swap Contract Third Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		3,708
Derivative, Oil Roll Differential Swap, Weighted-Average Contract Price | $ / Barrels		(0.25)
NYMEX Oil Roll Differential Swap Contract Fourth Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		3,283
Derivative, Oil Roll Differential Swap, Weighted-Average Contract Price | $ / Barrels		(0.24)
NYMEX Oil Roll Differential Swap Contract, 2022 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		6,002
Derivative, Oil Roll Differential Swap, Weighted-Average Contract Price | $ / Barrels		(0.04)
NYMEX Oil Roll Differential Swap Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		20,425
WTI Midland NYMEX WTI [Member] | Oil Basis Swap Contract First Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		3,223
Derivative, Oil Basis Swap, Weighted-Average Contract Price | $ / Barrels		0.79
WTI Midland NYMEX WTI [Member] | Oil Basis Swap Contract Second Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		3,385
Derivative, Oil Basis Swap, Weighted-Average Contract Price | $ / Barrels		0.78
WTI Midland NYMEX WTI [Member] | Oil Basis Swap Contract Third Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		3,574
Derivative, Oil Basis Swap, Weighted-Average Contract Price | $ / Barrels		0.74
WTI Midland NYMEX WTI [Member] | Oil Basis Swap Contract Fourth Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		3,824
Derivative, Oil Basis Swap, Weighted-Average Contract Price | $ / Barrels		0.71
WTI Midland NYMEX WTI [Member] | Oil Basis Swap Contract, 2022 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		9,500
Derivative, Oil Basis Swap, Weighted-Average Contract Price | $ / Barrels		1.15
WTI Midland NYMEX WTI [Member] | Oil Basis Swap [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		23,506
NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract First Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		900
Derivative, Oil Basis Swap, Weighted-Average Contract Price | $ / Barrels		(7.86)
NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract Second Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		910
Derivative, Oil Basis Swap, Weighted-Average Contract Price | $ / Barrels		(7.86)
NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract Third Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		920
Derivative, Oil Basis Swap, Weighted-Average Contract Price | $ / Barrels		(7.86)
NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract Fourth Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		920
Derivative, Oil Basis Swap, Weighted-Average Contract Price | $ / Barrels		(7.86)
NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract, 2022 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		3,650
Derivative, Oil Basis Swap, Weighted-Average Contract Price | $ / Barrels		(7.78)
NYMEX WTI ICE Brent [Member] | Oil Basis Swap [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		7,300
WTI Houston MEH NYMEX WTI [Member] | Oil Basis Swap Contract First Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		173
Derivative, Oil Basis Swap, Weighted-Average Contract Price | $ / Barrels		0.60
WTI Houston MEH NYMEX WTI [Member] | Oil Basis Swap Contract Second Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		493
Derivative, Oil Basis Swap, Weighted-Average Contract Price | $ / Barrels		0.60
WTI Houston MEH NYMEX WTI [Member] | Oil Basis Swap Contract Third Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		356
Derivative, Oil Basis Swap, Weighted-Average Contract Price | $ / Barrels		0.60
WTI Houston MEH NYMEX WTI [Member] | Oil Basis Swap Contract Fourth Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		466
Derivative, Oil Basis Swap, Weighted-Average Contract Price | $ / Barrels		0.60
WTI Houston MEH NYMEX WTI [Member] | Oil Basis Swap Contract, 2022 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		0
Derivative, Oil Basis Swap, Weighted-Average Contract Price | $ / Barrels		0
WTI Houston MEH NYMEX WTI [Member] | Oil Basis Swap [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		1,488
IF HSC [Member] | Gas Swaps Contract First Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU		11,592
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent		2.48
IF HSC [Member] | Gas Swaps Contract Second Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU		13,672
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent		2.45
IF HSC [Member] | Gas Swaps Contract Third Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU		12,575
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent		2.40
IF HSC [Member] | Gas Swaps Contract Fourth Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU		12,412
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent		2.41
IF HSC [Member] | Gas Swaps Contract, 2022 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU		21,119
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent		2.48
IF HSC [Member] | Gas Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU		71,370
WAHA [Member] | Gas Swaps Contract First Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU		6,544
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent		1.76
WAHA [Member] | Gas Swaps Contract Second Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU		7,230
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent		1.76
WAHA [Member] | Gas Swaps Contract Third Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU		8,086
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent		1.88
WAHA [Member] | Gas Swaps Contract Fourth Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU		7,627
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent		1.82
WAHA [Member] | Gas Swaps Contract, 2022 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU		10,066
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent		2.30
WAHA [Member] | Gas Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU		39,553
IF WAHA [Member]
Derivative Financial Instruments
Index percent of natural gas fixed swaps		59.00%
GD Waha [Member]
Derivative Financial Instruments
Index percent of natural gas fixed swaps		41.00%
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract First Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		614
Derivative, Swap Type, Average Fixed Price | $ / Barrels		21.58
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Second Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		707
Derivative, Swap Type, Average Fixed Price | $ / Barrels		21.26
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		735
Derivative, Swap Type, Average Fixed Price | $ / Barrels		21.26
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		714
Derivative, Swap Type, Average Fixed Price | $ / Barrels		21.30
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract, 2022 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		116
Derivative, Swap Type, Average Fixed Price | $ / Barrels		21.21
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		2,886
Subsequent Event [Member] | NYMEX Oil Swap Contract, First Quarter to Third Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	1,048
Derivative, Swap Type, Average Fixed Price | $ / Barrels	51.91
Subsequent Event [Member] | NYMEX Oil Swap Contract, 2022 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	1,222
Derivative, Swap Type, Average Fixed Price | $ / Barrels	48.50
Subsequent Event [Member] | NYMEX Oil Collar Contract, 2022 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	1,095
Derivative, Floor Price | $ / Barrels	50
Derivative, Ceiling Price | $ / Barrels	53.28
Subsequent Event [Member] | NYMEX Oil Roll Differential Swap Contract, First Quarter to Fourth Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	2,213
Derivative, Oil Roll Differential Swap, Weighted-Average Contract Price | $ / Barrels	0.30
Subsequent Event [Member] | NYMEX Oil Roll Differential Swap Contract, 2022 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	5,276
Derivative, Oil Roll Differential Swap, Weighted-Average Contract Price | $ / Barrels	0.27
Subsequent Event [Member] | WTI Midland NYMEX WTI [Member] | Oil Basis Swap Contract, First Quarter to Third Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	1,095
Derivative, Oil Basis Swap, Weighted-Average Contract Price | $ / Barrels	0.95
Subsequent Event [Member] | WTI Houston MEH NYMEX WTI [Member] | Oil Basis Swap Contract, 2022 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	1,329
Derivative, Oil Basis Swap, Weighted-Average Contract Price | $ / Barrels	1.25
Subsequent Event [Member] | IF HSC [Member] | Gas Swaps Contract, 2022 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU	7,813
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent	2.64
Subsequent Event [Member] | IF WAHA [Member] | Gas Swaps Contract, 2022 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU	3,650
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent	2.30
Subsequent Event [Member] | OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract First Quarter to Fourth Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	440
Derivative, Swap Type, Average Fixed Price | $ / Barrels	27.72
Subsequent Event [Member] | OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract, 2022 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	115
Derivative, Swap Type, Average Fixed Price | $ / Barrels	24.78
Subsequent Event [Member] | OPIS Propane Mont Belvieu Non-TET [Member] | NGL Collar Contract, 2022 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	234
Derivative, Floor Price | $ / Barrels	22.05
Derivative, Ceiling Price | $ / Barrels	27.30
Subsequent Event [Member] | OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract First Quarter to Fourth Quarter, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	143
Derivative, Swap Type, Average Fixed Price | $ / Barrels	30.87

Derivative Financial Instrume_4

Derivative Financial Instruments Fair Value (Details) $ in Thousands	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018
Fair value of derivative assets and liabilities
Derivative, Fair Value, Net	$ (168,200)	$ 21,500
Derivative Assets, Current	31,203	55,184
Derivative Assets, Noncurrent	23,150	20,624
Total Derivative Assets	54,353	75,808
Derivative Liabilities, Current	200,189	50,846
Derivative Liabilities, Noncurrent	22,331	3,444
Total Derivative Liabilities	(222,520)	(54,290)
Derivative Asset, Not Offset in the Accompanying Balance Sheets	(53,598)	(35,075)
Derivative Liabilities, Not Offset in the Accompanying Balance Sheets	53,598	35,075
Derivative Asset, Fair Value, Net Amounts	755	40,733
Derivative Liabilities, Fair Value, Net Amounts	(168,922)	(19,215)
Not Designated as Hedging Instrument [Member]
Fair value of derivative assets and liabilities
Derivative Assets, Current	31,203	55,184
Derivative Assets, Noncurrent	23,150	20,624
Derivative Liabilities, Current	200,189	50,846
Derivative Liabilities, Noncurrent	22,331	3,444
Fair Value, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Not Designated as Hedging Instrument [Member]
Fair value of derivative assets and liabilities
Total Derivative Assets	54,353	75,808
Total Derivative Liabilities	$ 222,520	$ 54,290
Designated as Hedging Instrument [Member]
Fair value of derivative assets and liabilities
Derivative, Number of Instruments Held	0	0	0

Derivative Financial Instrume_5

Derivative Financial Instruments Gains and Losses (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments, (Gain) Loss [Line Items]
Derivative settlement (gain) loss	$ (351,261)	$ (39,222)	$ 135,803
Net derivative (gain) loss	(161,576)	97,539	(161,832)
Oil Contracts [Member]
Derivative Instruments, (Gain) Loss [Line Items]
Derivative settlement (gain) loss	(331,559)	19,685	68,860
Net derivative (gain) loss	(205,180)	172,055	(192,002)
Gas Contracts [Member]
Derivative Instruments, (Gain) Loss [Line Items]
Derivative settlement (gain) loss	(11,898)	(23,008)	13,029
Net derivative (gain) loss	30,038	(41,205)	35,411
NGL Contracts [Member]
Derivative Instruments, (Gain) Loss [Line Items]
Derivative settlement (gain) loss	(7,804)	(35,899)	53,914
Net derivative (gain) loss	$ 13,566	$ (33,311)	$ (5,241)

Derivative Financial Instrume_6

Derivative Financial Instruments Credit Facility (Details)	Dec. 31, 2020
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Percentage of Proved Property Secured for Credit Facility Borrowing	85.00%

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	Jun. 17, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Aug. 20, 2018	Sep. 12, 2016	Aug. 12, 2016	May 21, 2015	Nov. 17, 2014	May 20, 2013
Assets:
Derivative Assets, Fair Value, Gross Asset		$ 54,353	$ 75,808
Liabilities:
Derivative Liability, Fair Value, Gross Liability		(222,520)	(54,290)
Oil and Gas Properties
Impairment of proved oil and gas properties and related support equipment		956,700	0	$ 0
Abandonment and impairment of unproved properties		59,300	33,800	49,900
Impairment		1,016,013	33,842	$ 49,889
Property, Plant, and Equipment, Fair Value Disclosure		0	0
Debt Instrument, Fair Value Disclosure [Abstract]
Class of Warrant or Right, Number of Securities Called by Warrants or Rights	5,900
Warrants Percent of Outstanding Stock	5.00%
Exercise price of warrants	$ 0.01
Warrant triggering date - amount	$ 1,000,000
Issuance of warrants	21,500	$ 21,520
1.50% Senior Secured Convertible Notes Due 2021 [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Senior Notes, interest rate, stated percentage		1.50%
Principal amount		$ 65,485	0
Fair value		$ 61,449	0
10.0% Senior Secured Notes due 2025 [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Senior Notes, interest rate, stated percentage		10.00%
Principal amount	$ 446,700	$ 446,675	0
Fair value		$ 482,887	$ 0
6.125% Senior Unsecured Notes Due 2022 [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Senior Notes, interest rate, stated percentage	6.125%	6.125%	6.125%						6.125%
Principal amount		$ 212,403	$ 476,796						$ 600,000
Fair value		$ 205,379	$ 481,564
5.0% Senior Unsecured Notes Due 2024 [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Senior Notes, interest rate, stated percentage	5.00%	5.00%	5.00%							5.00%
Principal amount		$ 277,034	$ 500,000							$ 500,000
Fair value		$ 240,072	$ 479,815
5.625% Senior Unsecured Notes Due 2025 [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Senior Notes, interest rate, stated percentage	5.625%	5.625%	5.625%					5.625%
Principal amount		$ 349,118	$ 500,000					$ 500,000
Fair value		$ 289,401	$ 475,835
6.75% Senior Unsecured Notes Due 2026 [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Senior Notes, interest rate, stated percentage	6.75%	6.75%	6.75%			6.75%
Principal amount		$ 419,235	$ 500,000			$ 500,000
Fair value		$ 342,385	$ 494,860
6.625% Senior Unsecured Notes Due 2027 [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Senior Notes, interest rate, stated percentage	6.625%	6.625%	6.625%		6.625%
Principal amount		$ 416,791	$ 500,000		$ 500,000
Fair value		$ 331,220	$ 493,750
1.50% Senior Unsecured Convertible Notes Due 2021 [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Senior Notes, interest rate, stated percentage		1.50%	1.50%
Principal amount		$ 0	$ 172,500				$ 172,500
Fair value		$ 0	164,430
Fair Value, Nonrecurring [Member] | Measurement Input, Discount Rate [Member] | Oil and Gas Properties [Member]
Oil and Gas Properties
Fair value assumptions, measurement input		0.11
Not Designated as Hedging Instrument [Member] | Fair Value, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Assets:
Derivative Assets, Fair Value, Gross Asset		$ 0	0
Liabilities:
Derivative Liability, Fair Value, Gross Liability		0	0
Not Designated as Hedging Instrument [Member] | Fair Value, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Assets:
Derivative Assets, Fair Value, Gross Asset		54,353	75,808
Liabilities:
Derivative Liability, Fair Value, Gross Liability		222,520	54,290
Not Designated as Hedging Instrument [Member] | Fair Value, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Assets:
Derivative Assets, Fair Value, Gross Asset		0	0
Liabilities:
Derivative Liability, Fair Value, Gross Liability		$ 0	$ 0

Leases Lease Parameter (Details

Leases Lease Parameter (Details)	Dec. 31, 2020	Dec. 31, 2019
Lessee, Lease, Description [Line Items]
Weighted average remaining lease term	3 years	3 years
Optional extension period	10 years
Minimum [Member]
Lessee, Lease, Description [Line Items]
Remaining lease term	1 year
Maximum [Member]
Lessee, Lease, Description [Line Items]
Remaining lease term	5 years

Components of total lease cost

Components of total lease cost (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Lessee Disclosure [Abstract]
Total lease cost	$ 232,730	$ 442,949
Operating lease cost	17,980	35,570
Short-term lease cost	143,892	301,373
Variable lease cost	70,858	106,006
Operating cash flows from operating leases	12,046	12,074
Investing cash flows from operating leases	7,313	24,129
Right-of-use assets obtained in exchange for new operating lease liabilities	$ 745	$ 25,400

Operating lease liability matur

Operating lease liability maturities (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Lessee Disclosure [Abstract]
Operating lease liability payments, due 2021	$ 12,781
Operating lease liability payments, due 2022	5,891
Operating lease liability payments, due 2023	3,591
Operating lease liability payments, due 2024	2,081
Operating lease liability payments, due 2025	1,222
Operating lease liability payments, due thereafter	417
Total Lease payments	25,983
Imputed interest	(2,426)
Total operating lease liability	$ 23,557
Weighted-average discount rate	7.00%	6.60%

Balance Sheet information relat

Balance Sheet information related to operating leases (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Lessee Disclosure [Abstract]
Other noncurrent assets	$ 21,701	$ 39,717
Other current liabilities	11,659	19,189
Other noncurrent liabilities	$ 11,898	$ 23,137
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	us-gaap:OtherLiabilitiesCurrent	us-gaap:OtherLiabilitiesCurrent
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	us-gaap:OtherLiabilitiesNoncurrent	us-gaap:OtherLiabilitiesNoncurrent

Accounts Receivable (Details)

Accounts Receivable (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Accounts Receivable
Accounts receivable	$ 162,455	$ 184,732
Oil, gas, and NGL production revenue [Member]
Accounts Receivable
Accounts receivable	108,928	146,308
Amounts due from joint interest owners [Member]
Accounts Receivable
Accounts receivable	31,514	22,681
State severance tax refunds [Member]
Accounts Receivable
Accounts receivable	2,301	4,069
Derivative settlements [Member]
Accounts Receivable
Accounts receivable	16,348	6,868
Other [Member]
Accounts Receivable
Accounts receivable	$ 3,364	$ 4,806

Accounts Payable and Accrued Ex

Accounts Payable and Accrued Expenses (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Accounts Payable and Accrued Liabilities, Current [Abstract]
Drilling and lease operating cost accruals	$ 65,365	$ 96,925
Trade accounts payable	63,006	52,094
Revenue and severance tax payable	105,233	109,847
Property taxes	20,584	24,535
Compensation	30,907	41,540
Derivative settlements	1,146	5,851
Interest	52,802	44,175
Other	32,627	27,041
Total accounts payable and accrued expenses	$ 371,670	$ 402,008

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning asset retirement obligations	$ 86,846	$ 94,194
Liabilities incurred	1,018	3,927
Liabilities settled	(1,404)	(4,105)
Accretion expense	4,034	4,016
Revision to estimated cash flows	(5,169)	(11,186)
Ending asset retirement obligations	85,325	86,846
Current asset retirement obligation liability	$ 2,000	$ 2,700

Suspended Well Costs (Details)

Suspended Well Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Net changes in capitalized exploratory well costs
Beginning balance	$ 11,925	$ 11,197	$ 49,446
Additions to capitalized exploratory well costs pending the determination of proved reserves	3,346	11,925	11,197
Divestitures	0	0	(109)
Reclassifications based on the determination of proved reserves	(9,573)	(11,197)	(49,337)
Capitalized exploratory well costs charged to expense	0	0	0
Ending balance	5,698	$ 11,925	$ 11,197
Exploratory well costs capitalized for more than one year	$ 0

Uncategorized Items - sm-202012

Label	Element	Value
Cumulative Effect, Period of Adoption, Adjustment [Member] | AOCI Attributable to Parent [Member]
Stockholders' Equity Attributable to Parent	us-gaap_StockholdersEquity	$ (2,969,000)
Cumulative Effect, Period of Adoption, Adjustment [Member] | Retained Earnings [Member]
Stockholders' Equity Attributable to Parent	us-gaap_StockholdersEquity	$ 2,969,000