SM Energy (SM) 10-K 20 Feb 20 2019 FY Annual report Financial data

Cover page

Cover page - USD ($)	12 Months Ended
	Dec. 31, 2019	Feb. 06, 2020	Jun. 28, 2019
Cover page.
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2019
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	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 1,392,750,253
Entity Common Stock, Shares Outstanding		112,988,364
Documents Incorporated by Reference	Certain information required by Items 10, 11, 12, 13, and 14 of Part III is incorporated by reference from portions of the registrant’s Definitive Proxy Statement on Schedule 14A relating to its 2020 annual meeting of stockholders to be filed within 120 days after December 31, 2019 .
Entity Central Index Key	0000893538
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2019
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, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 10	$ 77,965
Accounts receivable	184,732	167,536
Derivative assets	55,184	175,130
Prepaid expenses and other	12,708	8,632
Total current assets	252,634	429,263
Property and equipment (successful efforts method):
Proved oil and gas properties	8,934,020	7,278,362
Accumulated depletion, depreciation, and amortization	(4,177,876)	(3,417,953)
Unproved oil and gas properties	1,005,887	1,581,401
Wells in progress	118,769	295,529
Other property and equipment, net of accumulated depreciation of $64,032 and $57,102, respectively	72,848	93,826
Total property and equipment, net	5,953,648	5,831,165
Noncurrent assets:
Derivative assets	20,624	58,499
Other noncurrent assets	65,326	33,935
Total noncurrent assets	85,950	92,434
Total assets	6,292,232	6,352,862
Current liabilities:
Accounts payable and accrued expenses	402,008	403,199
Derivative liabilities	50,846	62,853
Other current liabilities	19,189	0
Total current liabilities	472,043	466,052
Noncurrent liabilities:
Revolving credit facility	122,500	0
Senior Notes, net of unamortized deferred financing costs	2,453,035	2,448,439
Senior Convertible Notes, net of unamortized discount and deferred financing costs	157,263	147,894
Asset retirement obligations	84,134	91,859
Deferred income taxes	189,386	223,278
Derivative liabilities	3,444	12,496
Other noncurrent liabilities	61,433	42,522
Total noncurrent liabilities	3,071,195	2,966,488
Commitments and contingencies (note 6)
Stockholders' Equity:
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 112,987,952 and 112,241,966 shares, respectively	1,130	1,122
Additional paid-in capital	1,791,596	1,765,738
Retained earnings	967,587	1,165,842
Accumulated other comprehensive loss	(11,319)	(12,380)
Total stockholders' equity	2,748,994	2,920,322
Total liabilities and stockholders' equity	$ 6,292,232	$ 6,352,862

CONSOLIDATED BALANCE SHEETS (_2

CONSOLIDATED BALANCE SHEETS (in thousands, except share data) Parenthetical - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Other property and equipment, accumulated depreciation	$ 64,032	$ 57,102
Common Stock, par value per share	$ 0.01	$ 0.01
Common Stock, shares authorized	200,000,000	200,000,000
Common Stock, shares issued	112,987,952	112,241,966
Common Stock, shares outstanding	112,987,952	112,241,966

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, 2019		Dec. 31, 2018		Dec. 31, 2017
Operating revenues and other income:
Oil, gas, and NGL production revenue	$ 1,585,750	[1]	$ 1,636,357	[2]	$ 1,253,783	[3]
Net gain (loss) on divestiture activity	862		426,917		(131,028)
Other operating revenues	3,493		3,798		6,621
Total operating revenues and other income	1,590,105		2,067,072		1,129,376
Operating expenses:
Oil, gas, and NGL production expense	500,709		487,367		507,906
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	823,798		665,313		557,036
Exploration	51,500		55,166		54,713
Impairment of oil and gas properties	33,842		49,889		16,078
General and administrative	132,797		116,504		117,283
Net derivative (gain) loss	97,539		(161,832)		26,414
Other operating expenses, net	19,888		18,328		13,667
Total operating expenses	1,660,073		1,230,735		1,293,097
Income (loss) from operations	(69,968)		836,337		(163,721)
Interest expense	(159,102)		(160,906)		(179,257)
Loss on extinguishment of debt	0		(26,740)		(35)
Other non-operating income (expense), net	(1,974)		3,086		(800)
Income (loss) before income taxes	(231,044)		651,777		(343,813)
Income tax (expense) benefit	44,043		(143,370)		182,970
Net income (loss)	$ (187,001)		$ 508,407		$ (160,843)
Basic weighted-average common shares outstanding	112,544		111,912		111,428
Diluted weighted-average common shares outstanding	112,544		113,502		111,428
Basic net income (loss) per common share	$ (1.66)		$ 4.54		$ (1.44)
Diluted net income (loss) per common share	$ (1.66)		$ 4.48		$ (1.44)
[1]	Note: Amounts may not calculate due to rounding.
[2]	Note: Amounts may not calculate due to rounding.
[3]	Note: Amounts may not calculate due to rounding.

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (in thousands) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement of Comprehensive Income [Abstract]
Net income (loss)		$ (187,001)	$ 508,407	$ (160,843)
Other comprehensive income, net of tax:
Pension liability adjustment	[1]	1,061	4,378	767
Total other comprehensive income, net of tax		1,061	4,378	767
Total comprehensive income (loss)		$ (185,940)	$ 512,785	$ (160,076)
[1]	(1) Please refer to Note 8 – Pension Benefits for additional discussion on 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, 2016		111,257,500
Balances, Total Stockholders' Equity, Beginning at Dec. 31, 2016	$ 2,497,133	$ 1,113	$ 1,716,556	$ 794,020	$ (14,556)
Increase (Decrease) in Stockholders' Equity
Net income (loss)	(160,843)			(160,843)
Other comprehensive income	767				767
Cash dividends, $ 0.10 per share	(11,144)			(11,144)
Issuance of common stock under Employee Stock Purchase Plan (Shares)		186,665
Issuance of common stock under Employee Stock Purchase Plan (Amount)	2,623	$ 2	2,621
Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings (Shares)		171,278
Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings (Amount)	(1,240)	$ 1	(1,241)
Stock-based compensation expense (Shares)		71,573
Stock-based compensation expense (Amount)	22,700	$ 1	22,699
Other	(120)		(120)
Balances, Common Stock, Shares, Outstanding, Ending at Dec. 31, 2017		111,687,016
Balances, Total Stockholders' Equity, Ending at Dec. 31, 2017	$ 2,394,608	$ 1,117	1,741,623	665,657	(13,789)
Cash dividends per share	$ 0.10
Increase (Decrease) in Stockholders' Equity
Net income (loss)	$ 508,407			508,407
Other comprehensive income	4,378				4,378
Cash dividends, $ 0.10 per share	(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, net of shares used for tax withholdings (Shares)		291,745
Issuance of common stock upon vesting of RSUs, 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	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	1,061				1,061
Cash dividends, $ 0.10 per share	(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, net of shares used for tax withholdings (Shares)		334,399
Issuance of common stock upon vesting of RSUs, 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)

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash flows from operating activities:
Net income (loss)	$ (187,001)	$ 508,407	$ (160,843)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net (gain) loss on divestiture activity	(862)	(426,917)	131,028
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	823,798	665,313	557,036
Impairment of oil and gas properties	33,842	49,889	16,078
Stock-based compensation expense	24,318	23,908	22,700
Net derivative (gain) loss	97,539	(161,832)	26,414
Derivative settlement gain (loss)	39,222	(135,803)	21,234
Amortization of debt discount and deferred financing costs	15,474	15,258	16,276
Loss on extinguishment of debt	0	26,740	35
Deferred income taxes	(41,835)	141,708	(192,066)
Other, net	2,220	287	7,885
Changes in current assets and liabilities:
Accounts receivable	(39,556)	(20,775)	20,410
Prepaid expenses and other	6,130	(729)	(1,953)
Accounts payable and accrued expenses	50,278	35,175	51,156
Net cash provided by operating activities	823,567	720,629	515,390
Cash flows from investing activities:
Net proceeds from the sale of oil and gas properties	13,059	748,509	776,719
Capital expenditures	(1,023,769)	(1,303,188)	(888,353)
Acquisition of proved and unproved oil and gas properties	(2,581)	(33,255)	(89,896)
Net cash used in investing activities	(1,013,291)	(587,934)	(201,530)
Cash flows from financing activities:
Proceeds from credit facility	1,589,000	0	406,000
Repayment of credit facility	(1,466,500)	0	(406,000)
Net proceeds from Senior Notes	0	492,079	0
Cash paid to repurchase Senior Notes, including premium	0	(845,002)	(2,357)
Net proceeds from sale of common stock	3,209	3,187	2,623
Dividends paid	(11,254)	(11,191)	(11,144)
Other, net	(2,686)	(7,746)	(1,411)
Net cash provided by (used in) financing activities	111,769	(368,673)	(12,289)
Net change in cash, cash equivalents, and restricted cash	(77,955)	(235,978)	301,571
Cash, cash equivalents, and restricted cash at beginning of period	77,965	313,943	12,372
Cash, cash equivalents, and restricted cash at end of period	10	77,965	313,943
Supplemental Cash Flow Information - Operating Activities [Abstract]
Cash paid for interest, net of capitalized interest	(141,902)	(150,727)	(164,097)
Net cash (paid) refunded for income taxes	6,109	(2,995)	(5,986)
Supplemental Cash Flow Information - Investing Activities [Abstract]
Changes in capital expenditure accruals and other	(24,289)	(2,774)	7,309
Supplemental Cash Flow Information - Non-Cash Investing Activities [Abstract]
Carrying value of properties exchanged	73,442	95,121	293,963
Supplemental Cash Flow Information - Non-Cash Financing Activities [Abstract]
Non-cash loss on extinguishment of debt, net	$ 0	$ 6,334	$ 22

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2019
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 consolidated financial statements, the Company evaluated events subsequent to the balance sheet date of December 31, 2019 , through the filing of this report. Additionally, certain prior period amounts have been reclassified to conform to current period presentation in the 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 depletion, depreciation, and amortization expense, impairment of proved 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 consists mainly of receivables 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 regions. The following major customers and entities under common control accounted for 10 percent or more of its total oil, gas, and NGL production revenue for at least one of the periods presented: For the Years Ended December 31, 2019 2018 2017 Major customer #1 (1) 18 % 18 % 6 % Major customer #2 (1) 14 % 5 % 1 % Major customer #3 (1) 13 % 7 % — % Major customer #4 (1) 9 % 10 % 10 % Group #1 of entities under common control (2) 13 % 18 % 17 % Group #2 of entities under common control (2) 11 % 12 % 8 % ____________________________________________ (1) These major customers are purchasers of a portion of the Company’s production from its Midland Basin assets. (2) In the aggregate, these groups of entities under common control represented purchasers of more than 10 percent 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 percent 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 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. The Company maintains investments in highly rated, highly liquid investment products with numerous banks that are party to its revolving credit facility. 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 a 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 group asset basis; however, the units-of-production method is based on estimated total proved oil and gas reserves. The computation of DD&A 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 and reduced to fair value when there is an indication that associated carrying costs may not be recoverable. The Company uses an income valuation technique, which converts future cash flow to a single present value amount, to measure the fair value of proved properties through an application of discount rates and price forecasts, as selected by the Company’s management. The Company uses discount rates that are representative of current market conditions and considers estimates of future cash payments, reserve categories, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The discount rates typically range from 10 percent to 15 percent based on the reservoir specific weightings of future estimated proved and unproved cash flows. 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 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. 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 balance sheets consists of 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 a units-of-production basis. 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 prospect and the portion of such costs estimated to be nonproductive prior to lease expiration are 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 a 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 wells 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 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 oil and gas properties. 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, 2019 , and 2018 . 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 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 derivative commodity 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, 2019 , the Company had stock-based employee compensation plans that included restricted stock units (“RSUs”) and performance share units (“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 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. Please refer to Note 4 – Income Taxes for additional disclosure. Earnings per Share The Company uses the treasury stock method to determine the potential dilutive effect of non-vested RSUs, contingent PSUs, and Senior Convertible Notes. 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 credit facility approximates its fair value as it bears interest at a floating rate that approximates a current market rate. The Company had a $122.5 million balance under its credit facility as of December 31, 2019 , compared with a zero balance as of December 31, 2018 . The Company’s Senior Notes and Senior Convertible Notes 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 . 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 2019 or 2018 . Recently Issued Accounting Standards Effective January 1, 2017, the Company adopted, using various transition methods, Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). ASU 2016-09 is meant to simplify certain aspects of accounting for share-based arrangements, including income tax effects, accounting for forfeitures, and net share settlements. The Company adopted the various applicable amendments, which are summarized as follows: • On January 1, 2017, a $44.3 million cumulative-effect adjustment was made to retained earnings and a corresponding deferred tax asset was recorded for previously unrecognized excess tax benefits using a modified retrospective transition method. Effective January 1, 2017, excess tax benefits are presented in net cash provided by operating activities on the accompanying statements of cash flows. • On January 1, 2017, the Company elected to change its policy to account for forfeitures of share-based payment awards as they occur, rather than applying an estimated forfeiture rate. This change was made using a modified retrospective transition method and resulted in an increase in additional paid-in capital of $1.1 million , a decrease in deferred tax assets of $400,000 , and a net $700,000 cumulative effect decrease to retained earnings. • Under this new guidance, excess tax benefits and deficiencies from share-based payments impact the Company’s effective tax rate between periods. In February 2016, the FASB issued 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 guidance is to be applied using a modified retrospective method and is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. The Company adopted ASU 2016-13 on January 1, 2020. The adoption of ASU 2016-13 is not expected to result in a material impact to the Company’s consolidated financial statements or disclosures. In March 2017, the FASB issued ASU No. 2017-07, Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (“ASU 2017-07”). ASU 2017-07 requires presentation of service cost in the same line item(s) as other compensation costs arising from services rendered by employees during the period, and presentation of the remaining components of net benefit cost in a separate line item, outside operating items. In addition, only the service cost component of net benefit cost is eligible for capitalization. The Company adopted ASU 2017-07 on the effective date of January 1, 2018, with retrospective application of the service cost component and the other components of net benefit cost in the consolidated statements of operations, and prospective application for the capitalization of the service cost component of net benefit costs in assets. While the adoption of ASU 2017-07 resulted in the Company reclassifying certain amounts from operating expenses to non-operating expenses, ASU 2017-07 did not result in a material impact to the Company’s consolidated financial statements or disclosures. In February 2018, the FASB issued ASU No. 2018-02, Income Statement – Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (“ASU 2018-02”). ASU 2018-02 permits entities to reclassify tax effects stranded in accumulated other comprehensive income (loss) to retained earnings as a result of the 2017 Tax Act. The Company early adopted ASU 2018-02 effective January 1, 2018 using a retrospective method. As a result of adopting ASU 2018-02, the Company reclassified $3.0 million of tax effects stranded in accumulated other comprehensive loss to retained earnings as of January 1, 2018. The Company’s policy for releasing income tax effects within accumulated other comprehensive loss is an incremental, unit-of-account approach. 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. The adoption of ASU 2018-15 is not expected to have a material impact to the Company’s consolidated financial statements or 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. ASU 2019-12 is effective for fiscal years beginning after December 15, 2020, with early adoption permitted. The Company is evaluating the impact of ASU 2019-12 on its consolidated financial statements. 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, 2019 , and through the filing of this report.

Revenue from Contracts with Cus

Revenue from Contracts with Customers	12 Months Ended
	Dec. 31, 2019
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 in its Midland Basin and South Texas assets. 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. 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 the oil, gas, and NGL production revenue by product type for each of the Company’s operating regions for the years ended December 31, 2019 , 2018 , and 2017 : 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 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. For the year ended December 31, 2017 Midland Basin South Texas Rocky Mountain Total (in thousands) Oil production revenue $ 419,732 $ 82,674 $ 151,844 $ 654,250 Gas production revenue 61,781 301,780 5,849 369,410 NGL production revenue 547 226,031 3,545 230,123 Total $ 482,060 $ 610,485 $ 161,238 $ 1,253,783 Relative percentage 38 % 49 % 13 % 100 % ____________________________________________ Note: Amounts may not calculate due to rounding. The Company recognizes oil, gas, and NGL production revenue at the point in time when 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 the inlet of 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 based on the proceeds the processor realizes from selling the NGLs to third parties. For the residue gas taken in-kind, the Company has separate sales contracts where control transfers at points downstream of the processing facility. 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 customers 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, 2019 , and 2018 , were $146.3 million and $107.2 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.

Divestitures, Assets Held for S

Divestitures, Assets Held for Sale, and Acquisitions	12 Months Ended
	Dec. 31, 2019
Divestitures, Assets Held for Sale, and Acquisitions Disclosure [Abstract]
Divestitures, Assets Held for Sale, and Acquisitions [Text Block]	Note 3 – Divestitures, Assets Held for Sale, and Acquisitions 2019 Divestiture Activity No material divestitures occurred during 2019 . 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 (referred to throughout this report as “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 following table presents loss before income taxes from the Divide County, North Dakota assets sold for the years ended December 31, 2019 , 2018 , and 2017 . The Divide County Divestiture was considered a disposal of a significant asset group. For the Years Ended December 31, 2019 2018 2017 (in thousands) Loss before income taxes (1) $ — $ (28,975 ) $ (468,786 ) ____________________________________________ (1) 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. During the year ended December 31, 2017 , the Company recorded a write-down of $523.6 million on these assets. 2017 Divestiture Activity Eagle Ford Divestiture. On March 10, 2017, the Company divested its outside-operated Eagle Ford shale assets, including its ownership interest in related midstream assets, for final net divestiture proceeds of $744.1 million . The Company recorded a final net gain of $396.8 million related to these divested assets for the year ended December 31, 2017 . This divestiture was considered a disposal of a significant asset group. For the year ended December 31, 2017 , income before income taxes from the outside-operated Eagle Ford shale assets sold was $24.3 million . This amount reflects oil, gas, and NGL production revenue, less oil, gas, and NGL production expense, and depletion, depreciation, amortization, and asset retirement obligation liability accretion expense. During 2017, the Company divested certain non-core properties for net divestiture proceeds of $36.2 million and recognized an insignificant final net gain. The Company determined that executed asset sales in 2018 and 2017 did not qualify for discontinued operations accounting under financial statement presentation authoritative guidance. 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 Martin and Howard 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. 2017 Acquisition Activity During the year ended December 31, 2017 , the Company acquired approximately 3,600 net acres of primarily unproved properties in Howard and Martin Counties, Texas, in multiple transactions for a total of $76.5 million of cash consideration. Under authoritative accounting guidance, these transactions were 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. Also during the year ended December 31, 2017 , the Company completed several non-monetary acreage trades of primarily unproved properties in Howard and Martin Counties, Texas, resulting in the exchange of approximately 8,125 net acres for approximately 7,580 net acres with $294.0 million of carrying value attributed to the properties transferred by the Company in such trades. These trades were recorded at carryover basis with no gain or loss recognized.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2019
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, 2019 2018 2017 (in thousands) Current portion of income tax expense (benefit) Federal $ (3,826 ) $ — $ 5,698 State 1,618 1,662 3,398 Deferred portion of income tax expense (benefit) (41,835 ) 141,708 (192,066 ) Income tax expense (benefit) $ (44,043 ) $ 143,370 $ (182,970 ) Effective tax rate 19.1 % 22.0 % 53.2 % The components of the net deferred tax liabilities are as follows: As of December 31, 2019 2018 (in thousands) Deferred tax liabilities Oil and gas properties $ 205,028 $ 218,094 Derivative assets 4,646 35,247 Other 12,361 4,812 Total deferred tax liabilities 222,035 258,153 Deferred tax assets Credit carryover 11,270 22,554 Pension 5,971 6,427 Federal and state tax net operating loss carryovers 4,172 4,217 Stock compensation 3,503 3,263 Other liabilities 10,803 1,497 Total deferred tax assets 35,719 37,958 Valuation allowance (3,070 ) (3,083 ) Net deferred tax assets 32,649 34,875 Total net deferred tax liabilities $ 189,386 $ 223,278 Current federal income tax refundable $ 3,885 $ 59 Current state income tax payable $ 1,404 $ 1,331 As of December 31, 2019 , the Company estimated its federal net operating loss (“NOL”) carryforward at $3.3 million and state NOL carryforwards at $77.8 million . The Company has federal research and development (“R&D”) and AMT credit carryforwards of $7.4 million and $4.3 million , respectively. The majority of federal NOLs do not expire but the state NOLs and state tax credits expire between 2021 and 2038. The federal R&D credit carryforwards expire between 2028 and 2035. The Company’s AMT credit carryforwards are expected to be fully refunded by 2022. 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. 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 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, and the cumulative impact of other smaller permanent differences, and is reported as follows: For the Years Ended December 31, 2019 2018 2017 (in thousands) Federal statutory tax expense (benefit) $ (48,519 ) $ 136,873 $ (120,335 ) Increase (decrease) in tax resulting from: Federal tax reform changes - 2017 Tax Act — — (63,675 ) State tax expense (benefit) (net of federal benefit) 260 2,771 (3,286 ) Change in valuation allowance (13 ) 105 (2,727 ) Employee share-based compensation 3,346 2,508 8,190 Other 883 1,113 (1,137 ) Income tax expense (benefit) $ (44,043 ) $ 143,370 $ (182,970 ) 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. During the fourth quarter of 2019, the Company claimed and received a $7.7 million refund for a portion of its deferred AMT credit carryover. An additional refund of $3.8 million is expected to be claimed in 2020. For all years before 2015, 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 Company does not expect a significant change to the recorded unrecognized tax benefits in 2020 . The total amount recorded for unrecognized tax benefits for each of the years ended December 31, 2019 , 2018 , and 2017 , was $446,000 .

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Long-Term Debt	Note 5 – Long-Term Debt Credit Agreement On September 19, 2019, the Company and its lenders entered into the Second Amendment to the Sixth Amended and Restated Credit Agreement which permitted the Company to enter into swap agreements with respect to the price of electricity in order to minimize exposure to electrical price volatility. As of December 31, 2019 , the Credit Agreement provided for a senior secured revolving credit facility with a maximum loan amount of $2.5 billion , a borrowing base of $1.6 billion , and aggregate lender commitments of $1.2 billion . The borrowing base is subject to regular, semi-annual redetermination, and considers the value of both the Company’s (a) proved oil and gas properties reflected in the Company’s most recent reserve report; and (b) commodity derivative contracts, each as determined by the Company’s lender group. The next scheduled borrowing base redetermination date is April 1, 2020 . The Credit Agreement is scheduled to mature on the earlier of September 28, 2023 , (the “Scheduled Maturity Date”), and August 16, 2022 , to the extent that, on or before such date, the Company’s outstanding 2022 Senior Notes are not repurchased, redeemed, or refinanced to have a maturity date at least 91 days after the Scheduled Maturity Date unless, on August 16, 2022 , both (i) the aggregate outstanding principal amount of the 2022 Senior Notes is not more than $100.0 million and (ii) after giving pro forma effect to the repayment in full at maturity of the 2022 Senior Notes then outstanding, the aggregate amount of unrestricted cash and certain types of unrestricted investments held by the Company and its Consolidated Restricted Subsidiaries plus the amount of unused availability under the Credit Agreement is at least $300.0 million . The Company must comply with certain financial and non-financial covenants under the terms of the Credit Agreement, including covenants limiting dividend payments and requiring the Company to maintain certain financial ratios, as defined by the Credit Agreement. The financial covenants under the Credit Agreement require that the Company’s (a) total funded debt, as defined in the Credit Agreement, to adjusted EBITDAX ratio for the most recently ended four consecutive fiscal quarters (excluding the first three quarters which used annualized adjusted EBITDAX), cannot be greater than 4.25 to 1.00 beginning with the quarter ending December 31, 2018, through and including the fiscal quarter ending December 31, 2019, and for each quarter ending thereafter, the ratio cannot be greater than 4.00 to 1.00; and (b) adjusted current ratio cannot be less than 1.0 to 1.0 as of the last day of any fiscal quarter. The Company was in compliance with all financial and non-financial covenants as of December 31, 2019 , and through the filing of this report. Interest and commitment fees associated with the credit facility are accrued based on a borrowing base utilization grid set forth in the Credit Agreement. 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. The borrowing base utilization grid as set forth in the Credit Agreement is as follows: Borrowing Base Utilization Percentage <25% ≥25% <50% ≥50% <75% ≥75% <90% ≥90% Eurodollar Loans (1) 1.500 % 1.750 % 2.000 % 2.250 % 2.500 % ABR Loans or Swingline Loans 0.500 % 0.750 % 1.000 % 1.250 % 1.500 % Commitment Fee Rate 0.375 % 0.375 % 0.500 % 0.500 % 0.500 % ____________________________________________ (1) The Company’s Credit Agreement specifies that in the event that LIBOR is no longer a widely used benchmark rate, or that it shall no longer be 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 borrower. 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 6, 2020 , December 31, 2019 , and December 31, 2018 : As of February 6, 2020 As of December 31, 2019 As of December 31, 2018 (in thousands) Revolving credit facility (1) $ 113,500 $ 122,500 $ — Letters of credit (2) — — 200 Available borrowing capacity 1,086,500 1,077,500 999,800 Total aggregate lender commitment amount $ 1,200,000 $ 1,200,000 $ 1,000,000 ____________________________________________ (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 $5.9 million and $6.4 million as of December 31, 2019 , and 2018 , respectively. These costs are being amortized over the term of the credit facility on a straight-line basis. (2) Letters of credit outstanding reduce the amount available under the credit facility on a dollar-for-dollar basis. The letter of credit outstanding as of December 31, 2018 , was released effective January 8, 2019. Senior Notes The Senior Notes, net of unamortized deferred financing costs line item on the accompanying balance sheets as of December 31, 2019 , and 2018 , consisted of the following: As of December 31, 2019 2018 Principal Amount Unamortized Deferred Financing Costs Principal Amount, Net of Unamortized Deferred Financing Costs Principal Amount Unamortized Deferred Financing Costs Principal Amount, Net of Unamortized Deferred Financing Costs (in thousands) 6.125% Senior Notes due 2022 $ 476,796 $ 2,920 $ 473,876 $ 476,796 $ 3,921 $ 472,875 5.0% Senior Notes due 2024 500,000 3,766 496,234 500,000 4,688 495,312 5.625% Senior Notes due 2025 500,000 4,903 495,097 500,000 5,808 494,192 6.75% Senior Notes due 2026 500,000 5,571 494,429 500,000 6,407 493,593 6.625% Senior Notes due 2027 500,000 6,601 493,399 500,000 7,533 492,467 Total $ 2,476,796 $ 23,761 $ 2,453,035 $ 2,476,796 $ 28,357 $ 2,448,439 The 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. There are no subsidiary guarantors of the Senior Notes. The Company is subject to certain covenants under the indentures governing the Senior Notes that limit the Company’s ability to incur additional indebtedness, issue preferred stock, and make restricted payments, including dividends. The Company was in compliance with all such covenants under its Senior Notes as of December 31, 2019 , and through the filing of this report. All Senior Notes are registered under the Securities Act. The Company may redeem some or all of its Senior 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 Notes. On July 16, 2018, the Company redeemed its 2021 Senior Notes which resulted in the payment of total cash consideration, including accrued interest, of $355.9 million . Additionally, during the third quarter of 2018, the Company used the proceeds from the issuance of its 2027 Senior Notes, as discussed below, and cash on hand to fund the cash tender offer and redemption of $395.0 million of its 2023 Senior Notes and $85.0 million of its 2022 Senior Notes. The Company paid total consideration, including accrued interest, of $497.8 million to complete these transactions. As a result of the redemption of the 2021 Senior Notes, and the cash tender offer and redemption of all of the 2023 Senior Notes and a portion of the 2022 Senior Notes, the Company recorded a combined loss on extinguishment of debt of $26.7 million for the year ended December 31, 2018 . This amount included combined premiums paid of $20.4 million and $6.3 million of accelerated unamortized deferred financing costs for the redemption. 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 the first quarter of 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 interest. During the third quarter of 2018, through the tender offer discussed above, the Company retired $85.0 million of its 2022 Senior Notes for total consideration, including accrued interest, of $89.5 million . 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. 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. As discussed above, the net proceeds were used to fund the tender offer and redemption of all of the Company’s 2023 Senior Notes and a portion of its 2022 Senior Notes. Senior 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 Senior Convertible 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 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 Senior Convertible Notes. Holders may convert their Senior Convertible Notes at their option at any time prior to January 1, 2021, only under the following circumstances: (1) during any calendar quarter (and only during such calendar quarter) commencing after the calendar quarter ending on September 30, 2016, if the last reported sale price of the Company’s common stock for at least 20 trading days (whether or not consecutive) during a period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day; (2) during the five business day period after any five consecutive trading day period (the “measurement period”) in which the trading price (as defined in the indenture) per $1,000 principal amount of Notes for each trading day of the measurement period was less than 98% of the product of the last reported sale price of the Company’s common stock and the conversion rate on each such trading day; or (3) upon the occurrence of specified corporate events. On or after January 1, 2021, until the maturity date, holders may convert their Senior Convertible Notes at any time. The Company may not redeem the Senior Convertible Notes prior to the maturity date. Upon conversion, the Senior Convertible Notes may be settled, at the Company’s election, in shares of the Company’s common stock, cash, or a combination of cash and common stock. 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 Senior Convertible Notes, which is equal to an initial conversion price of approximately $40.50 per share, subject to adjustment. The Company has initially elected a net-settlement method to satisfy its conversion obligation, which would result in the Company settling the principal amount in cash with any excess conversion in shares of the Company’s common stock. The Senior Convertible Notes were not convertible at the option of holders as of December 31, 2019 , or through the filing of this report. Notwithstanding the inability to convert, the if-converted value of the Senior Convertible Notes as of December 31, 2019 , did not exceed the principal amount. Upon the issuance of the 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 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 transaction costs of $5.9 million relating to the issuance of the Senior Convertible Notes, which were allocated between the debt and equity components in proportion to their determined fair value amounts. The debt discount and debt-related issuance costs are amortized to the principal value of the Senior Convertible Notes as interest expense through the maturity date of July 1, 2021 . Interest expense recognized on the Senior Convertible Notes related to the stated interest rate and amortization of the debt discount totaled $11.0 million , $10.5 million , and $9.9 million for the years ended December 31, 2019 , 2018 , and 2017, respectively. The Senior Convertible Notes, net of unamortized discount and deferred financing costs line on the accompanying balance sheets consisted of the following as of December 31, 2019 and 2018 : As of December 31, 2019 2018 (in thousands) Principal amount of Senior Convertible Notes $ 172,500 $ 172,500 Unamortized debt discount (13,861 ) (22,313 ) Unamortized deferred financing costs (1,376 ) (2,293 ) Senior Convertible Notes, net of unamortized discount and deferred financing costs $ 157,263 $ 147,894 As of both December 31, 2019 and 2018, 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 . There have been no changes to this amount since issuance. If the Company undergoes a fundamental change, as defined by the governing indenture, holders of the Senior 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 Senior Convertible Notes to be repurchased, plus accrued and unpaid interest. The indenture governing the Senior Convertible Notes contains customary events of default with respect to the Senior 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 Senior 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. The Company is subject to certain covenants under the indenture governing the Senior Convertible Notes and was in compliance with all covenants as of December 31, 2019 , and through the filing of this report. Capped Call Transactions In connection with the issuance of the 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 reduce the potential dilution upon conversion of the Senior Convertible Notes and/or partially offset any cash payments the Company is required to make in excess of the principal amount of converted Senior 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 Senior 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 could be dilution or 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. Capitalized Interest Capitalized interest costs for the Company for the years ended December 31, 2019 , 2018 , and 2017 , totaled $18.5 million , $20.6 million , and $12.6 million , respectively. Capitalized interest costs are included in total costs incurred. Please refer to Costs Incurred in Oil and Gas Producing Activities 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, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 6 – Commitments and Contingencies Commitments The Company has entered into various agreements, which include drilling rig and completion service contracts of $34.1 million , gathering, processing, transportation throughput, and delivery commitments of $218.5 million , office leases, including maintenance, of $28.3 million , fixed price contracts to purchase electricity of $53.2 million , and other miscellaneous contracts and leases of $15.5 million . The annual minimum payments for the next five years and total minimum payments thereafter are presented below: Years Ending December 31, Amount (in thousands) 2020 $ 102,550 2021 94,494 2022 73,826 2023 41,661 2024 12,349 Thereafter 24,697 Total $ 349,577 Drilling Rig and Completion Service Contracts. The Company has several drilling rig and completion service contracts in place to facilitate its drilling and completion plans. As of December 31, 2019 , the Company’s drilling rig and completion service contract commitments totaled $34.1 million , included in the table above. If all of these contracts were terminated as of December 31, 2019 , the Company would avoid a portion of the contractual service commitments; however, the Company would be required to pay $26.3 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 arrangement. As of December 31, 2019 , potential penalties under this completion service agreement, which expires on December 31, 2023, range from zero to a maximum of $13.4 million . 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, 2019 , the Company has commitments to deliver a minimum of 24 MMBbl of oil and 424 Bcf of gas through 2023 , and 18 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, 2019 , if the Company fails to deliver any product, as applicable, the aggregate undiscounted deficiency payments total approximately $218.5 million . This amount does not include deficiency payment estimates associated with approximately 16.5 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. 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. 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, 2019 , 2018 , and 2017 , was $5.5 million , $4.5 million , and $4.8 million , respectively. Electrical Power Purchase Contracts. During the second quarter of 2019, the Company entered into a fixed price contract for the purchase of electrical power that increased the purchase commitment under an existing agreement. As of December 31, 2019 , the Company had a commitment to purchase electrical power through 2027 with a total remaining obligation of $53.2 million . Delivery and Purchase Commitments. During the second quarter of 2019, the Company executed an amendment to its existing sand sourcing agreement that created 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 amended sand sourcing agreement expires on December 31, 2023. As of December 31, 2019 , potential penalties under this sand sourcing agreement range from zero to a maximum of $10.0 million . Drilling and Completion Commitments. The Company has an agreement in place that includes minimum drilling and completion requirements on certain leases. If these minimum requirements are not satisfied by March 31, 2020, the Company would be required to make a liquidated damage payment based on the difference between actual development progress and the minimum development requirements. As of December 31, 2019 , the Company did not expect to meet certain minimum development requirements. In the fourth quarter of 2019, the Company recognized one-time charges associated with expected payments to lessors related to drilling and completion obligations and early termination fees for drilling rigs totaling $18.2 million . These amounts are included in the other operating expense line item on the accompanying statements of operations. 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, 2019
Compensation Related Costs [Abstract]
Compensation Plans	Note 7 – Compensation Plans Equity Incentive Compensation Plan There are several components to the Company’s Equity Incentive Compensation Plan (“Equity Plan”) that are described in this section. Various types of equity awards have been granted by the Company in different periods. As of December 31, 2019 , approximately 4.4 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 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 performance criteria over a three -year performance period. PSUs generally vest on the third anniversary of the date of the grant or upon other triggering events as set forth in the Equity Plan. Employees who are retirement eligible at the time a PSU award was granted, vest in each portion of that award equally in six -month increments over a three -year period beginning at grant date. Retirement eligible employees must stay with the Company through the entire six -month vesting period to receive that increment of vesting and any non-vested portions of a PSU award will be forfeited when the employee leaves the Company. 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 -year performance period. By using a stochastic simulation, the Company can create multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences regarding the path the stock price may take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the GBM Model, is deemed an appropriate method by which to determine the fair value of the PSUs. Significant assumptions used in this simulation include the Company’s expected volatility, dividend yield, and risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with a three-year vesting period, as well as the volatilities and dividend yields for each of the Company’s peers. For PSUs granted in 2017, which the Company has determined to be equity awards, the settlement criteria include 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 depend entirely on market-based settlement criteria, the associated compensation expense is recognized on a straight-line basis within general and administrative expense and exploration expense over the vesting period of the awards. 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 measures, the award agreements for these grants also stipulate that if the Company’s absolute TSR is negative over the three -year performance period, the maximum number of shares of common stock that can be issued to settle outstanding PSUs is capped at one times the number of PSUs granted on the award date, regardless of the Company’s TSR and CRTCI performance relative to its peer group. The fair value of the PSUs granted in 2018 and 2019 was measured on the applicable grant dates using the GBM Model, with the assumption that the associated CRTCI performance condition will be met at the target amount at the end of the respective performance periods. Compensation expense for PSUs granted in 2018 and 2019 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 $10.9 million , $10.3 million , and $9.7 million for the years ended December 31, 2019 , 2018 , and 2017 , respectively. As of December 31, 2019 , there was $15.9 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, 2019 2018 2017 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 1,711,259 $ 20.68 1,533,491 $ 22.97 828,923 $ 43.25 Granted 793,125 $ 12.80 572,924 $ 24.45 977,731 $ 15.86 Vested (346,021 ) $ 26.32 (233,102 ) $ 44.25 (94,338 ) $ 85.85 Forfeited (135,778 ) $ 16.98 (162,054 ) $ 21.79 (178,825 ) $ 44.99 Non-vested at end of year 2,022,585 $ 16.87 1,711,259 $ 20.68 1,533,491 $ 22.97 ____________________________________________ (1) The number of awards assumes a multiplier of one . The final number of shares of common stock issued may vary depending on the three -year performance multiplier, which ranges from zero to two . The fair value of the PSUs granted in 2019 , 2018 , and 2017 was $10.2 million , $14.0 million , and $15.5 million , respectively. During the years ended December 31, 2019 , 2018, and 2017, PSUs that were granted in 2016, 2015, and 2014, 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, 2019 , 2018 , and 2017 was $9.1 million , $10.3 million , and $8.1 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 a three-year 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 -month increments over a three -year period beginning at grant date. Retirement eligible employees must stay with the Company through the entire six -month vesting period to receive that increment of vesting and any non-vested portions of an RSU award will be forfeited when the employee leaves the Company. 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, 2019 , 2018 , and 2017 , was $11.1 million , $10.8 million , and $10.3 million , respectively. As of December 31, 2019 , there was $16.9 million of total unrecognized compensation expense related to non-vested RSU awards, which is being amortized through 2022 . 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, 2019 2018 2017 RSUs Weighted- Average Grant-Date Fair Value RSUs Weighted- Average Grant-Date Fair Value RSUs Weighted- Average Grant-Date Fair Value Non-vested at beginning of year 1,243,163 $ 21.50 1,244,262 $ 20.25 604,116 $ 37.39 Granted 978,932 $ 12.36 583,552 $ 25.77 1,020,780 $ 16.64 Vested (466,535 ) $ 21.94 (407,529 ) $ 24.30 (246,025 ) $ 43.99 Forfeited (223,429 ) $ 18.16 (177,122 ) $ 17.26 (134,609 ) $ 26.38 Non-vested at end of year 1,532,131 $ 16.01 1,243,163 $ 21.50 1,244,262 $ 20.25 The fair value of RSUs granted to eligible employees in 2019 , 2018 , and 2017 was $12.1 million , $15.0 million , and $17.0 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, 2019 2018 2017 Shares of common stock issued to settle RSUs (1) 466,535 407,529 246,025 Less: shares of common stock withheld for income and payroll taxes (132,136 ) (115,784 ) (74,747 ) Net shares of common stock issued 334,399 291,745 171,278 ____________________________________________ (1) During the years ended December 31, 2019 , 2018 , and 2017 , 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, 2019 , 2018 , and 2017 was $10.2 million , $9.9 million , and $10.8 million , respectively. Director Shares In 2019 , 2018 , and 2017 , the Company issued 96,719 , 63,741 , and 71,573 shares, respectively, of its common stock to its non-employee directors under the Equity Plan. In 2017, the Company issued 8,794 RSUs to a non-employee director. For the years ended December 31, 2019 , 2018 , and 2017 , the Company recorded $1.2 million , $1.7 million , and $1.6 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. The RSUs issued to a non-employee director in 2017 fully vested on December 31, 2017, and will settle upon the earlier to occur of May 25, 2027, or the director resigning from the Board of Directors. 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 Internal Revenue Code (the “IRC”). The Company had approximately 1.3 million shares of its common stock available for issuance under the ESPP as of December 31, 2019 . There were 314,868 , 199,464 , and 186,665 shares issued under the ESPP in 2019 , 2018 , and 2017 , respectively. Total proceeds to the Company for the issuance of these shares were $3.2 million for each of the years ended December 31, 2019 , and 2018 , respectively, and $2.6 million for the year ended December 31, 2017 . 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, 2019 2018 2017 Risk free interest rate 2.3 % 1.8 % 0.9 % Dividend yield 0.7 % 0.4 % 0.5 % Volatility factor of the expected market price of the Company’s common stock 56.6 % 55.9 % 62.5 % Expected life (in years) 0.5 0.5 0.5 The Company expensed $1.1 million for each of the years ended December 31, 2019 , and 2018 , respectively, and $1.0 million for the year ended December 31, 2017 , 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 $5.1 million , $4.9 million , and $4.5 million for the years ended December 31, 2019 , 2018 , and 2017 , respectively.

Pension Benefits

Pension Benefits	12 Months Ended
	Dec. 31, 2019
Defined Benefit Plan [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 (the “Qualified Pension Plan”). The Company also has a supplemental non-contributory pension plan covering certain management employees (the “Nonqualified Pension Plan” and together with the Qualified Pension Plan, the “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, 2019 2018 (in thousands) Change in benefit obligation: Projected benefit obligation at beginning of year $ 66,086 $ 71,937 Service cost 5,582 6,730 Interest cost 2,791 2,622 Actuarial (gain) loss 2,035 (7,155 ) Benefits paid (5,651 ) (8,048 ) Projected benefit obligation at end of year 70,843 66,086 Change in plan assets: Fair value of plan assets at beginning of year 30,100 30,978 Actual return (loss) on plan assets 3,985 (964 ) Employer contribution 7,200 8,134 Benefits paid (5,651 ) (8,048 ) Fair value of plan assets at end of year 35,634 30,100 Funded status at end of year $ (35,209 ) $ (35,986 ) The Company’s underfunded status for the Pension Plans as of December 31, 2019 , and 2018 , was $35.2 million and $36.0 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, 2019 2018 (in thousands) Projected benefit obligation $ 70,843 $ 66,086 Accumulated benefit obligation $ 60,877 $ 52,368 Less: fair value of plan assets (35,634 ) (30,100 ) Underfunded accumulated benefit obligation $ 25,243 $ 22,268 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, 2019 , and 2018 , were as follows: As of December 31, 2019 2018 (in thousands) Unrecognized actuarial losses $ 14,406 $ 15,741 Unrecognized prior service costs 31 48 Accumulated other comprehensive loss $ 14,437 $ 15,789 The pension liability adjustments recognized in other comprehensive income (loss) during 2019 , 2018 , and 2017 , were as follows: For the Years Ended December 31, 2019 2018 2017 (in thousands) Net actuarial gain (loss) $ 377 $ 4,329 $ (2,995 ) Amortization of prior service cost 17 18 17 Amortization of net actuarial loss 958 1,327 1,297 Settlements — — 3,009 Total pension liability adjustment, pre-tax 1,352 5,674 1,328 Tax expense (291 ) (4,265 ) (561 ) Cumulative effect of accounting change (1) — 2,969 — Total pension liability adjustment, net $ 1,061 $ 4,378 $ 767 _________________________________________ (1) Please refer to Recently Issued Accounting Standards in Note 1 – Summary of Significant Accounting Policies and Statements of Stockholders’ Equity for additional information. Components of Net Periodic Benefit Cost for the Pension Plans For the Years Ended December 31, 2019 2018 2017 (in thousands) Components of net periodic benefit cost: Service cost $ 5,582 $ 6,730 $ 6,638 Interest cost 2,791 2,622 2,689 Expected return on plan assets that reduces periodic pension benefit cost (1,574 ) (1,862 ) (2,244 ) Amortization of prior service cost 17 18 17 Amortization of net actuarial loss 958 1,327 1,297 Settlements — — 3,009 Net periodic benefit cost $ 7,774 $ 8,835 $ 11,406 Pension Plan Assumptions The weighted-average assumptions used to measure the Company’s projected benefit obligation are as follows: As of December 31, 2019 2018 Projected benefit obligation: Discount rate 3.6% 4.4% Rate of compensation increase 4.5% 6.2% The weighted-average assumptions used to measure the Company’s net periodic benefit cost are as follows: For the Years Ended December 31, 2019 2018 2017 Net periodic benefit cost: Discount rate 4.4% 3.8% 4.2% Expected return on plan assets (1) 5.0% 5.5% 6.5% Rate of compensation increase 6.2% 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 2020 2019 2018 Equity securities 35.0 % 36.9 % 31.8 % Fixed income securities 40.0 % 38.1 % 41.3 % Other securities 25.0 % 25.0 % 26.9 % 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 5.0 percent , 5.5 percent , and 6.5 percent was used to calculate the Company’s net periodic pension cost under the Qualified Pension Plan for the years ended December 31, 2019 , 2018 , and 2017 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, 2019 , and 2018 , 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, 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 As of December 31, 2018 Equity securities: Domestic (2) 15.4 % $ 4,639 $ 3,197 $ 1,442 $ — International (3) 16.4 % 4,941 3,642 1,299 — Total equity securities 31.8 % 9,580 6,839 2,741 — Fixed income securities: Core fixed income (4) 34.4 % 10,342 10,342 — — Floating rate corporate loans (5) 6.9 % 2,078 2,078 — — Total fixed income securities 41.3 % 12,420 12,420 — — Other securities: Real estate (6) 6.0 % 1,820 — — 1,820 Collective investment trusts (7) 3.1 % 934 — 934 — Hedge fund (8) 17.8 % 5,346 — 1,659 3,687 Total other securities 26.9 % 8,100 — 2,593 5,507 Total investments 100.0 % $ 30,100 $ 19,259 $ 5,334 $ 5,507 ____________________________________________ (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 and 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, 2018 $ 5,209 Purchases — Realized gain on assets 191 Unrealized gain on assets 152 Disposition (45 ) Balance at December 31, 2018 $ 5,507 Purchases — Realized gain on assets 190 Unrealized gain on assets 51 Disposition — Balance at December 31, 2019 $ 5,748 Contributions The Company contributed $7.2 million , $8.1 million , and $7.0 million to the Pension Plans for the years ended December 31, 2019 , 2018 , and 2017 , respectively. The Company expects to make a $5.6 million contribution to the Pension Plans in 2020 . Benefit Payments The Pension Plans made actual benefit payments of $5.7 million , $8.0 million , and $10.8 million in the years ended December 31, 2019 , 2018 , and 2017 , respectively. Expected benefit payments over the next 10 years are as follows: Years Ending December 31, (in thousands) 2020 $ 7,609 2021 $ 3,914 2022 $ 4,022 2023 $ 6,308 2024 $ 4,939 2025 through 2029 $ 25,065

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2019
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. Potentially dilutive securities for this calculation consist primarily of non-vested RSUs, contingent PSUs, and shares into which the Senior Convertible Notes are convertible, which are measured using the treasury stock method. PSUs represent the right to receive, upon settlement of the PSUs after the completion of the three -year performance period, a number of shares of the Company’s common stock that may range from zero to two times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, which would be issuable at the end of the respective reporting period, assuming that date was the end of the contingency period applicable to such PSUs. For additional discussion on PSUs, please refer to Note 7 – Compensation Plans under the heading Performance Share Units . On August 12, 2016 , the Company issued $172.5 million in aggregate principal amount of Senior Convertible Notes due 2021 . Upon conversion, the Senior Convertible Notes may be settled, at the Company’s election, in shares of the Company’s common stock, cash, or a combination of cash and common stock. The Company has initially elected a net-settlement method to satisfy its conversion obligation, which would result in the Company settling the principal amount of the Senior Convertible Notes in cash and the excess conversion value in shares. However, the Company has not made an irrevocable election and thereby reserves the right to settle the Senior Convertible Notes in any manner allowed under the indenture as business circumstances warrant. 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 , 2018 , and 2017 , therefore, the Senior Convertible Notes had no dilutive impact. In connection with the offering of the 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. Please refer to Note 5 – Long-Term Debt for additional discussion. When the Company recognizes a net loss from continuing operations, as was the case for the years ended December 31, 2019 , and 2017 , 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, 2019 2018 2017 (in thousands) Anti-dilutive 684 — 264 The following table sets forth the calculations of basic and diluted net income (loss) per common share: For the Years Ended December 31, 2019 2018 2017 (in thousands, except per share data) Net income (loss) $ (187,001 ) $ 508,407 $ (160,843 ) Basic weighted-average common shares outstanding 112,544 111,912 111,428 Dilutive effect of non-vested RSUs and contingent PSUs — 1,590 — Diluted weighted-average common shares outstanding 112,544 113,502 111,428 Basic net income (loss) per common share $ (1.66 ) $ 4.54 $ (1.44 ) Diluted net income (loss) per common share $ (1.66 ) $ 4.48 $ (1.44 )

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2019
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 has entered into various 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, 2019 , 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 and gas production, and swap arrangements for 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 also 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. The Company also has basis swaps with fixed price differentials between 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. As of December 31, 2019 , the Company had commodity derivative contracts outstanding through the fourth quarter of 2022, as summarized in the tables below. Oil Swaps Contract Period NYMEX WTI Volumes Weighted-Average Contract Price (MBbl) (per Bbl) First quarter 2020 2,486 $ 59.65 Second quarter 2020 2,838 $ 58.81 Third quarter 2020 3,361 $ 56.43 Fourth quarter 2020 3,937 $ 56.94 2021 667 $ 56.00 Total 13,289 Oil Collars Contract Period NYMEX WTI Volumes Weighted-Average Floor Price Weighted-Average Ceiling Price (MBbl) (per Bbl) (per Bbl) First quarter 2020 2,267 $ 55.00 $ 63.91 Second quarter 2020 1,881 $ 55.00 $ 62.17 Third quarter 2020 1,252 $ 55.00 $ 62.90 Fourth quarter 2020 610 $ 55.00 $ 61.90 2021 329 $ 55.00 $ 56.70 Total 6,339 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) (MBbl) (per Bbl) (MBbl) (per Bbl) First quarter 2020 4,193 $ (0.68 ) — $ — Second quarter 2020 3,495 $ (0.68 ) 910 $ (8.06 ) Third quarter 2020 3,325 $ (0.74 ) 920 $ (8.01 ) Fourth quarter 2020 3,261 $ (0.73 ) 920 $ (8.01 ) 2021 5,954 $ 0.59 3,650 $ (7.86 ) 2022 — $ — 3,650 $ (7.78 ) Total 20,228 10,050 ____________________________________________ (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). 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 2020 9,123 $ 2.98 3,099 $ 1.93 Second quarter 2020 4,160 $ 2.20 3,196 $ 0.56 Third quarter 2020 4,493 $ 2.41 3,268 $ 1.03 Fourth quarter 2020 3,722 $ 2.36 3,419 $ 1.17 2021 — $ — 4,224 $ 1.51 Total (1) 21,498 17,206 ____________________________________________ (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, 2019 , WAHA volumes were comprised of 92 percent IF WAHA and eight percent GD WAHA . NGL Swaps OPIS Ethane Purity Mont Belvieu OPIS Propane Mont Belvieu Non-TET Contract Period Volumes Weighted-Average Contract Price Volumes Weighted-Average Contract Price (MBbl) (per Bbl) (MBbl) (per Bbl) First quarter 2020 447 $ 11.53 382 $ 22.64 Second quarter 2020 264 $ 11.13 382 $ 22.34 Third quarter 2020 — $ — 409 $ 22.33 Fourth quarter 2020 — $ — 466 $ 22.29 Total 711 1,639 Commodity Derivative Contracts Entered Into Subsequent to December 31, 2019 Subsequent to December 31, 2019 , the Company entered into the following commodity derivative contracts: • fixed price NYMEX WTI oil swap contracts for the fourth quarter of 2020 through January 2021 for a total of 0.6 MMBbl of oil production at a weighted-average contract price of $57.82 per Bbl; and • fixed price WTI Midland-NYMEX WTI oil basis swap contracts for the second quarter of 2020 through the fourth quarter of 2022 for a total of 16.3 MMBbl of oil production at a weighted-average contract price of $1.14 per Bbl. 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 derivative commodity contracts as hedging instruments. The fair value of the commodity derivative contracts at December 31, 2019 , and 2018 , was a net asset of $21.5 million and $158.3 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, 2019 As of December 31, 2018 (in thousands) Derivative assets: Current assets $ 55,184 $ 175,130 Noncurrent assets 20,624 58,499 Total derivative assets $ 75,808 $ 233,629 Derivative liabilities: Current liabilities $ 50,846 $ 62,853 Noncurrent liabilities 3,444 12,496 Total derivative liabilities $ 54,290 $ 75,349 Offsetting of Derivative Assets and Liabilities As of December 31, 2019 , and 2018 , 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, 2019 2018 2019 2018 (in thousands) Gross amounts presented in the accompanying balance sheets $ 75,808 $ 233,629 $ (54,290 ) $ (75,349 ) Amounts not offset in the accompanying balance sheets (35,075 ) (56,041 ) 35,075 56,041 Net amounts $ 40,733 $ 177,588 $ (19,215 ) $ (19,308 ) 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 derivatives designated as hedging instruments for the years ended December 31, 2019 , 2018 , and 2017 . 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 net derivative (gain) loss line item presented in the accompanying statements of operations: For the Years Ended December 31, 2019 2018 2017 (in thousands) Derivative settlement (gain) loss: Oil contracts $ 19,685 $ 68,860 $ 31,176 Gas contracts (23,008 ) 13,029 (87,857 ) NGL contracts (35,899 ) 53,914 35,447 Total derivative settlement (gain) loss $ (39,222 ) $ 135,803 $ (21,234 ) Net derivative (gain) loss: Oil contracts $ 172,055 $ (192,002 ) $ 71,502 Gas contracts (41,205 ) 35,411 (76,315 ) NGL contracts (33,311 ) (5,241 ) 31,227 Total net derivative (gain) loss $ 97,539 $ (161,832 ) $ 26,414 Credit Related Contingent Features As of December 31, 2019 , 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, 2019
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 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. 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. 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, 2018 : Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 233,629 $ — Liabilities: Derivatives (1) $ — $ 75,349 $ — ____________________________________________ (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. 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 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 Proved oil and gas properties . Proved oil and gas property costs are evaluated for impairment 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 to measure the fair value of proved properties through an application of discount rates and price forecasts representative of the current operating environment, as selected by the Company’s management. Unproved oil and gas properties . 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. 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. There were no proved or unproved oil and gas properties recorded at fair value on the accompanying balance sheets as of December 31, 2019 , or December 31, 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, 2019 2018 2017 (in millions) Impairment of proved properties $ — $ — $ 3.8 Abandonment and impairment of unproved properties 33.8 49.9 12.3 Impairment of oil and gas properties $ 33.8 $ 49.9 $ 16.1 Abandonment and impairment of unproved properties expense recorded during the years ended December 31, 2019 , 2018 , and 2017 primarily 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. Long-Term Debt The following table reflects the fair value of the Company’s unsecured 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, 2019 , or 2018 , 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 discussion. As of December 31, 2019 2018 Principal Amount Fair Value Principal Amount Fair Value (in thousands) 6.125% Senior Notes due 2022 $ 476,796 $ 481,564 $ 476,796 $ 452,336 5.0% Senior Notes due 2024 $ 500,000 $ 479,815 $ 500,000 $ 439,265 5.625% Senior Notes due 2025 $ 500,000 $ 475,835 $ 500,000 $ 436,460 6.75% Senior Notes due 2026 $ 500,000 $ 494,860 $ 500,000 $ 448,305 6.625% Senior Notes due 2027 $ 500,000 $ 493,750 $ 500,000 $ 442,500 1.50% Senior Convertible Notes due 2021 $ 172,500 $ 164,430 $ 172,500 $ 158,614 The carrying value of the Company’s credit facility approximates its fair value, as the applicable interest rates are floating, based on prevailing market rates.

Suspended Well Costs

Suspended Well Costs	12 Months Ended
	Dec. 31, 2019
Suspended Well Costs [Abstract]
Suspended Well Costs [Text Block]	Note 15 – Suspended Well Costs The following table reflects the net changes in capitalized exploratory well costs during 2019 , 2018 , and 2017 . 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, 2019 2018 2017 (in thousands) Beginning balance $ 11,197 $ 49,446 $ 19,846 Additions to capitalized exploratory well costs pending the determination of proved reserves 11,925 11,197 49,446 Divestitures — (109 ) — Reclassifications to wells, facilities, and equipment based on the determination of proved reserves (11,197 ) (49,337 ) (19,846 ) Capitalized exploratory well costs charged to expense — — — Ending balance $ 11,925 $ 11,197 $ 49,446 As of December 31, 2019 , there were no exploratory well costs that were capitalized for more than one year.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2019
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. A reconciliation of the Company’s total asset retirement obligation liability is as follows: As of December 31, 2019 2018 (in thousands) Beginning asset retirement obligations $ 94,194 $ 114,470 Liabilities incurred (1) 3,927 4,054 Liabilities settled (2) (4,105 ) (33,024 ) Accretion expense 4,016 4,438 Revision to estimated cash flows (11,186 ) 4,256 Ending asset retirement obligations (3) $ 86,846 $ 94,194 ____________________________________________ (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, 2019 , and 2018 , included $2.7 million and $2.3 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.

Accounts Receivable and Account

Accounts Receivable and Accounts Payable and Accrued Expenses	12 Months Ended
	Dec. 31, 2019
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, 2019 2018 (in thousands) Oil, gas, and NGL production revenue $ 146,308 $ 107,230 Amounts due from joint interest owners 22,681 31,497 State severance tax refunds 4,069 4,415 Derivative settlements 6,868 9,475 Other 4,806 14,919 Total accounts receivable $ 184,732 $ 167,536 Accounts payable and accrued expenses are comprised of the following accruals: As of December 31, 2019 2018 (in thousands) Drilling and lease operating cost accruals $ 96,925 $ 139,711 Trade accounts payable 52,094 56,047 Revenue and severance tax payable 109,847 94,806 Property taxes 24,535 18,694 Compensation 41,540 31,486 Derivative settlements 5,851 1,287 Interest 44,175 40,840 Other 27,041 20,328 Total accounts payable and accrued expenses $ 402,008 $ 403,199

Leases

Leases	12 Months Ended
	Dec. 31, 2019
Lessee Disclosure [Abstract]
Leases	Note 12 - Leases Effective January 1, 2019, the Company adopted Topic 842, which requires lessees to recognize operating and finance leases with terms greater than 12 months on the balance sheet. The Company adopted this standard using the modified retrospective method and elected to use the optional transition methodology whereby reporting periods prior to adoption continue to be presented in accordance with legacy accounting guidance. As of December 31, 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. • 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. 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 six years . The weighted-average lease term remaining for these leases is approximately three years . 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. Exercising an early termination option may also result in an early termination penalty depending on the terms of the underlying agreement. 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. 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. For the year ended December 31, 2019 , total costs related to operating leases, including short-term leases, and variable lease payments made for leases with initial lease terms greater than 12 months, were $442.9 million . 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. Components of the Company’s total lease cost, whether capitalized or expensed, for the year ended December 31, 2019 , were as follows: For the Year Ended December 31, 2019 Operating lease cost $ 35,570 Short-term lease cost (1) 301,373 Variable lease cost (2) 106,006 Total lease cost (3) $ 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 is significant as it 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. (3) Lease costs are either expensed on the accompanying statements of operations or capitalized on the accompanying balance sheets depending on the nature and use of the underlying ROU asset. Other information related to the Company’s leases for the year ended December 31, 2019 , was as follows: For the Year Ended December 31, 2019 (in thousands) Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 12,074 Investing cash flows from operating leases $ 24,129 Right-of-use assets obtained in exchange for new operating lease liabilities $ 25,360 Maturities for the Company’s operating lease liabilities included on the accompanying balance sheets as of December 31, 2019 , were as follows: As of December 31, 2019 (in thousands) 2020 $ 21,102 2021 12,600 2022 5,749 2023 3,602 2024 2,081 Thereafter 1,639 Total Lease payments $ 46,773 Less: Imputed interest (1) (4,447 ) Total $ 42,326 ____________________________________________ (1) The weighted-average discount rate used to determine the operating lease liability as of December 31, 2019 was 6.6 percent . Amounts recorded on the accompanying balance sheets for operating leases as of December 31, 2019 , were as follows: As of December 31, 2019 (in thousands) Other noncurrent assets $ 39,717 Other current liabilities $ 19,189 Other noncurrent liabilities $ 23,137 As of December 31, 2019 , and through the filing of this report, the Company has no material lease arrangements which are scheduled to commence in the future.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2019
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 consolidated financial statements, the Company evaluated events subsequent to the balance sheet date of December 31, 2019 , through the filing of this report. Additionally, certain prior period amounts have been reclassified to conform to current period presentation in the 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 depletion, depreciation, and amortization expense, impairment of proved 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 consists mainly of receivables 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 regions. The following major customers and entities under common control accounted for 10 percent or more of its total oil, gas, and NGL production revenue for at least one of the periods presented: For the Years Ended December 31, 2019 2018 2017 Major customer #1 (1) 18 % 18 % 6 % Major customer #2 (1) 14 % 5 % 1 % Major customer #3 (1) 13 % 7 % — % Major customer #4 (1) 9 % 10 % 10 % Group #1 of entities under common control (2) 13 % 18 % 17 % Group #2 of entities under common control (2) 11 % 12 % 8 % ____________________________________________ (1) These major customers are purchasers of a portion of the Company’s production from its Midland Basin assets. (2) In the aggregate, these groups of entities under common control represented purchasers of more than 10 percent 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 percent 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 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. The Company maintains investments in highly rated, highly liquid investment products with numerous banks that are party to its revolving credit facility.
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 a 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 group asset basis; however, the units-of-production method is based on estimated total proved oil and gas reserves. The computation of DD&A 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]	Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that associated carrying costs may not be recoverable. The Company uses an income valuation technique, which converts future cash flow to a single present value amount, to measure the fair value of proved properties through an application of discount rates and price forecasts, as selected by the Company’s management. The Company uses discount rates that are representative of current market conditions and considers estimates of future cash payments, reserve categories, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The discount rates typically range from 10 percent to 15 percent based on the reservoir specific weightings of future estimated proved and unproved cash flows. 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 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. 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 balance sheets consists of 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 a units-of-production basis. 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 prospect and the portion of such costs estimated to be nonproductive prior to lease expiration are 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 a 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 [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 wells 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 oil and gas properties. 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, 2019 , and 2018 .
Derivative 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 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 derivative commodity 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, 2019 , the Company had stock-based employee compensation plans that included restricted stock units (“RSUs”) and performance share units (“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 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. Please refer to Note 4 – Income Taxes for additional disclosure.
Earnings Per Share [Policy Text Block]	Earnings per Share The Company uses the treasury stock method to determine the potential dilutive effect of non-vested RSUs, contingent PSUs, and Senior Convertible Notes. 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 credit facility approximates its fair value as it bears interest at a floating rate that approximates a current market rate. The Company had a $122.5 million balance under its credit facility as of December 31, 2019 , compared with a zero balance as of December 31, 2018 . The Company’s Senior Notes and Senior Convertible Notes 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 . 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 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.
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 2019 or 2018 .
Recently Issued Accounting Standards [Policy Text Block]	Recently Issued Accounting Standards Effective January 1, 2017, the Company adopted, using various transition methods, Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). ASU 2016-09 is meant to simplify certain aspects of accounting for share-based arrangements, including income tax effects, accounting for forfeitures, and net share settlements. The Company adopted the various applicable amendments, which are summarized as follows: • On January 1, 2017, a $44.3 million cumulative-effect adjustment was made to retained earnings and a corresponding deferred tax asset was recorded for previously unrecognized excess tax benefits using a modified retrospective transition method. Effective January 1, 2017, excess tax benefits are presented in net cash provided by operating activities on the accompanying statements of cash flows. • On January 1, 2017, the Company elected to change its policy to account for forfeitures of share-based payment awards as they occur, rather than applying an estimated forfeiture rate. This change was made using a modified retrospective transition method and resulted in an increase in additional paid-in capital of $1.1 million , a decrease in deferred tax assets of $400,000 , and a net $700,000 cumulative effect decrease to retained earnings. • Under this new guidance, excess tax benefits and deficiencies from share-based payments impact the Company’s effective tax rate between periods. In February 2016, the FASB issued 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 guidance is to be applied using a modified retrospective method and is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. The Company adopted ASU 2016-13 on January 1, 2020. The adoption of ASU 2016-13 is not expected to result in a material impact to the Company’s consolidated financial statements or disclosures. In March 2017, the FASB issued ASU No. 2017-07, Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (“ASU 2017-07”). ASU 2017-07 requires presentation of service cost in the same line item(s) as other compensation costs arising from services rendered by employees during the period, and presentation of the remaining components of net benefit cost in a separate line item, outside operating items. In addition, only the service cost component of net benefit cost is eligible for capitalization. The Company adopted ASU 2017-07 on the effective date of January 1, 2018, with retrospective application of the service cost component and the other components of net benefit cost in the consolidated statements of operations, and prospective application for the capitalization of the service cost component of net benefit costs in assets. While the adoption of ASU 2017-07 resulted in the Company reclassifying certain amounts from operating expenses to non-operating expenses, ASU 2017-07 did not result in a material impact to the Company’s consolidated financial statements or disclosures. In February 2018, the FASB issued ASU No. 2018-02, Income Statement – Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (“ASU 2018-02”). ASU 2018-02 permits entities to reclassify tax effects stranded in accumulated other comprehensive income (loss) to retained earnings as a result of the 2017 Tax Act. The Company early adopted ASU 2018-02 effective January 1, 2018 using a retrospective method. As a result of adopting ASU 2018-02, the Company reclassified $3.0 million of tax effects stranded in accumulated other comprehensive loss to retained earnings as of January 1, 2018. The Company’s policy for releasing income tax effects within accumulated other comprehensive loss is an incremental, unit-of-account approach. 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. The adoption of ASU 2018-15 is not expected to have a material impact to the Company’s consolidated financial statements or 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. ASU 2019-12 is effective for fiscal years beginning after December 15, 2020, with early adoption permitted. The Company is evaluating the impact of ASU 2019-12 on its consolidated financial statements. 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, 2019 , 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. • 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.
Property, Plant and Equipment, Impairment [Policy Text Block]	Oil and Gas Properties Proved oil and gas properties . Proved oil and gas property costs are evaluated for impairment 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 to measure the fair value of proved properties through an application of discount rates and price forecasts representative of the current operating environment, as selected by the Company’s management. Unproved oil and gas properties . 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. 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. There were no proved or unproved oil and gas properties recorded at fair value on the accompanying balance sheets as of December 31, 2019 , or December 31, 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, 2019 2018 2017 (in millions) Impairment of proved properties $ — $ — $ 3.8 Abandonment and impairment of unproved properties 33.8 49.9 12.3 Impairment of oil and gas properties $ 33.8 $ 49.9 $ 16.1 Abandonment and impairment of unproved properties expense recorded during the years ended December 31, 2019 , 2018 , and 2017 primarily 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.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2019
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 its total oil, gas, and NGL production revenue for at least one of the periods presented: For the Years Ended December 31, 2019 2018 2017 Major customer #1 (1) 18 % 18 % 6 % Major customer #2 (1) 14 % 5 % 1 % Major customer #3 (1) 13 % 7 % — % Major customer #4 (1) 9 % 10 % 10 % Group #1 of entities under common control (2) 13 % 18 % 17 % Group #2 of entities under common control (2) 11 % 12 % 8 % ____________________________________________ (1) These major customers are purchasers of a portion of the Company’s production from its Midland Basin assets. (2) In the aggregate, these groups of entities under common control represented purchasers of more than 10 percent 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 percent 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, 2019
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue [Table Text Block]	The tables below present the oil, gas, and NGL production revenue by product type for each of the Company’s operating regions for the years ended December 31, 2019 , 2018 , and 2017 : 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 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. For the year ended December 31, 2017 Midland Basin South Texas Rocky Mountain Total (in thousands) Oil production revenue $ 419,732 $ 82,674 $ 151,844 $ 654,250 Gas production revenue 61,781 301,780 5,849 369,410 NGL production revenue 547 226,031 3,545 230,123 Total $ 482,060 $ 610,485 $ 161,238 $ 1,253,783 Relative percentage 38 % 49 % 13 % 100 % ____________________________________________ Note: Amounts may not calculate due to rounding.

Divestitures, Assets Held for_2

Divestitures, Assets Held for Sale, and Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2019
Divestitures, Assets Held for Sale, and Acquisitions Disclosure [Abstract]
Income (loss) before income taxes from sold assets [Table Text Block]	The following table presents loss before income taxes from the Divide County, North Dakota assets sold for the years ended December 31, 2019 , 2018 , and 2017 . The Divide County Divestiture was considered a disposal of a significant asset group. For the Years Ended December 31, 2019 2018 2017 (in thousands) Loss before income taxes (1) $ — $ (28,975 ) $ (468,786 ) ____________________________________________ (1) 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. During the year ended December 31, 2017 , the Company recorded a write-down of $523.6 million on these assets.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 2018 2017 (in thousands) Current portion of income tax expense (benefit) Federal $ (3,826 ) $ — $ 5,698 State 1,618 1,662 3,398 Deferred portion of income tax expense (benefit) (41,835 ) 141,708 (192,066 ) Income tax expense (benefit) $ (44,043 ) $ 143,370 $ (182,970 ) Effective tax rate 19.1 % 22.0 % 53.2 %
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, 2019 2018 (in thousands) Deferred tax liabilities Oil and gas properties $ 205,028 $ 218,094 Derivative assets 4,646 35,247 Other 12,361 4,812 Total deferred tax liabilities 222,035 258,153 Deferred tax assets Credit carryover 11,270 22,554 Pension 5,971 6,427 Federal and state tax net operating loss carryovers 4,172 4,217 Stock compensation 3,503 3,263 Other liabilities 10,803 1,497 Total deferred tax assets 35,719 37,958 Valuation allowance (3,070 ) (3,083 ) Net deferred tax assets 32,649 34,875 Total net deferred tax liabilities $ 189,386 $ 223,278 Current federal income tax refundable $ 3,885 $ 59 Current state income tax payable $ 1,404 $ 1,331
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 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, and the cumulative impact of other smaller permanent differences, and is reported as follows: For the Years Ended December 31, 2019 2018 2017 (in thousands) Federal statutory tax expense (benefit) $ (48,519 ) $ 136,873 $ (120,335 ) Increase (decrease) in tax resulting from: Federal tax reform changes - 2017 Tax Act — — (63,675 ) State tax expense (benefit) (net of federal benefit) 260 2,771 (3,286 ) Change in valuation allowance (13 ) 105 (2,727 ) Employee share-based compensation 3,346 2,508 8,190 Other 883 1,113 (1,137 ) Income tax expense (benefit) $ (44,043 ) $ 143,370 $ (182,970 )

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Borrowing Base Utilization Grid, Credit Facility [Table Text Block]	The borrowing base utilization grid as set forth in the Credit Agreement is as follows: Borrowing Base Utilization Percentage <25% ≥25% <50% ≥50% <75% ≥75% <90% ≥90% Eurodollar Loans (1) 1.500 % 1.750 % 2.000 % 2.250 % 2.500 % ABR Loans or Swingline Loans 0.500 % 0.750 % 1.000 % 1.250 % 1.500 % Commitment Fee Rate 0.375 % 0.375 % 0.500 % 0.500 % 0.500 % ____________________________________________ (1) The Company’s Credit Agreement specifies that in the event that LIBOR is no longer a widely used benchmark rate, or that it shall no longer be 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 borrower.
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 6, 2020 , December 31, 2019 , and December 31, 2018 : As of February 6, 2020 As of December 31, 2019 As of December 31, 2018 (in thousands) Revolving credit facility (1) $ 113,500 $ 122,500 $ — Letters of credit (2) — — 200 Available borrowing capacity 1,086,500 1,077,500 999,800 Total aggregate lender commitment amount $ 1,200,000 $ 1,200,000 $ 1,000,000 ____________________________________________ (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 $5.9 million and $6.4 million as of December 31, 2019 , and 2018 , respectively. These costs are being amortized over the term of the credit facility on a straight-line basis. (2) Letters of credit outstanding reduce the amount available under the credit facility on a dollar-for-dollar basis. The letter of credit outstanding as of December 31, 2018 , was released effective January 8, 2019.
Schedule of Senior Notes [Table Text Block]	The Senior Notes, net of unamortized deferred financing costs line item on the accompanying balance sheets as of December 31, 2019 , and 2018 , consisted of the following: As of December 31, 2019 2018 Principal Amount Unamortized Deferred Financing Costs Principal Amount, Net of Unamortized Deferred Financing Costs Principal Amount Unamortized Deferred Financing Costs Principal Amount, Net of Unamortized Deferred Financing Costs (in thousands) 6.125% Senior Notes due 2022 $ 476,796 $ 2,920 $ 473,876 $ 476,796 $ 3,921 $ 472,875 5.0% Senior Notes due 2024 500,000 3,766 496,234 500,000 4,688 495,312 5.625% Senior Notes due 2025 500,000 4,903 495,097 500,000 5,808 494,192 6.75% Senior Notes due 2026 500,000 5,571 494,429 500,000 6,407 493,593 6.625% Senior Notes due 2027 500,000 6,601 493,399 500,000 7,533 492,467 Total $ 2,476,796 $ 23,761 $ 2,453,035 $ 2,476,796 $ 28,357 $ 2,448,439
Schedule of Senior Convertible Notes [Table Text Block]	The Senior Convertible Notes, net of unamortized discount and deferred financing costs line on the accompanying balance sheets consisted of the following as of December 31, 2019 and 2018 : As of December 31, 2019 2018 (in thousands) Principal amount of Senior Convertible Notes $ 172,500 $ 172,500 Unamortized debt discount (13,861 ) (22,313 ) Unamortized deferred financing costs (1,376 ) (2,293 ) Senior Convertible Notes, net of unamortized discount and deferred financing costs $ 157,263 $ 147,894

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Schedule of contractual obligation, five years [Table Text Block]	The annual minimum payments for the next five years and total minimum payments thereafter are presented below: Years Ending December 31, Amount (in thousands) 2020 $ 102,550 2021 94,494 2022 73,826 2023 41,661 2024 12,349 Thereafter 24,697 Total $ 349,577

Compensation Plans (Tables)

Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2019
Compensation Related Costs [Abstract]
Schedule of performance share awards under equity incentive compensation plan [Table Text Block]	A summary of the status and activity of non-vested PSUs is presented in the following table: For the Years Ended December 31, 2019 2018 2017 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 1,711,259 $ 20.68 1,533,491 $ 22.97 828,923 $ 43.25 Granted 793,125 $ 12.80 572,924 $ 24.45 977,731 $ 15.86 Vested (346,021 ) $ 26.32 (233,102 ) $ 44.25 (94,338 ) $ 85.85 Forfeited (135,778 ) $ 16.98 (162,054 ) $ 21.79 (178,825 ) $ 44.99 Non-vested at end of year 2,022,585 $ 16.87 1,711,259 $ 20.68 1,533,491 $ 22.97 ____________________________________________ (1) The number of awards assumes a multiplier of one . The final number of shares of common stock issued may vary depending on the three -year performance multiplier, which ranges from zero to two .	[1]
Schedule of share-based compensation, restricted stock units award activity [Table Text Block]	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, 2019 2018 2017 RSUs Weighted- Average Grant-Date Fair Value RSUs Weighted- Average Grant-Date Fair Value RSUs Weighted- Average Grant-Date Fair Value Non-vested at beginning of year 1,243,163 $ 21.50 1,244,262 $ 20.25 604,116 $ 37.39 Granted 978,932 $ 12.36 583,552 $ 25.77 1,020,780 $ 16.64 Vested (466,535 ) $ 21.94 (407,529 ) $ 24.30 (246,025 ) $ 43.99 Forfeited (223,429 ) $ 18.16 (177,122 ) $ 17.26 (134,609 ) $ 26.38 Non-vested at end of year 1,532,131 $ 16.01 1,243,163 $ 21.50 1,244,262 $ 20.25
Schedule of shares settled, restricted stock units [Table Text Block]	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, 2019 2018 2017 Shares of common stock issued to settle RSUs (1) 466,535 407,529 246,025 Less: shares of common stock withheld for income and payroll taxes (132,136 ) (115,784 ) (74,747 ) Net shares of common stock issued 334,399 291,745 171,278 ____________________________________________ (1) During the years ended December 31, 2019 , 2018 , and 2017 , 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 [Table Text Block]	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, 2019 2018 2017 Risk free interest rate 2.3 % 1.8 % 0.9 % Dividend yield 0.7 % 0.4 % 0.5 % Volatility factor of the expected market price of the Company’s common stock 56.6 % 55.9 % 62.5 % Expected life (in years) 0.5 0.5 0.5
[1]	(1) The number of awards assumes a multiplier of one . The final number of shares of common stock issued may vary depending on the three -year performance multiplier, which ranges from zero to two .

Pension Benefits (Tables)

Pension Benefits (Tables)	12 Months Ended
	Dec. 31, 2019
Defined Benefit Plan [Abstract]
Schedule of net funded status [Table Text Block]	For the Years Ended December 31, 2019 2018 (in thousands) Change in benefit obligation: Projected benefit obligation at beginning of year $ 66,086 $ 71,937 Service cost 5,582 6,730 Interest cost 2,791 2,622 Actuarial (gain) loss 2,035 (7,155 ) Benefits paid (5,651 ) (8,048 ) Projected benefit obligation at end of year 70,843 66,086 Change in plan assets: Fair value of plan assets at beginning of year 30,100 30,978 Actual return (loss) on plan assets 3,985 (964 ) Employer contribution 7,200 8,134 Benefits paid (5,651 ) (8,048 ) Fair value of plan assets at end of year 35,634 30,100 Funded status at end of year $ (35,209 ) $ (35,986 )
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, 2019 2018 (in thousands) Projected benefit obligation $ 70,843 $ 66,086 Accumulated benefit obligation $ 60,877 $ 52,368 Less: fair value of plan assets (35,634 ) (30,100 ) Underfunded accumulated benefit obligation $ 25,243 $ 22,268
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, 2019 , and 2018 , were as follows: As of December 31, 2019 2018 (in thousands) Unrecognized actuarial losses $ 14,406 $ 15,741 Unrecognized prior service costs 31 48 Accumulated other comprehensive loss $ 14,437 $ 15,789
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 2019 , 2018 , and 2017 , were as follows: For the Years Ended December 31, 2019 2018 2017 (in thousands) Net actuarial gain (loss) $ 377 $ 4,329 $ (2,995 ) Amortization of prior service cost 17 18 17 Amortization of net actuarial loss 958 1,327 1,297 Settlements — — 3,009 Total pension liability adjustment, pre-tax 1,352 5,674 1,328 Tax expense (291 ) (4,265 ) (561 ) Cumulative effect of accounting change (1) — 2,969 — Total pension liability adjustment, net $ 1,061 $ 4,378 $ 767 _________________________________________ (1) Please refer to Recently Issued Accounting Standards in Note 1 – Summary of Significant Accounting Policies and Statements of Stockholders’ Equity for additional information.
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, 2019 2018 2017 (in thousands) Components of net periodic benefit cost: Service cost $ 5,582 $ 6,730 $ 6,638 Interest cost 2,791 2,622 2,689 Expected return on plan assets that reduces periodic pension benefit cost (1,574 ) (1,862 ) (2,244 ) Amortization of prior service cost 17 18 17 Amortization of net actuarial loss 958 1,327 1,297 Settlements — — 3,009 Net periodic benefit cost $ 7,774 $ 8,835 $ 11,406
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, 2019 2018 Projected benefit obligation: Discount rate 3.6% 4.4% Rate of compensation increase 4.5% 6.2% The weighted-average assumptions used to measure the Company’s net periodic benefit cost are as follows: For the Years Ended December 31, 2019 2018 2017 Net periodic benefit cost: Discount rate 4.4% 3.8% 4.2% Expected return on plan assets (1) 5.0% 5.5% 6.5% Rate of compensation increase 6.2% 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 2020 2019 2018 Equity securities 35.0 % 36.9 % 31.8 % Fixed income securities 40.0 % 38.1 % 41.3 % Other securities 25.0 % 25.0 % 26.9 % 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, 2019 , and 2018 , 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, 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 As of December 31, 2018 Equity securities: Domestic (2) 15.4 % $ 4,639 $ 3,197 $ 1,442 $ — International (3) 16.4 % 4,941 3,642 1,299 — Total equity securities 31.8 % 9,580 6,839 2,741 — Fixed income securities: Core fixed income (4) 34.4 % 10,342 10,342 — — Floating rate corporate loans (5) 6.9 % 2,078 2,078 — — Total fixed income securities 41.3 % 12,420 12,420 — — Other securities: Real estate (6) 6.0 % 1,820 — — 1,820 Collective investment trusts (7) 3.1 % 934 — 934 — Hedge fund (8) 17.8 % 5,346 — 1,659 3,687 Total other securities 26.9 % 8,100 — 2,593 5,507 Total investments 100.0 % $ 30,100 $ 19,259 $ 5,334 $ 5,507 ____________________________________________ (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 and 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, 2018 $ 5,209 Purchases — Realized gain on assets 191 Unrealized gain on assets 152 Disposition (45 ) Balance at December 31, 2018 $ 5,507 Purchases — Realized gain on assets 190 Unrealized gain on assets 51 Disposition — Balance at December 31, 2019 $ 5,748
Schedule of expected benefit payments [Table Text Block]	Expected benefit payments over the next 10 years are as follows: Years Ending December 31, (in thousands) 2020 $ 7,609 2021 $ 3,914 2022 $ 4,022 2023 $ 6,308 2024 $ 4,939 2025 through 2029 $ 25,065

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2019
Earnings Per Share [Abstract]
Schedule of weighted-average anti-dilutive securities excluded from computation of earnings per share	The following table details the weighted-average anti-dilutive securities for the years presented: For the Years Ended December 31, 2019 2018 2017 (in thousands) Anti-dilutive 684 — 264
Schedule of calculations of basic and diluted net 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, 2019 2018 2017 (in thousands, except per share data) Net income (loss) $ (187,001 ) $ 508,407 $ (160,843 ) Basic weighted-average common shares outstanding 112,544 111,912 111,428 Dilutive effect of non-vested RSUs and contingent PSUs — 1,590 — Diluted weighted-average common shares outstanding 112,544 113,502 111,428 Basic net income (loss) per common share $ (1.66 ) $ 4.54 $ (1.44 ) Diluted net income (loss) per common share $ (1.66 ) $ 4.48 $ (1.44 )

Derivative Financial Instrume_2

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2019
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Schedule of commodity derivative contracts outstanding	Oil Swaps Contract Period NYMEX WTI Volumes Weighted-Average Contract Price (MBbl) (per Bbl) First quarter 2020 2,486 $ 59.65 Second quarter 2020 2,838 $ 58.81 Third quarter 2020 3,361 $ 56.43 Fourth quarter 2020 3,937 $ 56.94 2021 667 $ 56.00 Total 13,289 Oil Collars Contract Period NYMEX WTI Volumes Weighted-Average Floor Price Weighted-Average Ceiling Price (MBbl) (per Bbl) (per Bbl) First quarter 2020 2,267 $ 55.00 $ 63.91 Second quarter 2020 1,881 $ 55.00 $ 62.17 Third quarter 2020 1,252 $ 55.00 $ 62.90 Fourth quarter 2020 610 $ 55.00 $ 61.90 2021 329 $ 55.00 $ 56.70 Total 6,339 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) (MBbl) (per Bbl) (MBbl) (per Bbl) First quarter 2020 4,193 $ (0.68 ) — $ — Second quarter 2020 3,495 $ (0.68 ) 910 $ (8.06 ) Third quarter 2020 3,325 $ (0.74 ) 920 $ (8.01 ) Fourth quarter 2020 3,261 $ (0.73 ) 920 $ (8.01 ) 2021 5,954 $ 0.59 3,650 $ (7.86 ) 2022 — $ — 3,650 $ (7.78 ) Total 20,228 10,050 ____________________________________________ (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). 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 2020 9,123 $ 2.98 3,099 $ 1.93 Second quarter 2020 4,160 $ 2.20 3,196 $ 0.56 Third quarter 2020 4,493 $ 2.41 3,268 $ 1.03 Fourth quarter 2020 3,722 $ 2.36 3,419 $ 1.17 2021 — $ — 4,224 $ 1.51 Total (1) 21,498 17,206 ____________________________________________ (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, 2019 , WAHA volumes were comprised of 92 percent IF WAHA and eight percent GD WAHA . NGL Swaps OPIS Ethane Purity Mont Belvieu OPIS Propane Mont Belvieu Non-TET Contract Period Volumes Weighted-Average Contract Price Volumes Weighted-Average Contract Price (MBbl) (per Bbl) (MBbl) (per Bbl) First quarter 2020 447 $ 11.53 382 $ 22.64 Second quarter 2020 264 $ 11.13 382 $ 22.34 Third quarter 2020 — $ — 409 $ 22.33 Fourth quarter 2020 — $ — 466 $ 22.29 Total 711 1,639
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, 2019 As of December 31, 2018 (in thousands) Derivative assets: Current assets $ 55,184 $ 175,130 Noncurrent assets 20,624 58,499 Total derivative assets $ 75,808 $ 233,629 Derivative liabilities: Current liabilities $ 50,846 $ 62,853 Noncurrent liabilities 3,444 12,496 Total derivative liabilities $ 54,290 $ 75,349
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, 2019 2018 2019 2018 (in thousands) Gross amounts presented in the accompanying balance sheets $ 75,808 $ 233,629 $ (54,290 ) $ (75,349 ) Amounts not offset in the accompanying balance sheets (35,075 ) (56,041 ) 35,075 56,041 Net amounts $ 40,733 $ 177,588 $ (19,215 ) $ (19,308 )
Schedule of gains and losses on derivative instruments in the statement of operations	The following table summarizes the commodity components of the net derivative (gain) loss line item presented in the accompanying statements of operations: For the Years Ended December 31, 2019 2018 2017 (in thousands) Derivative settlement (gain) loss: Oil contracts $ 19,685 $ 68,860 $ 31,176 Gas contracts (23,008 ) 13,029 (87,857 ) NGL contracts (35,899 ) 53,914 35,447 Total derivative settlement (gain) loss $ (39,222 ) $ 135,803 $ (21,234 ) Net derivative (gain) loss: Oil contracts $ 172,055 $ (192,002 ) $ 71,502 Gas contracts (41,205 ) 35,411 (76,315 ) NGL contracts (33,311 ) (5,241 ) 31,227 Total net derivative (gain) loss $ 97,539 $ (161,832 ) $ 26,414

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2019
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, 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. 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, 2018 : Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 233,629 $ — Liabilities: Derivatives (1) $ — $ 75,349 $ — ____________________________________________ (1) This represents a financial asset or liability that is measured at fair value on a recurring basis.	[1],[2]
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, 2019 2018 2017 (in millions) Impairment of proved properties $ — $ — $ 3.8 Abandonment and impairment of unproved properties 33.8 49.9 12.3 Impairment of oil and gas properties $ 33.8 $ 49.9 $ 16.1
Long Term Debt Fair Value [Table Text Block]	The following table reflects the fair value of the Company’s unsecured 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, 2019 , or 2018 , 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 discussion. As of December 31, 2019 2018 Principal Amount Fair Value Principal Amount Fair Value (in thousands) 6.125% Senior Notes due 2022 $ 476,796 $ 481,564 $ 476,796 $ 452,336 5.0% Senior Notes due 2024 $ 500,000 $ 479,815 $ 500,000 $ 439,265 5.625% Senior Notes due 2025 $ 500,000 $ 475,835 $ 500,000 $ 436,460 6.75% Senior Notes due 2026 $ 500,000 $ 494,860 $ 500,000 $ 448,305 6.625% Senior Notes due 2027 $ 500,000 $ 493,750 $ 500,000 $ 442,500 1.50% Senior Convertible Notes due 2021 $ 172,500 $ 164,430 $ 172,500 $ 158,614
[1]	(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.
[2]	(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.

Suspended Well Costs (Tables)

Suspended Well Costs (Tables)	12 Months Ended
	Dec. 31, 2019
Suspended Well Costs [Abstract]
Net changes in capitalized exploratory well costs [Table Text Block]	The following table reflects the net changes in capitalized exploratory well costs during 2019 , 2018 , and 2017 . 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, 2019 2018 2017 (in thousands) Beginning balance $ 11,197 $ 49,446 $ 19,846 Additions to capitalized exploratory well costs pending the determination of proved reserves 11,925 11,197 49,446 Divestitures — (109 ) — Reclassifications to wells, facilities, and equipment based on the determination of proved reserves (11,197 ) (49,337 ) (19,846 ) Capitalized exploratory well costs charged to expense — — — Ending balance $ 11,925 $ 11,197 $ 49,446

Reconciliation of Asset Retirem

Reconciliation of Asset Retirement Obligation Liability (Tables)	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation [Abstract]
Schedule of change in asset retirement obligation liability [Table Text Block]	A reconciliation of the Company’s total asset retirement obligation liability is as follows: As of December 31, 2019 2018 (in thousands) Beginning asset retirement obligations $ 94,194 $ 114,470 Liabilities incurred (1) 3,927 4,054 Liabilities settled (2) (4,105 ) (33,024 ) Accretion expense 4,016 4,438 Revision to estimated cash flows (11,186 ) 4,256 Ending asset retirement obligations (3) $ 86,846 $ 94,194 ____________________________________________ (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, 2019 , and 2018 , included $2.7 million and $2.3 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.

Accounts Receivable and Accou_2

Accounts Receivable and Accounts Payable and Accrued Expenses (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 2018 (in thousands) Oil, gas, and NGL production revenue $ 146,308 $ 107,230 Amounts due from joint interest owners 22,681 31,497 State severance tax refunds 4,069 4,415 Derivative settlements 6,868 9,475 Other 4,806 14,919 Total accounts receivable $ 184,732 $ 167,536
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, 2019 2018 (in thousands) Drilling and lease operating cost accruals $ 96,925 $ 139,711 Trade accounts payable 52,094 56,047 Revenue and severance tax payable 109,847 94,806 Property taxes 24,535 18,694 Compensation 41,540 31,486 Derivative settlements 5,851 1,287 Interest 44,175 40,840 Other 27,041 20,328 Total accounts payable and accrued expenses $ 402,008 $ 403,199

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2019
Lessee Disclosure [Abstract]
Components of total lease cost [Table Text Block]	<div style="font-family:Times New Roman;font-size:10pt;"><div style="line-height:120%;text-indent:48px;font-size:9pt;"><font style="font-family:Arial;font-size:9pt;">Components of the Company’s total lease cost, whether capitalized or expensed, for the year ended </font><font style="font-family:Arial;font-size:9pt;">December 31, 2019</font><font style="font-family:Arial;font-size:9pt;">, were as follows:</font></div><div style="line-height:120%;text-align:left;font-size:10pt;"><div style="padding-left:0px;text-indent:0px;line-height:normal;padding-top:10px;"><table cellpadding="0" cellspacing="0" style="font-family:Times New Roman;font-size:10pt;width:373px;border-collapse:collapse;text-align:left;"><tr><td colspan="4" rowspan="1"></td></tr><tr><td style="width:196px;" rowspan="1" colspan="1"></td><td style="width:9px;" rowspan="1" colspan="1"></td><td style="width:163px;" rowspan="1" colspan="1"></td><td style="width:4px;" rowspan="1" colspan="1"></td></tr><tr><td style="vertical-align:bottom;padding-left:2px;padding-top:2px;padding-bottom:2px;padding-right:2px;" rowspan="1" colspan="1"><div style="overflow:hidden;font-size:10pt;"><font style="font-family:inherit;font-size:10pt;"> </font></div></td><td colspan="3" style="vertical-align:bottom;border-bottom:1px solid #000000;padding-left:2px;padding-top:2px;padding-bottom:2px;padding-right:2px;" rowspan="1"><div style="text-align:center;font-size:9pt;"><font style="font-family:Arial;font-size:9pt;font-weight:bold;">For the Year Ended December 31, 2019</font></div></td></tr><tr><td style="vertical-align:bottom;padding-left:2px;padding-top:2px;padding-bottom:2px;padding-right:2px;" rowspan="1" colspan="1"><div style="overflow:hidden;height:18px;font-size:10pt;"><font style="font-family:inherit;font-size:10pt;"> </font></div></td><td colspan="3" style="vertical-align:bottom;padding-left:2px;padding-top:2px;padding-bottom:2px;padding-right:2px;" rowspan="1"><div style="overflow:hidden;height:18px;font-size:10pt;"><font style="font-family:inherit;font-size:10pt;"> </font></div></td></tr><tr><td style="vertical-align:bottom;background-color:#cceeff;padding-left:2px;padding-top:2px;padding-bottom:2px;padding-right:2px;" rowspan="1" colspan="1"><div style="text-align:left;font-size:9pt;"><font style="font-family:Arial;font-size:9pt;">Operating lease cost</font></div></td><td style="vertical-align:bottom;padding-left:2px;padding-top:2px;padding-bottom:2px;background-color:#cceeff;" rowspan="1" colspan="1"><div style="text-align:left;font-size:9pt;"><font style="font-family:Arial;font-size:9pt;">$</font></div></td><td style="vertical-align:bottom;background-color:#cceeff;padding-top:2px;padding-bottom:2px;" rowspan="1" colspan="1"><div style="text-align:right;font-size:9pt;"><font style="font-family:Arial;font-size:9pt;">35,570</font></div></td><td style="vertical-align:bottom;background-color:#cceeff;" rowspan="1" colspan="1"><div style="text-align:left;font-size:10pt;"><font style="font-family:inherit;font-size:10pt;"><br clear="none"/></font></div></td></tr><tr><td style="vertical-align:bottom;padding-left:2px;padding-top:2px;padding-bottom:2px;padding-right:2px;" rowspan="1" colspan="1"><div style="font-size:9pt;"><font style="font-family:Arial;font-size:9pt;">Short-term lease cost </font><font style="font-family:Arial;font-size:9pt;"><sup style="vertical-align:top;line-height:120%;font-size:6pt">(1)</sup></font></div></td><td colspan="2" style="vertical-align:bottom;padding-left:2px;padding-top:2px;padding-bottom:2px;" rowspan="1"><div style="text-align:right;font-size:9pt;"><font style="font-family:Arial;font-size:9pt;">301,373</font></div></td><td style="vertical-align:bottom;" rowspan="1" colspan="1"><div style="text-align:left;font-size:10pt;"><font style="font-family:inherit;font-size:10pt;"><br clear="none"/></font></div></td></tr><tr><td style="vertical-align:bottom;background-color:#cceeff;padding-left:2px;padding-top:2px;padding-bottom:2px;padding-right:2px;" rowspan="1" colspan="1"><div style="font-size:9pt;"><font style="font-family:Arial;font-size:9pt;">Variable lease cost </font><font style="font-family:Arial;font-size:9pt;"><sup style="vertical-align:top;line-height:120%;font-size:6pt">(2)</sup></font></div></td><td colspan="2" style="vertical-align:bottom;background-color:#cceeff;padding-left:2px;padding-top:2px;padding-bottom:2px;" rowspan="1"><div style="text-align:right;font-size:9pt;"><font style="font-family:Arial;font-size:9pt;">106,006</font></div></td><td style="vertical-align:bottom;background-color:#cceeff;" rowspan="1" colspan="1"><div style="text-align:left;font-size:10pt;"><font style="font-family:inherit;font-size:10pt;"><br clear="none"/></font></div></td></tr><tr><td style="vertical-align:bottom;padding-left:2px;padding-top:2px;padding-bottom:2px;padding-right:2px;" rowspan="1" colspan="1"><div style="text-align:left;font-size:9pt;"><font style="font-family:Arial;font-size:9pt;">Total lease cost </font><font style="font-family:Arial;font-size:9pt;"><sup style="vertical-align:top;line-height:120%;font-size:6pt">(3)</sup></font></div></td><td style="vertical-align:bottom;border-bottom:3px double #000000;padding-left:2px;padding-top:2px;padding-bottom:2px;border-top:1px solid #000000;" rowspan="1" colspan="1"><div style="text-align:left;font-size:9pt;"><font style="font-family:Arial;font-size:9pt;">$</font></div></td><td style="vertical-align:bottom;border-bottom:3px double #000000;padding-top:2px;padding-bottom:2px;border-top:1px solid #000000;" rowspan="1" colspan="1"><div style="text-align:right;font-size:9pt;"><font style="font-family:Arial;font-size:9pt;">442,949</font></div></td><td style="vertical-align:bottom;border-bottom:3px double #000000;border-top:1px solid #000000;" rowspan="1" colspan="1"><div style="text-align:left;font-size:10pt;"><font style="font-family:inherit;font-size:10pt;"><br clear="none"/></font></div></td></tr></table></div></div><div style="line-height:120%;text-align:left;font-size:6pt;"><font style="font-family:Arial;font-size:6pt;">____________________________________________</font></div><table cellpadding="0" cellspacing="0" style="padding-top:4px;font-family:Times New Roman; font-size:10pt;"><tr><td style="width:24px;" rowspan="1" colspan="1"></td><td rowspan="1" colspan="1"></td></tr><tr><td style="vertical-align:top" rowspan="1" colspan="1"><div style="line-height:120%;font-size:9pt;padding-left:0px;"><font style="font-family:Arial;font-size:9pt;"><sup style="vertical-align:top;line-height:120%;font-size:6pt">(1)</sup> </font></div></td><td style="vertical-align:top;" rowspan="1" colspan="1"><div style="line-height:120%;text-align:left;font-size:9pt;"><font style="font-family:Arial;font-size:9pt;">Costs associated with short-term lease agreements relate primarily to operational activities where underlying lease terms are less than one year. This amount is significant as it 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.</font></div></td></tr></table><table cellpadding="0" cellspacing="0" style="font-family:Times New Roman; font-size:10pt;"><tr><td style="width:24px;" rowspan="1" colspan="1"></td><td rowspan="1" colspan="1"></td></tr><tr><td style="vertical-align:top" rowspan="1" colspan="1"><div style="line-height:120%;font-size:9pt;padding-left:0px;"><font style="font-family:Arial;font-size:9pt;"><sup style="vertical-align:top;line-height:120%;font-size:6pt">(2)</sup> </font></div></td><td style="vertical-align:top;" rowspan="1" colspan="1"><div style="line-height:120%;text-align:left;font-size:9pt;"><font style="font-family:Arial;font-size:9pt;">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.</font></div></td></tr></table><table cellpadding="0" cellspacing="0" style="padding-bottom:16px;font-family:Times New Roman; font-size:10pt;"><tr><td style="width:24px;" rowspan="1" colspan="1"></td><td rowspan="1" colspan="1"></td></tr><tr><td style="vertical-align:top" rowspan="1" colspan="1"><div style="line-height:120%;font-size:9pt;padding-left:0px;"><font style="font-family:Arial;font-size:9pt;"><sup style="vertical-align:top;line-height:120%;font-size:6pt">(3)</sup> </font></div></td><td style="vertical-align:top;" rowspan="1" colspan="1"><div style="line-height:120%;text-align:left;font-size:9pt;"><font style="font-family:Arial;font-size:9pt;">Lease costs are either expensed on the accompanying statements of operations or capitalized on the accompanying balance sheets depending on the nature and use of the underlying ROU asset.</font></div></td></tr></table><div style="line-height:120%;text-align:left;text-indent:48px;font-size:9pt;"><font style="font-family:Arial;font-size:9pt;">Other information related to the Company’s leases for the year</font><font style="font-family:Arial;font-size:9pt;"> ended</font><font style="font-family:Arial;font-size:9pt;"> </font><font style="font-family:Arial;font-size:9pt;">December 31, 2019</font><font style="font-family:Arial;font-size:9pt;">, was as follows:</font></div><div style="line-height:120%;padding-bottom:16px;text-align:left;font-size:10pt;"><div style="padding-left:0px;text-indent:0px;line-height:normal;padding-top:10px;"><table cellpadding="0" cellspacing="0" style="font-family:Times New Roman;font-size:10pt;width:620px;border-collapse:collapse;text-align:left;"><tr><td colspan="4" rowspan="1"></td></tr><tr><td style="width:442px;" rowspan="1" colspan="1"></td><td style="width:9px;" rowspan="1" colspan="1"></td><td style="width:163px;" rowspan="1" colspan="1"></td><td style="width:4px;" rowspan="1" colspan="1"></td></tr><tr><td style="vertical-align:bottom;padding-left:2px;padding-top:2px;padding-bottom:2px;padding-right:2px;" rowspan="1" colspan="1"><div style="overflow:hidden;font-size:10pt;"><font style="font-family:inherit;font-size:10pt;"> </font></div></td><td colspan="3" style="vertical-align:bottom;border-bottom:1px solid #000000;padding-left:2px;padding-top:2px;padding-bottom:2px;padding-right:2px;" rowspan="1"><div style="text-align:center;font-size:9pt;"><font style="font-family:Arial;font-size:9pt;font-weight:bold;">For the Year Ended December 31, 2019</font></div></td></tr><tr><td style="vertical-align:bottom;padding-left:2px;padding-top:2px;padding-bottom:2px;padding-right:2px;" rowspan="1" colspan="1"><div style="overflow:hidden;font-size:10pt;"><font style="font-family:inherit;font-size:10pt;"> </font></div></td><td colspan="3" style="vertical-align:top;padding-left:2px;padding-top:2px;padding-bottom:2px;padding-right:2px;" rowspan="1"><div style="text-align:center;font-size:9pt;"><font style="font-family:Arial;font-size:9pt;font-weight:bold;">(in thousands)</font></div></td></tr><tr><td style="vertical-align:bottom;background-color:#cceeff;padding-left:2px;padding-top:2px;padding-bottom:2px;padding-right:2px;" rowspan="1" colspan="1"><div style="text-align:left;font-size:9pt;"><font style="font-family:Arial;font-size:9pt;">Cash paid for amounts included in the measurement of lease liabilities:</font></div></td><td colspan="3" style="vertical-align:bottom;background-color:#cceeff;padding-left:2px;padding-top:2px;padding-bottom:2px;padding-right:2px;" rowspan="1"><div style="overflow:hidden;font-size:10pt;"><font style="font-family:inherit;font-size:10pt;"> </font></div></td></tr><tr><td style="vertical-align:bottom;padding-left:20px;padding-top:2px;padding-bottom:2px;padding-right:2px;" rowspan="1" colspan="1"><div style="text-align:left;font-size:9pt;"><font style="font-family:Arial;font-size:9pt;">Operating cash flows from operating leases</font></div></td><td style="vertical-align:bottom;padding-left:2px;padding-top:2px;padding-bottom:2px;" rowspan="1" colspan="1"><div style="text-align:left;font-size:9pt;"><font style="font-family:Arial;font-size:9pt;">$</font></div></td><td style="vertical-align:bottom;padding-top:2px;padding-bottom:2px;" rowspan="1" colspan="1"><div style="text-align:right;font-size:9pt;"><font style="font-family:Arial;font-size:9pt;">12,074</font></div></td><td style="vertical-align:bottom;" rowspan="1" colspan="1"><div style="text-align:left;font-size:10pt;"><font style="font-family:inherit;font-size:10pt;"><br clear="none"/></font></div></td></tr><tr><td style="vertical-align:bottom;background-color:#cceeff;padding-left:20px;padding-top:2px;padding-bottom:2px;padding-right:2px;" rowspan="1" colspan="1"><div style="text-align:left;font-size:9pt;"><font style="font-family:Arial;font-size:9pt;">Investing cash flows from operating leases</font></div></td><td style="vertical-align:bottom;padding-left:2px;padding-top:2px;padding-bottom:2px;background-color:#cceeff;" rowspan="1" colspan="1"><div style="text-align:left;font-size:9pt;"><font style="font-family:Arial;font-size:9pt;">$</font></div></td><td style="vertical-align:bottom;background-color:#cceeff;padding-top:2px;padding-bottom:2px;" rowspan="1" colspan="1"><div style="text-align:right;font-size:9pt;"><font style="font-family:Arial;font-size:9pt;">24,129</font></div></td><td style="vertical-align:bottom;background-color:#cceeff;" rowspan="1" colspan="1"><div style="text-align:left;font-size:10pt;"><font style="font-family:inherit;font-size:10pt;"><br clear="none"/></font></div></td></tr><tr><td style="vertical-align:bottom;padding-left:2px;padding-top:2px;padding-bottom:2px;padding-right:2px;" rowspan="1" colspan="1"><div style="text-align:left;font-size:9pt;"><font style="font-family:Arial;font-size:9pt;">Right-of-use assets obtained in exchange for new operating lease liabilities</font></div></td><td style="vertical-align:bottom;padding-left:2px;padding-top:2px;padding-bottom:2px;" rowspan="1" colspan="1"><div style="text-align:left;font-size:9pt;"><font style="font-family:Arial;font-size:9pt;">$</font></div></td><td style="vertical-align:bottom;padding-top:2px;padding-bottom:2px;" rowspan="1" colspan="1"><div style="text-align:right;font-size:9pt;"><font style="font-family:Arial;font-size:9pt;">25,360</font></div></td><td style="vertical-align:bottom;" rowspan="1" colspan="1"><div style="text-align:left;font-size:10pt;"><font style="font-family:inherit;font-size:10pt;"><br clear="none"/></font></div></td></tr></table></div></div></div>
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, 2019 , were as follows: As of December 31, 2019 (in thousands) 2020 $ 21,102 2021 12,600 2022 5,749 2023 3,602 2024 2,081 Thereafter 1,639 Total Lease payments $ 46,773 Less: Imputed interest (1) (4,447 ) Total $ 42,326 ____________________________________________ (1) The weighted-average discount rate used to determine the operating lease liability as of December 31, 2019 was 6.6 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, 2019 , were as follows: As of December 31, 2019 (in thousands) Other noncurrent assets $ 39,717 Other current liabilities $ 19,189 Other noncurrent liabilities $ 23,137

Summary of Significant Accoun_4

Summary of Significant Accounting Policies Other (Details)		Dec. 31, 2019USD ($)	Dec. 31, 2019USD ($)		Dec. 31, 2018USD ($)		Dec. 31, 2017
Concentration of Credit Risk and Major Customers [Abstract]
Entity-Wide Revenue, Major Customer, Percentage			100.00%	[1]	100.00%	[2]	100.00%	[3]
Number of individual entities within groups of entities under common ownership that represent more than 10 percent of total production revenue			0
Revolving Credit Facility [Member] | Line of Credit [Member]
Basis of Presentation and Significant Accounting Policies [Line Items]
Revolving credit facility		$ 122,500,000	$ 122,500,000		$ 0
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
Customer Concentration Risk [Member] | Oil, gas, and NGLS revenue [Member] | Major customer one [Member]
Concentration of Credit Risk and Major Customers [Abstract]
Entity-Wide Revenue, Major Customer, Percentage	[4]		18.00%		18.00%		6.00%
Customer Concentration Risk [Member] | Oil, gas, and NGLS revenue [Member] | Major customer two [Member]
Concentration of Credit Risk and Major Customers [Abstract]
Entity-Wide Revenue, Major Customer, Percentage	[4]		14.00%		5.00%		1.00%
Customer Concentration Risk [Member] | Oil, gas, and NGLS revenue [Member] | Major customer three [Member]
Concentration of Credit Risk and Major Customers [Abstract]
Entity-Wide Revenue, Major Customer, Percentage	[4]		13.00%		7.00%		0.00%
Customer Concentration Risk [Member] | Oil, gas, and NGLS revenue [Member] | Major customer four [Member]
Concentration of Credit Risk and Major Customers [Abstract]
Entity-Wide Revenue, Major Customer, Percentage	[4]		9.00%		10.00%		10.00%
Customer Concentration Risk [Member] | Oil, gas, and NGLS 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]		13.00%		18.00%		17.00%
Customer Concentration Risk [Member] | Oil, gas, and NGLS revenue [Member] | Group two of entities under common control [Member]
Concentration of Credit Risk and Major Customers [Abstract]
Entity-Wide Revenue, Major Customer, Percentage	[5]		11.00%		12.00%		8.00%
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] | Oil and Gas Properties [Member]
Basis of Presentation and Significant Accounting Policies [Line Items]
Fair Value Assumptions, Measurement Input		0.10	0.10
Minimum [Member] | Measurement Input, Risk Free Interest Rate [Member] | Asset Retirement Obligation Costs [Member]
Basis of Presentation and Significant Accounting Policies [Line Items]
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] | Oil and Gas Properties [Member]
Basis of Presentation and Significant Accounting Policies [Line Items]
Fair Value Assumptions, Measurement Input		0.15	0.15
Maximum [Member] | Measurement Input, Risk Free Interest Rate [Member] | Asset Retirement Obligation Costs [Member]
Basis of Presentation and Significant Accounting Policies [Line Items]
Fair Value Assumptions, Measurement Input		0.12	0.12
[1]	Note: Amounts may not calculate due to rounding.
[2]	Note: Amounts may not calculate due to rounding.
[3]	Note: Amounts may not calculate due to rounding.
[4]	(1) These major customers are purchasers of a portion of the Company’s production from its Midland Basin assets.
[5]	(2) In the aggregate, these groups of entities under common control represented purchasers of more than 10 percent 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 percent of the Company’s total oil, gas, and NGL production revenue.

Summary of Significant Accoun_5

Summary of Significant Accounting Policies ASU Adjustment (Details) - USD ($)		Jan. 01, 2019	Dec. 31, 2019	Dec. 31, 2018	Jan. 01, 2018		Dec. 31, 2017	Jan. 01, 2017
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Retained Earnings (Accumulated Deficit)			$ 967,587,000	$ 1,165,842,000
Deferred Tax Assets, Net of Valuation Allowance			32,649,000	$ 34,875,000
Right-of-use assets obtained in exchange for new operating lease liabilities			25,360,000
Cumulative effect of accounting change	[1]				$ 0			$ 44,732,000
ASU 2016-09 Cumulative Effect Adjustment for Timing of Recognition of Excess Tax Benefits [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Retained Earnings (Accumulated Deficit)								44,300,000
ASU 2016-09 Cumulative Effect of Actual Forfeiture Rate [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Retained Earnings (Accumulated Deficit)								(700,000)
Additional Paid in Capital								1,100,000
Deferred Tax Assets, Net of Valuation Allowance								$ (400,000)
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		$ 50,000,000
Accounting Standards Update 2018-02 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative effect of accounting change			$ 0		$ 2,969,000	[2]	$ 0
[1]	(1) Please refer to Recently Issued Accounting Standards in Note 1 – Summary of Significant Accounting Policies for additional information.
[2]	(1) Please refer to Recently Issued Accounting Standards in Note 1 – Summary of Significant Accounting Policies and Statements of Stockholders’ Equity for additional information.

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, 2019		Dec. 31, 2018		Dec. 31, 2017
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	$ 1,585,750	[1]	$ 1,636,357	[2]	$ 1,253,783	[3]
Concentration Risk, Percentage	100.00%	[1]	100.00%	[2]	100.00%	[3]
Revenue, Remaining Performance Obligation, Amount	$ 0
Midland Basin [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	1,195,736	[1]	$ 1,064,607	[2]	$ 482,060	[3]
South Texas [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	$ 390,014	[1]	514,514	[2]	610,485	[3]
Rocky Mountain [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax			$ 57,236	[2]	$ 161,238	[3]
Revenue Benchmark [Member] | Geographic Concentration Risk [Member] | Midland Basin [Member]
Segment Reporting Information [Line Items]
Concentration Risk, Percentage	75.00%	[1]	65.00%	[2]	38.00%	[3]
Revenue Benchmark [Member] | Geographic Concentration Risk [Member] | South Texas [Member]
Segment Reporting Information [Line Items]
Concentration Risk, Percentage	25.00%	[1]	32.00%	[2]	49.00%	[3]
Revenue Benchmark [Member] | Geographic Concentration Risk [Member] | Rocky Mountain [Member]
Segment Reporting Information [Line Items]
Concentration Risk, Percentage			3.00%	[2]	13.00%	[3]
Oil production revenue [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	$ 1,183,212		$ 1,065,676		$ 654,250
Oil production revenue [Member] | Midland Basin [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	1,119,786		938,004		419,732
Oil production revenue [Member] | South Texas [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	63,426		72,821		82,674
Oil production revenue [Member] | Rocky Mountain [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax			54,851		151,844
Gas production revenue [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	262,529		354,450		369,410
Gas production revenue [Member] | Midland Basin [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	75,827		125,603		61,781
Gas production revenue [Member] | South Texas [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	186,702		227,252		301,780
Gas production revenue [Member] | Rocky Mountain [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax			1,595		5,849
NGL production revenue [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	140,009		216,231		230,123
NGL production revenue [Member] | Midland Basin [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	123		1,000		547
NGL production revenue [Member] | South Texas [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	$ 139,886		214,441		226,031
NGL production revenue [Member] | Rocky Mountain [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax			$ 790		$ 3,545
[1]	Note: Amounts may not calculate due to rounding.
[2]	Note: Amounts may not calculate due to rounding.
[3]	Note: Amounts may not calculate due to rounding.

Revenue from Contracts with C_4

Revenue from Contracts with Customers Accounts Receivable from Customers (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Accounts Receivable
Accounts receivable	$ 184,732	$ 167,536
Oil, gas, and NGL production revenue [Member]
Accounts Receivable
Accounts receivable	$ 146,308	$ 107,230
Minimum [Member]
Accounts Receivable
Revenue receipt, days after sale	30
Maximum [Member]
Accounts Receivable
Revenue receipt, days after sale	90

Divestitures and Assets Held fo

Divestitures and Assets Held for Sale (Details) $ in Thousands		Mar. 26, 2018a	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net proceeds from the sale of oil and gas properties			$ 13,059	$ 748,509	$ 776,719
Net gain (loss) on divestiture activity			862	426,917	(131,028)
Disposal group, disposed of by sale, not discontinued operations [Member] | 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 proceeds from the sale of oil and gas properties				492,200
Net gain (loss) on divestiture activity				410,600
Disposal group, disposed of by sale, not discontinued operations [Member] | 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 proceeds from the sale of oil and gas properties				252,200
Net gain (loss) on divestiture activity				15,400
Disposal group, disposed of by sale, not discontinued operations [Member] | Divide County Divestiture 2018 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Income (loss) before income taxes			$ 0	$ (28,975)	(468,786)	[1]
Write-down on disposal group					523,600
Disposal group, disposed of by sale, not discontinued operations [Member] | Non-Operated Eagle Ford Divestiture 2017 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net proceeds from the sale of oil and gas properties					744,100
Net gain (loss) on divestiture activity					396,800
Income (loss) before income taxes	[1]				24,300
Disposal group, disposed of by sale, not discontinued operations [Member] | Rocky Mountain and Permian Divestitures [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net proceeds from the sale of oil and gas properties					$ 36,200
[1]	(1) 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. During the year ended December 31, 2017 , the Company recorded a write-down of $523.6 million on these assets.

Asset Acquisitions (Details)

Asset Acquisitions (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)a	Dec. 31, 2017USD ($)a
Asset Acquisitions [Line Items]
Net acres acquired | a		1,030
Payments to acquire oil and gas property and equipment | $	$ 2,581	$ 33,255	$ 89,896
Howard and Martin Counties Acquisitions 2017 [Member]
Asset Acquisitions [Line Items]
Net acres acquired | a			3,600
Payments to acquire oil and gas property and equipment | $			$ 76,500

Divestitures, Assets Held for_3

Divestitures, Assets Held for Sale, and Acquisitions Nonmonetary Transactions (Details)	12 Months Ended
	Dec. 31, 2019USD ($)a	Dec. 31, 2018USD ($)a	Dec. 31, 2017USD ($)a
Nonmonetary Transaction [Line Items]
Net acres exchanged	2,200	2,650
Non-monetary trade, acreage acquired			8,125
Non-monetary Trade, acreage divested			7,580
Carrying value of properties exchanged | $	$ 73,442,000	$ 95,121,000	$ 293,963,000
Basis of accounting for assets exchanged	carryover	carryover	carryover
Gain (loss) recognized on trade | $	$ 0	$ 0	$ 0

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Components of the provision for income taxes
Federal	$ (3,826)	$ 0	$ 5,698
State	1,618	1,662	3,398
Deferred portion of income tax expense (benefit)	(41,835)	141,708	(192,066)
Income tax expense (benefit)	$ (44,043)	$ 143,370	$ (182,970)
Effective tax rate (as a percent)	19.10%	22.00%	53.20%
Deferred income taxes [Abstract]
Deferred tax liabilities, oil and gas properties	$ 205,028	$ 218,094
Deferred tax liabilities, derivatives assets	4,646	35,247
Deferred tax liabilities, other	12,361	4,812
Total deferred tax liabilities	222,035	258,153
Deferred tax assets, credit carryover	11,270	22,554
Deferred tax assets, pension	5,971	6,427
Deferred tax assets, federal and state tax net operating loss carryovers	4,172	4,217
Deferred tax assets, stock compensation	3,503	3,263
Deferred tax assets, other liabilities	10,803	1,497
Total deferred tax assets	35,719	37,958
Deferred tax assets, valuation allowance	(3,070)	(3,083)
Net deferred tax assets	32,649	34,875
Total net deferred tax liabilities	189,386	223,278
State and local jurisdiction [Member]
Deferred income taxes [Abstract]
Current state income tax payable	1,404	1,331
Net operating loss carryforwards	77,800
Internal Revenue Service (IRS) [Member] | Domestic tax authority [Member]
Deferred income taxes [Abstract]
Current federal income tax refundable	3,885	$ 59
Net operating loss carryforwards	3,300
Internal Revenue Service (IRS) [Member] | Research and development tax credit carryforward [Member] | Domestic tax authority [Member]
Deferred income taxes [Abstract]
Tax credit carryforwards	7,400
Internal Revenue Service (IRS) [Member] | Alternative minimum tax credit carryforward [Member] | Domestic tax authority [Member]
Deferred income taxes [Abstract]
Tax credit carryforwards	$ 4,300

Income Taxes Reconciliation of

Income Taxes Reconciliation of Tax Expense (Benefit) and Other (Details) - USD ($)	3 Months Ended	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Federal statutory tax benefit		$ (48,519,000)	$ 136,873,000	$ (120,335,000)
Federal tax reform changes - 2017 Tax Act		0	0	(63,675,000)
State tax benefit (net of federal benefit)		260,000	2,771,000	(3,286,000)
Change in valuation allowance		(13,000)	105,000	(2,727,000)
Employee share-based compensation		3,346,000	2,508,000	8,190,000
Other		883,000	1,113,000	(1,137,000)
Income tax expense (benefit)		(44,043,000)	143,370,000	(182,970,000)
Proceeds from income tax refunds	$ 7,700,000
Proceeds expected from income tax refunds	3,800,000	3,800,000
Unrecognized tax benefits [Roll Forward]
Unrecognized tax benefits	$ 446,000	$ 446,000	$ 446,000	$ 446,000

Long-term Debt Revolving Credit

Long-term Debt Revolving Credit Facility (Details) $ in Thousands		12 Months Ended
		Dec. 31, 2019USD ($)	Feb. 06, 2020USD ($)	Dec. 31, 2018USD ($)
Line of Credit Facility [Line Items]
Line of credit agreement, maximum amount outstanding during period		$ 100,000
Line of credit agreement, minimum amount of unrestricted cash and investments		300,000
Revolving credit facility		$ 122,500		$ 0
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 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 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 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 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] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, maximum loan amount		$ 2,500,000
Line of credit agreement, current borrowing base		1,600,000
Line of credit agreement, aggregate lender commitment amount		1,200,000		1,000,000
Revolving credit facility	[1]	122,500		0
Letters of credit	[2]	0		200
Available borrowing capacity		1,077,500		999,800
Credit facility, unamortized deferred financing costs		$ 5,900		$ 6,400
Subsequent Event [Member] | Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, aggregate lender commitment amount			$ 1,200,000
Revolving credit facility			113,500
Letters of credit			0
Available borrowing capacity			$ 1,086,500
Eurodollar [Member] | Line of Credit [Member] | Borrowing Base Utilization of 25 Percent [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, basis spread on variable rate	[3]	1.50%
Eurodollar [Member] | 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, basis spread on variable rate	[3]	1.75%
Eurodollar [Member] | 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, basis spread on variable rate	[3]	2.00%
Eurodollar [Member] | 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, basis spread on variable rate	[3]	2.25%
Eurodollar [Member] | Line of Credit [Member] | Borrowing Base Utilization Of 90 Percent Or More [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, basis spread on variable rate	[3]	2.50%
Debt Instrument Variable Rate, Alternative Base Rate, And Swingline Loans [Member] | Line of Credit [Member] | Borrowing Base Utilization of 25 Percent [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, basis spread on variable rate		0.50%
Debt Instrument Variable Rate, Alternative Base Rate, And Swingline Loans [Member] | 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, basis spread on variable rate		0.75%
Debt Instrument Variable Rate, Alternative Base Rate, And Swingline Loans [Member] | 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, basis spread on variable rate		1.00%
Debt Instrument Variable Rate, Alternative Base Rate, And Swingline Loans [Member] | 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, basis spread on variable rate		1.25%
Debt Instrument Variable Rate, Alternative Base Rate, And Swingline Loans [Member] | Line of Credit [Member] | Borrowing Base Utilization Of 90 Percent Or More [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, basis spread on variable rate		1.50%
Minimum [Member] | Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, covenant compliance, adjusted current ratio		1
12/31/18 QE through 12/31/19 QE [Member] | Maximum [Member] | Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, covenant compliance, total funded debt to adjusted EBITDAX ratio		4.25
3/31/20 QE and Thereafter [Member] | Maximum [Member] | Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, covenant compliance, total funded debt to adjusted EBITDAX ratio		4
[1]	(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 $5.9 million and $6.4 million as of December 31, 2019 , and 2018 , respectively. These costs are being amortized over the term of the credit facility on a straight-line basis.
[2]	(2) Letters of credit outstanding reduce the amount available under the credit facility on a dollar-for-dollar basis. The letter of credit outstanding as of December 31, 2018 , was released effective January 8, 2019.
[3]	(1) The Company’s Credit Agreement specifies that in the event that LIBOR is no longer a widely used benchmark rate, or that it shall no longer be 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 borrower.

Long-term Debt Senior Notes (De

Long-term Debt Senior Notes (Details) - USD ($) $ in Thousands	Aug. 20, 2018	Jul. 16, 2018	Sep. 12, 2016	May 21, 2015	Nov. 17, 2014	May 20, 2013	Sep. 30, 2018	Mar. 31, 2016	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Senior Notes [Line Items]
Principal amount, net of unamortized deferred financing costs									$ 2,453,035	$ 2,448,439
Loss on extinguishment of debt									0	(26,740)	$ (35)
Accelerated unamortized deferred financing costs for extinguishment of debt									$ 0	6,334	$ 22
6.125% Senior Notes Due 2022 [Member]
Senior Notes [Line Items]
Senior Notes, interest rate, stated percentage									6.125%
Principal amount					$ 600,000				$ 476,796	476,796
Unamortized deferred financing costs									(2,920)	(3,921)
Principal amount, net of unamortized deferred financing costs									$ 473,876	472,875
Senior Notes, repurchased face amount							$ 85,000	$ 38,200
Senior Notes repurchased, settlement amount							89,500	$ 24,300
Net proceeds from Senior Notes issuance					590,000
Senior Notes debt issuance costs					$ 10,000
5% Senior Notes Due 2024 [Member]
Senior Notes [Line Items]
Senior Notes, interest rate, stated percentage									5.00%
Principal amount						$ 500,000			$ 500,000	500,000
Unamortized deferred financing costs									(3,766)	(4,688)
Principal amount, net of unamortized deferred financing costs									$ 496,234	495,312
Net proceeds from Senior Notes issuance						490,200
Senior Notes debt issuance costs						$ 9,800
5.625% Senior Notes Due 2025 [Member]
Senior Notes [Line Items]
Senior Notes, interest rate, stated percentage									5.625%
Principal amount				$ 500,000					$ 500,000	500,000
Unamortized deferred financing costs									(4,903)	(5,808)
Principal amount, net of unamortized deferred financing costs									$ 495,097	494,192
Net proceeds from Senior Notes issuance				491,000
Senior Notes debt issuance costs				$ 9,000
6.75% Senior Notes Due 2026 [Member]
Senior Notes [Line Items]
Senior Notes, interest rate, stated percentage									6.75%
Principal amount			$ 500,000						$ 500,000	500,000
Unamortized deferred financing costs									(5,571)	(6,407)
Principal amount, net of unamortized deferred financing costs									$ 494,429	493,593
Net proceeds from Senior Notes issuance			491,600
Senior Notes debt issuance costs			$ 8,400
6.625% Senior Notes Due 2027 [Member]
Senior Notes [Line Items]
Senior Notes, interest rate, stated percentage									6.625%
Principal amount	$ 500,000								$ 500,000	500,000
Unamortized deferred financing costs									(6,601)	(7,533)
Principal amount, net of unamortized deferred financing costs									493,399	492,467
Net proceeds from Senior Notes issuance	492,100
Senior Notes debt issuance costs	$ 7,900
Senior Notes [Member]
Senior Notes [Line Items]
Principal amount									2,476,796	2,476,796
Unamortized deferred financing costs									(23,761)	(28,357)
Principal amount, net of unamortized deferred financing costs									$ 2,453,035	2,448,439
6.50% Senior Notes Due 2021 [Member]
Senior Notes [Line Items]
Senior Notes repurchased, settlement amount		$ 355,900
6.50% Senior Notes Due 2023 [Member]
Senior Notes [Line Items]
Senior Notes, repurchased face amount							395,000
Q3 2018 Senior Notes Transactions [Member]
Senior Notes [Line Items]
Senior Notes repurchased, settlement amount							$ 497,800
Loss on extinguishment of debt										(26,700)
Premiums paid for extinguishment of debt										20,400
Accelerated unamortized deferred financing costs for extinguishment of debt										$ 6,300

Long-term Debt Senior Convertib

Long-term Debt Senior Convertible Notes (Details)	Aug. 12, 2016USD ($)$ / shares	Dec. 31, 2019USD ($)$ / shares	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Senior Convertible Notes [Line Items]
Senior Convertible Notes, net carrying amount		$ 157,263,000	$ 147,894,000
Capped call transaction costs	$ 24,200,000
Capped Call, Cap Price | $ / shares	$ 60
Capitalized interest costs		18,500,000	20,600,000	$ 12,600,000
1.50% Senior Convertible Notes Due 2021 [Member]
Senior Convertible Notes [Line Items]
Senior Convertible Notes, principal amount	$ 172,500,000	$ 172,500,000	172,500,000
Senior Convertible Notes, interest rate, stated percentage		1.50%
Proceeds from Debt, Net of Issuance Costs	166,600,000
Senior Convertible Notes, debt issuance costs	(5,900,000)
Senior Convertible Notes, threshold trading days		20
Senior Convertible Notes, threshold consecutive trading days		30
Senior Convertible Notes, threshold percentage of stock price trigger		130.00%
Senior Convertible Notes, threshold business days, trading price trigger		5 days
Senior Convertible Notes, threshold trading days, trading price trigger		5 days
Senior Convertible Notes, principal amount of note		$ 1,000
Senior Convertible Notes, threshold percentage of trading price trigger		98.00%
Senior Convertible Notes, conversion rate		24.6914
Senior Convertible Notes, conversion price | $ / shares		$ 40.50
Senior Convertible Notes, initial fair value of liability component	$ 132,300,000
Senior Convertible Notes, effective interest rate	7.25%
Senior Convertible Notes, initial value of equity component	$ 40,200,000
Senior Convertible Notes, interest expense		$ 11,000,000	10,500,000	$ 9,900,000
Senior Convertible Notes, unamortized debt discount		(13,861,000)	(22,313,000)
Unamortized deferred financing costs		(1,376,000)	(2,293,000)
Senior Convertible Notes, net carrying amount		157,263,000	147,894,000
Senior Convertible Notes, net carrying amount, equity component		$ 33,600,000	$ 33,600,000

Commitments (Details)

Commitments (Details) Bcf in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2019USD ($)MMBblsBcf	Dec. 31, 2019USD ($)MMBblsBcf	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Commitments and Contingencies
Contractual obligation, due in 2020	$ 102,550,000	$ 102,550,000
Contractual obligation, due in 2021	94,494,000	94,494,000
Contractual obligation, due in 2022	73,826,000	73,826,000
Contractual obligation, due in 2023	41,661,000	41,661,000
Contractual obligation, due in 2024	12,349,000	12,349,000
Contractual obligation, due thereafter	24,697,000	24,697,000
Contractual obligation	349,577,000	$ 349,577,000
Loss on drilling and completion contract terminations	$ 18,200,000
Crude oil pipeline commitment [Member]
Commitments and Contingencies
Oil and gas delivery commitments, remaining minimum contractual volumes | MMBbls	24	24
Natural gas pipeline commitment [Member]
Commitments and Contingencies
Oil and gas delivery commitments, remaining minimum contractual volumes | Bcf	424	424
Crude Oil Pipeline Commitment Excluded from Remaining Deficiency Payment Amount [Member]
Commitments and Contingencies
Oil and gas delivery commitments, remaining minimum contractual volumes | MMBbls	16.5	16.5
Drilling Rig Leasing Contracts [Member]
Commitments and Contingencies
Contractual obligation	$ 34,100,000	$ 34,100,000
Early Termination Penalty for Rig Contract Cancellation	26,300,000	26,300,000
PipelineCommitments [Member]
Commitments and Contingencies
Contractual obligation	218,500,000	218,500,000
Office Space Leases [Member]
Commitments and Contingencies
Contractual obligation	28,300,000	28,300,000
Operating leases, rent expense, net of sublease income		5,500,000	$ 4,500,000	$ 4,800,000
Electricity Purchase Agreement [Member]
Commitments and Contingencies
Contractual obligation	53,200,000	53,200,000
Other miscellaneous contracts and leases [Member]
Commitments and Contingencies
Contractual obligation	$ 15,500,000	$ 15,500,000
Water pipeline commitment [Member]
Commitments and Contingencies
Water delivery commitments, remaining minimum contractual volumes | MMBbls	18	18
Minimum [Member] | Completion Service Commitment [Member]
Commitments and Contingencies
Potential Penalty for not Meeting Minimum Completion Service Arrangement Requirements	$ 0	$ 0
Minimum [Member] | Sand Sourcing Commitment [Member]
Commitments and Contingencies
Potential Penalty for not Meeting Minimum Sand Sourcing Requirements	0	0
Maximum [Member] | Completion Service Commitment [Member]
Commitments and Contingencies
Potential Penalty for not Meeting Minimum Completion Service Arrangement Requirements	13,400,000	13,400,000
Maximum [Member] | Sand Sourcing Commitment [Member]
Commitments and Contingencies
Potential Penalty for not Meeting Minimum Sand Sourcing Requirements	$ 10,000,000	$ 10,000,000

Compensation Plans_ Stock Based

Compensation Plans: Stock Based (Details) $ / shares in Units, $ in Millions		Dec. 31, 2019USD ($)$ / sharesshares	Dec. 31, 2019USD ($)shares$ / shares	Dec. 31, 2018USD ($)$ / sharesshares	Dec. 31, 2017USD ($)$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares of common stock available for grant		4,400,000	4,400,000
Impact outright issuance of one share has on number of available shares			1
Director [Member]
Director Shares
Shares Issued, Shares, Share-based Payment Arrangement, before Forfeiture			96,719	63,741	71,573
Performance Shares [Member]
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	0	0	0
Award vesting period		3 years
Multiplier assumed			1
Stock-based compensation expense | $			$ 10.9	$ 10.3	$ 9.7
Unrecognized stock based compensation expense | $		$ 15.9	15.9
Fair value of PSUs/RSUs granted in period | $			$ 10.2	$ 14	$ 15.5
Share-based compensation arrangement by share-based payment award, increment vesting period			6 months
Shares Issued in Period			0	0	0
Fair value of PSUs/RSUs Vested in Period | $			$ 9.1	$ 10.3	$ 8.1
Weighted Average Grant Date Fair Value
Non-vested at beginning of year (in shares)	[1]		1,711,259	1,533,491	828,923
Non-vested outstanding at the beginning of the period (in dollars per share) | $ / shares			$ 20.68	$ 22.97	$ 43.25
Granted (in shares)	[1]		793,125	572,924	977,731
Granted (in dollars per share) | $ / shares			$ 12.80	$ 24.45	$ 15.86
Vested (in shares)	[1]		(346,021)	(233,102)	(94,338)
Vested (in dollars per share) | $ / shares			$ 26.32	$ 44.25	$ 85.85
Forfeited (in shares)	[1]		(135,778)	(162,054)	(178,825)
Forfeited (in dollars per share) | $ / shares			$ 16.98	$ 21.79	$ 44.99
Non-vested at end of year (in shares)	[1]	2,022,585	2,022,585	1,711,259	1,533,491
Non-vested outstanding at the end of the period (in dollars per share) | $ / shares		$ 16.87	$ 16.87	$ 20.68	$ 22.97
Performance Shares [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Multiplier applied to PSU awards at settlement		0	0
Performance Shares [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Multiplier applied to PSU awards at settlement		2	2
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period		3 years
Stock-based compensation expense | $			$ 11.1	$ 10.8	$ 10.3
Unrecognized stock based compensation expense | $		$ 16.9	16.9
Fair value of PSUs/RSUs granted in period | $			$ 12.1	$ 15	$ 17
Number of Shares Represented by Each RSU		1	1
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vesting Increment				0.33
Share-based compensation arrangement by share-based payment award, increment vesting period			6 months
Restricted Stock, Shares Settled Gross of Shares for Tax Withholdings	[2]		466,535,000	407,529,000	246,025,000
Shares held for settlement of income and payroll tax obligations (in shares)			(132,136,000)	(115,784,000)	(74,747,000)
Shares Issued in Period			334,399,000	291,745,000	171,278,000
Fair value of PSUs/RSUs Vested in Period | $			$ 10.2	$ 9.9	$ 10.8
Weighted Average Grant Date Fair Value
Non-vested at beginning of year (in shares)			1,243,163	1,244,262	604,116
Non-vested outstanding at the beginning of the period (in dollars per share) | $ / shares			$ 21.50	$ 20.25	$ 37.39
Granted (in shares)			978,932	583,552	1,020,780
Granted (in dollars per share) | $ / shares			$ 12.36	$ 25.77	$ 16.64
Vested (in shares)			(466,535)	(407,529)	(246,025)
Vested (in dollars per share) | $ / shares			$ 21.94	$ 24.30	$ 43.99
Forfeited (in shares)			(223,429)	(177,122)	(134,609)
Forfeited (in dollars per share) | $ / shares			$ 18.16	$ 17.26	$ 26.38
Non-vested at end of year (in shares)		1,532,131	1,532,131	1,243,163	1,244,262
Non-vested outstanding at the end of the period (in dollars per share) | $ / shares		$ 16.01	$ 16.01	$ 21.50	$ 20.25
Restricted Stock Units (RSUs) [Member] | Director [Member]
Weighted Average Grant Date Fair Value
Granted (in shares)					8,794
Shares Issued to the Board of Directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense | $			$ 1.2	$ 1.7	$ 1.6
[1]	(1) The number of awards assumes a multiplier of one . The final number of shares of common stock issued may vary depending on the three -year performance multiplier, which ranges from zero to two .
[2]	(1) During the years ended December 31, 2019 , 2018 , and 2017 , 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.

Compensation Plans Employee Sto

Compensation Plans Employee Stock Purchase Plan (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Compensation plans
Number of shares of common stock available for grant	4,400,000
Employee Stock Purchase Plan [Member]
Compensation plans
Maximum employee subscription rate	15.00%
Share-based compensation arrangement by share-based payment award, maximum employee subscription	$ 25,000
Percent of offering date price paid	85.00%
Number of shares of common stock available for grant	1,300,000
Issuance of common stock under Employee Stock Purchase Plan (Shares)	314,868	199,464	186,665
Proceeds from issuance of shares under incentive and share-based compensation plans, excluding stock options	$ 3,200,000	$ 3,200,000	$ 2,600,000
Risk free interest rate	2.30%	1.80%	0.90%
Dividend yield	0.70%	0.40%	0.50%
Volatility factor of the expected market price of the Company's common stock	56.60%	55.90%	62.50%
Expected life (in years)	15 days	15 days	15 days
Stock-based compensation expense	$ 1,100,000	$ 1,100,000	$ 1,000,000

Compensation Plans Non Stock-Ba

Compensation Plans Non Stock-Based Compensation (Details) - 401K Plan [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
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, employer matching contribution, percent of employees' gross pay	6.00%
Defined Contribution Plan, matching contributions	$ 5.1	$ 4.9	$ 4.5
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%
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%

Pension Benefits (Details)

Pension Benefits (Details) - USD ($)		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Jan. 01, 2018		Jan. 01, 2017
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Projected benefit obligation at beginning of year		$ 66,086,000	$ 71,937,000
Defined Benefit Plan, service cost		5,582,000	6,730,000	$ 6,638,000
Defined Benefit Plan, interest cost		2,791,000	2,622,000	2,689,000
Defined Benefit Plan, actuarial (gain) loss		2,035,000	(7,155,000)
Defined Benefit Plan, benefits paid		(5,651,000)	(8,048,000)
Projected benefit obligation at end of year		70,843,000	66,086,000	71,937,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, fair value of plan assets at beginning of year		30,100,000	30,978,000
Defined Benefit Plan, actual return on plan assets		3,985,000	(964,000)
Defined Benefit Plan, employer contribution		7,200,000	8,134,000	7,000,000
Defined Benefit Plan, benefits paid		(5,651,000)	(8,048,000)	(10,800,000)
Defined Benefit Plan, fair value of plan assets at end of year		35,634,000	30,100,000	30,978,000
Defined Benefit Plan, funded status at end of year		(35,209,000)	(35,986,000)
Defined Benefit Plan, Plan with Accumulated Benefit Obligation in Excess of Plan Assets [Abstract]
Defined Benefit Plan, projected benefit obligation		70,843,000	66,086,000
Defined Benefit Plan, accumulated benefit obligation		60,877,000	52,368,000
Defined Benefit Plan, fair value of plan assets		35,634,000	30,100,000
Defined Benefit Plan, underfunded accumulated benefit obligation		$ 25,243,000	22,268,000
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		$ 14,406,000	15,741,000
Defined Benefit Plan, unrecognized prior service costs		31,000	48,000
Defined Benefit Plan, accumulated other comprehensive loss		14,437,000	15,789,000
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Other Comprehensive Income (Loss), Defined Benefit Plan, net actuarial gain (loss)		377,000	4,329,000	(2,995,000)
Other Comprehensive Income (Loss), Defined Benefit Plan, amortization of prior service cost		17,000	18,000	17,000
Other Comprehensive Income (Loss), Defined Benefit Plan, amortization of net actuarial loss		958,000	1,327,000	1,297,000
Other Comprehensive Income (Loss), Defined Benefit Plan, settlements		0	0	3,009,000
Other Comprehensive Income (Loss), Defined Benefit Plan, total pension liability adjustment, pre-tax		1,352,000	5,674,000	1,328,000
Other Comprehensive Income (Loss), Defined Benefit Plan, tax (expense) benefit		(291,000)	(4,265,000)	(561,000)
Other Comprehensive Income (Loss), Defined Benefit Plan, cumulative effect of accounting change	[1]				$ 0		$ 44,732,000
Other Comprehensive Income (Loss), Defined Benefit Plan, total pension liability adjustment, net	[2]	(1,061,000)	(4,378,000)	(767,000)
Components of Net Periodic Benefit Costs for Both Pension Plans
Defined Benefit Plan, service cost		5,582,000	6,730,000	6,638,000
Defined Benefit Plan, interest cost		2,791,000	2,622,000	2,689,000
Defined Benefit Plan, expected return on plan assets that reduces periodic pension benefit cost		(1,574,000)	(1,862,000)	(2,244,000)
Defined Benefit Plan, amortization of prior service cost		17,000	18,000	17,000
Defined Benefit Plan, amortization of net actuarial loss		958,000	1,327,000	1,297,000
Defined Benefit Plan, settlements		0	0	3,009,000
Defined Benefit Plan, net periodic benefit cost		$ 7,774,000	$ 8,835,000	$ 11,406,000
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation and Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, discount rate		3.60%	4.40%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, rate of compensation increase		4.50%	6.20%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, discount rate		4.40%	3.80%	4.20%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, expected return on plan assets	[3]	5.00%	5.50%	6.50%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, rate of compensation increase		6.20%	6.20%	6.20%
Defined Benefit Plan, Expected Future Employer Contributions [Abstract]
Defined Benefit Plan, Expected Future Contributions in Next Fiscal Year		$ 5,600,000
Future Benefit Payments
Defined Benefit Plan, Expected Future Benefit Payments in Year One		7,609,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Two		3,914,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Three		4,022,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Four		6,308,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Five		4,939,000
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter		25,065,000
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%
Equity 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		$ 9,580,000
Defined Benefit Plan, fair value of plan assets at end of year		13,134,000	$ 9,580,000
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		12,420,000
Defined Benefit Plan, fair value of plan assets at end of year		13,578,000	12,420,000
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		8,100,000
Defined Benefit Plan, fair value of plan assets at end of year		8,922,000	$ 8,100,000
Accounting Standards Update 2018-02 [Member]
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Other Comprehensive Income (Loss), Defined Benefit Plan, cumulative effect of accounting change		$ 0		$ 0	$ 2,969,000	[4]
[1]	(1) Please refer to Recently Issued Accounting Standards in Note 1 – Summary of Significant Accounting Policies for additional information.
[2]	(1) Please refer to Note 8 – Pension Benefits for additional discussion on the pension liability adjustment.
[3]	(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.
[4]	(1) Please refer to Recently Issued Accounting Standards in Note 1 – Summary of Significant Accounting Policies and Statements of Stockholders’ Equity for additional information.

Pension Benefits Fair Value of

Pension Benefits Fair Value of Plan Assets in Heirarchy (Details) - USD ($)		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
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		$ 35,634,000	$ 30,100,000	$ 30,978,000
Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		26,672,000	19,259,000
Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		3,214,000	5,334,000
Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		5,748,000	5,507,000	5,209,000
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		190,000	191,000
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Unrealized Gain on Assets		51,000	152,000
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Disposition		$ 0	$ (45,000)
Domestic equity securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	[1],[2]	17.30%	15.40%
Defined Benefit Plan, Plan Assets, Amount	[2]	$ 6,176,000	$ 4,639,000
Domestic equity securities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[2]	4,130,000	3,197,000
Domestic equity securities [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[2]	2,046,000	1,442,000
Domestic equity securities [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[2]	$ 0	$ 0
International equity securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	[1],[3]	19.60%	16.40%
Defined Benefit Plan, Plan Assets, Amount	[3]	$ 6,958,000	$ 4,941,000
International equity securities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[3]	6,958,000	3,642,000
International equity securities [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[3]	0	1,299,000
International equity securities [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[3]	$ 0	$ 0
Total equity securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		35.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage		36.90%	31.80%
Defined Benefit Plan, Plan Assets, Amount		$ 13,134,000	$ 9,580,000
Total equity securities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		11,088,000	6,839,000
Total equity securities [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		2,046,000	2,741,000
Total equity securities [Member] | 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	[1],[4]	31.40%	34.40%
Defined Benefit Plan, Plan Assets, Amount	[4]	$ 11,199,000	$ 10,342,000
Core fixed income [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[4]	11,199,000	10,342,000
Core fixed income [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[4]	0	0
Core fixed income [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[4]	$ 0	$ 0
Floating rate corporate loans [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	[1],[5]	6.70%	6.90%
Defined Benefit Plan, Plan Assets, Amount	[5]	$ 2,379,000	$ 2,078,000
Floating rate corporate loans [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[5]	2,379,000	2,078,000
Floating rate corporate loans [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[5]	0	0
Floating rate corporate loans [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[5]	$ 0	$ 0
Total fixed income securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		40.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage		38.10%	41.30%
Defined Benefit Plan, Plan Assets, Amount		$ 13,578,000	$ 12,420,000
Total fixed income securities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		13,578,000	12,420,000
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
Real estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	[1],[6]	5.40%	6.00%
Defined Benefit Plan, Plan Assets, Amount	[6]	$ 1,929,000	$ 1,820,000
Real estate [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[6]	0	0
Real estate [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[6]	0	0
Real estate [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[6]	$ 1,929,000	$ 1,820,000
Collective investment trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	[1],[7]	3.30%	3.10%
Defined Benefit Plan, Plan Assets, Amount	[7]	$ 1,168,000	$ 934,000
Collective investment trusts [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[7]	0	0
Collective investment trusts [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[7]	1,168,000	934,000
Collective investment trusts [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[7]	$ 0	$ 0
Hedge fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	[1],[8]	16.30%	17.80%
Defined Benefit Plan, Plan Assets, Amount	[8]	$ 5,825,000	$ 5,346,000
Hedge fund [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[8]	2,006,000	0
Hedge fund [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[8]	0	1,659,000
Hedge fund [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[8]	$ 3,819,000	$ 3,687,000
Total other securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		25.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage		25.00%	26.90%
Defined Benefit Plan, Plan Assets, Amount		$ 8,922,000	$ 8,100,000
Total other securities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		2,006,000	0
Total other securities [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		1,168,000	2,593,000
Total other securities [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		5,748,000	5,507,000
Nonqualified Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		$ 0	$ 0	$ 0
[1]	(1) Percentages may not calculate due to rounding.
[2]	(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]	(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 and believed to have strong sustainable financial productivity at attractive valuations.
[4]	(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]	(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]	(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]	(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]	(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.

Earnings Per Share (Details)

Earnings Per Share (Details) $ / shares in Units, shares in Thousands, $ in Thousands	Dec. 31, 2019USD ($)$ / shares	Dec. 31, 2019USD ($)$ / sharesshares	Dec. 31, 2018USD ($)$ / sharesshares	Dec. 31, 2017USD ($)$ / sharesshares	Aug. 12, 2016USD ($)$ / shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Capped Call, Cap Price | $ / shares					$ 60
Anti-dilutive shares excluded from earnings per share | shares		684	0	264
Earnings Per Share Reconciliation [Abstract]
Net income (loss) | $		$ (187,001)	$ 508,407	$ (160,843)
Basic weighted-average common shares outstanding | shares		112,544	111,912	111,428
Dilutive effect of non-vested RSUs and contingent PSUs | shares		0	1,590	0
Diluted weighted-average common shares outstanding | shares		112,544	113,502	111,428
Basic net income (loss) per common share | $ / shares		$ (1.66)	$ 4.54	$ (1.44)
Diluted net income (loss) per common share | $ / shares		$ (1.66)	$ 4.48	$ (1.44)
1.50% Senior Convertible Notes Due 2021 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Senior Convertible Notes, principal amount | $	$ 172,500	$ 172,500	$ 172,500		$ 172,500
Senior Convertible Notes, conversion price | $ / shares	$ 40.50	$ 40.50
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period	3 years
Multiplier applied to PSU awards at settlement	0	0	0	0
Minimum [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Multiplier applied to PSU awards at settlement	0	0
Maximum [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Multiplier applied to PSU awards at settlement	2	2

Derivative Financial Instrume_3

Derivative Financial Instruments (Details) bbl in Thousands, BTU in Billions		Feb. 19, 2020$ / Barrelsbbl	Dec. 31, 2019BTU$ / EnergyContent$ / Barrelsbbl
IF WAHA [Member]
Derivative Financial Instruments
Index percent of natural gas fixed swaps			92.00%
GD Waha [Member]
Derivative Financial Instruments
Index percent of natural gas fixed swaps			8.00%
Subsequent Event [Member] | WTI Midland NYMEX WTI [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		16,300
Derivative, Weighted-Average Contract Price | $ / Barrels		1.14
NYMEX Oil Swap Contract First Quarter, 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			2,486
Derivative, Swap Type, Average Fixed Price | $ / Barrels			59.65
NYMEX Oil Swap Contract Second Quarter, 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			2,838
Derivative, Swap Type, Average Fixed Price | $ / Barrels			58.81
NYMEX Oil Swap Contract Third Quarter, 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			3,361
Derivative, Swap Type, Average Fixed Price | $ / Barrels			56.43
NYMEX Oil Swap Contract Fourth Quarter, 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			3,937
Derivative, Swap Type, Average Fixed Price | $ / Barrels			56.94
NYMEX Oil Swap Contract, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			667
Derivative, Swap Type, Average Fixed Price | $ / Barrels			56
NYMEX Oil Swap Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			13,289
NYMEX Oil Swap Contracts [Member] | Subsequent Event [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		600
Derivative, Swap Type, Average Fixed Price | $ / Barrels		57.82
NYMEX Oil Collar Contract First Quarter, 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			2,267
Derivative, Floor Price | $ / Barrels			55
Derivative, Ceiling Price | $ / Barrels			63.91
NYMEX Oil Collar Contract Second Quarter, 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			1,881
Derivative, Floor Price | $ / Barrels			55
Derivative, Ceiling Price | $ / Barrels			62.17
NYMEX Oil Collar Contract Third Quarter, 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			1,252
Derivative, Floor Price | $ / Barrels			55
Derivative, Ceiling Price | $ / Barrels			62.90
NYMEX Oil Collar Contract Fourth Quarter, 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			610
Derivative, Floor Price | $ / Barrels			55
Derivative, Ceiling Price | $ / Barrels			61.90
NYMEX Oil Collar Contract, 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			329
Derivative, Floor Price | $ / Barrels			55
Derivative, Ceiling Price | $ / Barrels			56.70
NYMEX Oil Collar Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			6,339
Oil Basis Swap Contract First Quarter, 2020 [Member] | WTI Midland NYMEX WTI [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			4,193
Derivative, Weighted-Average Contract Price | $ / Barrels	[1]		(0.68)
Oil Basis Swap Contract First Quarter, 2020 [Member] | NYMEX WTI ICE Brent [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			0
Derivative, Weighted-Average Contract Price | $ / Barrels	[2]		0
Oil Basis Swap Contract Second Quarter, 2020 [Member] | WTI Midland NYMEX WTI [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			3,495
Derivative, Weighted-Average Contract Price | $ / Barrels	[1]		(0.68)
Oil Basis Swap Contract Second Quarter, 2020 [Member] | NYMEX WTI ICE Brent [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			910
Derivative, Weighted-Average Contract Price | $ / Barrels	[2]		(8.06)
Oil Basis Swap Contract Third Quarter, 2020 [Member] | WTI Midland NYMEX WTI [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			3,325
Derivative, Weighted-Average Contract Price | $ / Barrels	[1]		(0.74)
Oil Basis Swap Contract Third Quarter, 2020 [Member] | NYMEX WTI ICE Brent [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			920
Derivative, Weighted-Average Contract Price | $ / Barrels	[2]		(8.01)
Oil Basis Swap Contract Fourth Quarter, 2020 [Member] | WTI Midland NYMEX WTI [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			3,261
Derivative, Weighted-Average Contract Price | $ / Barrels	[1]		(0.73)
Oil Basis Swap Contract Fourth Quarter, 2020 [Member] | NYMEX WTI ICE Brent [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			920
Derivative, Weighted-Average Contract Price | $ / Barrels	[2]		(8.01)
Oil Basis Swap Contract, 2021 [Member] | WTI Midland NYMEX WTI [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			5,954
Derivative, Weighted-Average Contract Price | $ / Barrels	[1]		0.59
Oil Basis Swap Contract, 2021 [Member] | NYMEX WTI ICE Brent [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			3,650
Derivative, Weighted-Average Contract Price | $ / Barrels	[2]		(7.86)
Oil Basis Swap Contract, 2022 [Member] | WTI Midland NYMEX WTI [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			0
Derivative, Weighted-Average Contract Price | $ / Barrels	[1]		0
Oil Basis Swap Contract, 2022 [Member] | NYMEX WTI ICE Brent [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			3,650
Derivative, Weighted-Average Contract Price | $ / Barrels	[2]		(7.78)
Oil Basis Swap [Member] | WTI Midland NYMEX WTI [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			20,228
Oil Basis Swap [Member] | NYMEX WTI ICE Brent [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			10,050
Gas Swaps Contract First Quarter, 2020 [Member] | IF HSC [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU			9,123
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent			2.98
Gas Swaps Contract First Quarter, 2020 [Member] | WAHA [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU			3,099
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent			1.93
Gas Swaps Contract Second Quarter, 2020 [Member] | IF HSC [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU			4,160
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent			2.20
Gas Swaps Contract Second Quarter, 2020 [Member] | WAHA [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU			3,196
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent			0.56
Gas Swaps Contract Third Quarter, 2020 [Member] | IF HSC [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU			4,493
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent			2.41
Gas Swaps Contract Third Quarter, 2020 [Member] | WAHA [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU			3,268
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent			1.03
Gas Swaps Contract Fourth Quarter, 2020 [Member] | IF HSC [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU			3,722
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent			2.36
Gas Swaps Contract Fourth Quarter, 2020 [Member] | WAHA [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU			3,419
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent			1.17
Gas Swaps Contract, 2021 [Member] | IF HSC [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU			0
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent			0
Gas Swaps Contract, 2021 [Member] | WAHA [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU			4,224
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent			1.51
Gas Swaps Contracts [Member] | IF HSC [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU	[3]		21,498
Gas Swaps Contracts [Member] | WAHA [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU	[3]		17,206
NGL Swaps Contract First Quarter, 2020 [Member] | OPIS Purity Ethane Mont Belvieu [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			447
Derivative, Swap Type, Average Fixed Price | $ / Barrels			11.53
NGL Swaps Contract First Quarter, 2020 [Member] | OPIS Propane Mont Belvieu Non-TET [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			382
Derivative, Swap Type, Average Fixed Price | $ / Barrels			22.64
NGL Swaps Contract Second Quarter, 2020 [Member] | OPIS Purity Ethane Mont Belvieu [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			264
Derivative, Swap Type, Average Fixed Price | $ / Barrels			11.13
NGL Swaps Contract Second Quarter, 2020 [Member] | OPIS Propane Mont Belvieu Non-TET [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			382
Derivative, Swap Type, Average Fixed Price | $ / Barrels			22.34
NGL Swaps Contract Third Quarter, 2020 [Member] | OPIS Purity Ethane Mont Belvieu [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			0
Derivative, Swap Type, Average Fixed Price | $ / Barrels			0
NGL Swaps Contract Third Quarter, 2020 [Member] | OPIS Propane Mont Belvieu Non-TET [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			409
Derivative, Swap Type, Average Fixed Price | $ / Barrels			22.33
NGL Swaps Contract Fourth Quarter, 2020 [Member] | OPIS Purity Ethane Mont Belvieu [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			0
Derivative, Swap Type, Average Fixed Price | $ / Barrels			0
NGL Swaps Contract Fourth Quarter, 2020 [Member] | OPIS Propane Mont Belvieu Non-TET [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			466
Derivative, Swap Type, Average Fixed Price | $ / Barrels			22.29
NGL Swaps Contracts [Member] | OPIS Purity Ethane Mont Belvieu [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			711
NGL Swaps Contracts [Member] | OPIS Propane Mont Belvieu Non-TET [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			1,639
[1]	(1) Represents the price differential between WTI Midland (Midland, Texas) and NYMEX WTI (Cushing, Oklahoma).
[2]	(2) Represents the price differential between NYMEX WTI (Cushing, Oklahoma) and ICE Brent (North Sea).
[3]	(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, 2019 , WAHA volumes were comprised of 92 percent IF WAHA and eight percent GD WAHA

Derivative Financial Instrume_4

Derivative Financial Instruments Fair Value (Details) $ in Thousands	Dec. 31, 2019USD ($)		Dec. 31, 2018USD ($)		Dec. 31, 2017
Fair value of derivative assets and liabilities
Derivative, Fair Value, Net	$ 21,500		$ 158,300
Derivative Assets, Current	55,184		175,130
Derivative Assets, Noncurrent	20,624		58,499
Total Derivative Assets	75,808		233,629
Derivative Liabilities, Current	50,846		62,853
Derivative Liabilities, Noncurrent	3,444		12,496
Total Derivative Liabilities	(54,290)		(75,349)
Derivative Asset, Not Offset in the Accompanying Balance Sheets	(35,075)		(56,041)
Derivative Liabilities, Not Offset in the Accompanying Balance Sheets	35,075		56,041
Derivative Asset, Fair Value, Net Amounts	40,733		177,588
Derivative Liability, Fair Value, Net Amounts	(19,215)		(19,308)
Not Designated as Hedging Instrument [Member]
Fair value of derivative assets and liabilities
Derivative Assets, Current	55,184		175,130
Derivative Assets, Noncurrent	20,624		58,499
Derivative Liabilities, Current	50,846		62,853
Derivative Liabilities, Noncurrent	3,444		12,496
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	75,808	[1]	233,629	[2]
Total Derivative Liabilities	$ 54,290	[1]	$ 75,349	[2]
Designated as Hedging Instrument [Member]
Fair value of derivative assets and liabilities
Derivative, Number of Instruments Held	0		0		0
[1]	(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.
[2]	(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.

Derivative Financial Instrume_5

Derivative Financial Instruments Gains and Losses (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivative Instruments, (Gain) Loss [Line Items]
Derivative settlement (gain) loss	$ (39,222)	$ 135,803	$ (21,234)
Net derivative (gain) loss	97,539	(161,832)	26,414
Oil Contracts [Member]
Derivative Instruments, (Gain) Loss [Line Items]
Derivative settlement (gain) loss	19,685	68,860	31,176
Net derivative (gain) loss	172,055	(192,002)	71,502
Gas Contracts [Member]
Derivative Instruments, (Gain) Loss [Line Items]
Derivative settlement (gain) loss	(23,008)	13,029	(87,857)
Net derivative (gain) loss	(41,205)	35,411	(76,315)
NGL Contracts [Member]
Derivative Instruments, (Gain) Loss [Line Items]
Derivative settlement (gain) loss	(35,899)	53,914	35,447
Net derivative (gain) loss	$ (33,311)	$ (5,241)	$ 31,227

Derivative Financial Instrume_6

Derivative Financial Instruments Credit Facility and Derivative Counterparties (Details)	Dec. 31, 2019
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 ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017	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	$ 75,808		$ 233,629
Liabilities:
Derivative Liability, Fair Value, Gross Liability	(54,290)		(75,349)
Oil and Gas Properties
Impairment of proved properties	0		0		$ 3,800
Abandonment and impairment of unproved properties	33,800		49,900		12,300
Impairment of oil and gas properties	$ 33,842		49,889		$ 16,078
6.125% Senior Notes Due 2022 [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Senior Notes, interest rate, stated percentage	6.125%
Debt Instrument, Face Amount	$ 476,796		476,796							$ 600,000
Long-term Debt, Fair Value	$ 481,564		452,336
5% Senior Notes Due 2024 [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Senior Notes, interest rate, stated percentage	5.00%
Debt Instrument, Face Amount	$ 500,000		500,000								$ 500,000
Long-term Debt, Fair Value	$ 479,815		439,265
5.625% Senior Notes Due 2025 [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Senior Notes, interest rate, stated percentage	5.625%
Debt Instrument, Face Amount	$ 500,000		500,000						$ 500,000
Long-term Debt, Fair Value	$ 475,835		436,460
6.75% Senior Notes Due 2026 [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Senior Notes, interest rate, stated percentage	6.75%
Debt Instrument, Face Amount	$ 500,000		500,000				$ 500,000
Long-term Debt, Fair Value	$ 494,860		448,305
6.625% Senior Notes Due 2027 [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Senior Notes, interest rate, stated percentage	6.625%
Debt Instrument, Face Amount	$ 500,000		500,000			$ 500,000
Long-term Debt, Fair Value	$ 493,750		442,500
1.50% Senior Convertible Notes Due 2021 [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Senior Notes, interest rate, stated percentage	1.50%
Debt Instrument, Face Amount	$ 172,500		172,500					$ 172,500
Long-term Debt, Fair Value	164,430		158,614
Proved Properties [Member]
Oil and Gas Properties
Proved and unproved oil and gas properties recorded at fair value	0		0
Unproved Properties [Member]
Oil and Gas Properties
Proved and unproved oil and gas properties recorded at fair value	0		0
Not Designated as Hedging Instrument [Member] | Fair Value, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Assets:
Derivative Assets, Fair Value, Gross Asset	0	[1]	0	[2]
Liabilities:
Derivative Liability, Fair Value, Gross Liability	0	[1]	0	[2]
Not Designated as Hedging Instrument [Member] | Fair Value, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Assets:
Derivative Assets, Fair Value, Gross Asset	75,808	[1]	233,629	[2]
Liabilities:
Derivative Liability, Fair Value, Gross Liability	54,290	[1]	75,349	[2]
Not Designated as Hedging Instrument [Member] | Fair Value, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Assets:
Derivative Assets, Fair Value, Gross Asset	0	[1]	0	[2]
Liabilities:
Derivative Liability, Fair Value, Gross Liability	$ 0	[1]	$ 0	[2]
[1]	(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.
[2]	(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.

Suspended Well Costs (Details)

Suspended Well Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Beginning balance	$ 11,197	$ 49,446	$ 19,846
Additions to capitalized exploratory well costs pending the determination of proved reserves	11,925	11,197	49,446
Divestitures	0	(109)	0
Reclassification to wells, facilities, and equipment based on the determination of proved reserves	(11,197)	(49,337)	(19,846)
Capitalized exploratory well costs charged to expense	0	0	0
Ending balance	11,925	$ 11,197	$ 49,446
Exploratory well costs capitalized for more than one year	$ 0

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2019		Dec. 31, 2018
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning asset retirement obligations		$ 94,194	[1]	$ 114,470
Liabilities incurred	[2]	3,927		4,054
Liabilities settled	[3]	(4,105)		(33,024)
Accretion expense		4,016		4,438
Revision to estimated cash flows		(11,186)		4,256
Ending asset retirement obligations	[1]	86,846		94,194
Current asset retirement obligation liability		$ 2,700		$ 2,300
[1]	(3) Balances as of December 31, 2019 , and 2018 , included $2.7 million and $2.3 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.
[2]	(1) Reflects liabilities incurred through drilling activities and acquisitions of drilled wells.
[3]	(2) Reflects liabilities settled through plugging and abandonment activities and divestitures of properties.

Accounts Receivable (Details)

Accounts Receivable (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Accounts Receivable
Accounts receivable	$ 184,732	$ 167,536
Oil, gas, and NGL production revenue [Member]
Accounts Receivable
Accounts receivable	146,308	107,230
Amounts due from joint interest owners [Member]
Accounts Receivable
Accounts receivable	22,681	31,497
State severance tax refunds [Member]
Accounts Receivable
Accounts receivable	4,069	4,415
Derivative settlements [Member]
Accounts Receivable
Accounts receivable	6,868	9,475
Other [Member]
Accounts Receivable
Accounts receivable	$ 4,806	$ 14,919

Accounts Payable and Accrued Ex

Accounts Payable and Accrued Expenses (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Accounts Payable and Accrued Liabilities, Current [Abstract]
Drilling and lease operating cost accruals	$ 96,925	$ 139,711
Trade accounts payable	52,094	56,047
Revenue and severance tax payable	109,847	94,806
Property taxes	24,535	18,694
Compensation	41,540	31,486
Derivative settlements	5,851	1,287
Interest	44,175	40,840
Other	27,041	20,328
Total accounts payable and accrued expenses	$ 402,008	$ 403,199

Leases Lease Parameter (Details

Leases Lease Parameter (Details)	Dec. 31, 2019
Lessee, Lease, Description [Line Items]
Weighted average remaining lease term	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	6 years

Components of total lease cost

Components of total lease cost (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Lessee Disclosure [Abstract]
Total lease cost	$ 442,949	[1]
Operating lease cost	35,570
Short-term lease cost	301,373	[2]
Variable lease cost	106,006	[3]
Operating cash flows from operating leases	12,074
Investing cash flows from operating leases	24,129
Right-of-use assets obtained in exchange for new operating lease liabilities	$ 25,360
[1]	(3) Lease costs are either expensed on the accompanying statements of operations or capitalized on the accompanying balance sheets depending on the nature and use of the underlying ROU asset.
[2]	(1) Costs associated with short-term lease agreements relate primarily to operational activities where underlying lease terms are less than one year. This amount is significant as it 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.
[3]	(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.

Operating lease liability matur

Operating lease liability maturities (Details) $ in Thousands	Dec. 31, 2019USD ($)
Lessee Disclosure [Abstract]
Operating lease liability payments, due 2020	$ 21,102
Operating lease liability payments, due 2021	12,600
Operating lease liability payments, due 2022	5,749
Operating lease liability payments, due 2023	3,602
Operating lease liability payments, due 2024	2,081
Operating lease liability payments, due thereafter	1,639
Total Lease payments	46,773
Imputed interest	(4,447)	[1]
Total operating lease liability	$ 42,326
Weighted-average discount rate	6.60%
[1]	(1) The weighted-average discount rate used to determine the operating lease liability as of December 31, 2019 was 6.6 percent .

Balance Sheet information relat

Balance Sheet information related to operating leases (Details) $ in Thousands	Dec. 31, 2019USD ($)
Lessee Disclosure [Abstract]
Other noncurrent assets	$ 39,717
Other current liabilities	19,189
Other noncurrent liabilities	$ 23,137

Uncategorized Items - sm-201912

Label	Element	Value	[1]
AOCI Attributable to Parent [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ (2,969,000)
Additional Paid-in Capital [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	1,108,000
Retained Earnings [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	2,969,000
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ 43,624,000
[1]	(1) Please refer to Recently Issued Accounting Standards in Note 1 – Summary of Significant Accounting Policies for additional information.