SM Energy (SM) 10-K 21 Feb 19 2018 Q4 Annual report Financial data

Document and Entity Information

Document and Entity Information Document - USD ($)	12 Months Ended
	Dec. 31, 2018	Feb. 07, 2019	Jun. 29, 2018
Document and Entity Information [Abstract]
Entity Registrant Name	SM Energy Co
Entity Central Index Key	893,538
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q4
Amendment Flag	false
Entity Common Stock, Shares Outstanding		112,243,245
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 2,844,912,835
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false

CONSOLIDATED BALANCE SHEETS (in

CONSOLIDATED BALANCE SHEETS (in thousands, except share data) - USD ($) $ in Thousands	Jan. 01, 2018	Dec. 31, 2018		Dec. 31, 2017
Current assets:
Cash and cash equivalents		$ 77,965		$ 313,943
Accounts receivable		167,536		160,154
Derivative assets		175,130		64,266
Prepaid expenses and other		8,632		10,752
Total current assets		429,263		549,115
Property and equipment (successful efforts method):
Proved oil and gas properties		7,278,362		6,139,379
Accumulated depletion, depreciation, and amortization		(3,417,953)		(3,171,575)
Unproved oil and gas properties		1,581,401		2,047,203
Wells in progress		295,529		321,347
Properties held for sale, net		5,280		111,700
Other property and equipment, net of accumulated depreciation of $57,102 and $49,985, respectively		88,546		106,738
Total property and equipment, net		5,831,165		5,554,792
Noncurrent assets:
Derivative assets		58,499		40,362
Other noncurrent assets		33,935		32,507
Total noncurrent assets		92,434		72,869
Total assets		6,352,862		6,176,776
Current liabilities:
Accounts payable and accrued expenses		403,199		386,630
Derivative liabilities		62,853		172,582
Total current liabilities		466,052		559,212
Noncurrent liabilities:
Revolving credit facility		0		0
Senior Notes, net of unamortized deferred financing costs		2,448,439		2,769,663
Senior Convertible Notes, net of unamortized discount and deferred financing costs		147,894		139,107
Asset retirement obligations		91,859		103,026
Asset retirement obligations associated with oil and gas properties held for sale		0		11,369
Deferred income taxes		223,278		79,989
Derivative liabilities		12,496		71,402
Other noncurrent liabilities		42,522		48,400
Total noncurrent liabilities		2,966,488		3,222,956
Commitments and contingencies (note 6)
Stockholders' Equity:
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 112,241,966 and 111,687,016 shares, respectively		1,122		1,117
Additional paid-in capital		1,765,738		1,741,623
Retained earnings		1,165,842	[1]	665,657
Accumulated other comprehensive loss		(12,380)	[1]	(13,789)
Total stockholders' equity		2,920,322		2,394,608
Total liabilities and stockholders' equity		$ 6,352,862		$ 6,176,776
Accounting Standards Update 2018-02 [Member]
Cumulative Effect on Retained Earnings, Net of Tax	$ 3,000
[1]	(1) The Company reclassified $3.0 million of tax effects stranded in accumulated other comprehensive loss to retained earnings as of January 1, 2018. Please refer to Note 1 – Summary of Significant Accounting Policies for further detail.

CONSOLIDATED BALANCE SHEETS Par

CONSOLIDATED BALANCE SHEETS Parenthetical - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Other property and equipment, accumulated depreciation	$ 57,102	$ 49,985
Common Stock, par value per share	$ 0.01	$ 0.01
Common Stock, Shares Authorized	200,000,000	200,000,000
Common Stock, Shares, Issued	112,241,966	111,687,016
Common Stock, Shares, Outstanding	112,241,966	111,687,016

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, 2018		Dec. 31, 2017		Dec. 31, 2016
Operating revenues and other income:
Oil, gas, and NGL production revenue	$ 1,636,357	[1]	$ 1,253,783	[2]	$ 1,178,426	[3]
Net gain (loss) on divestiture activity	426,917		(131,028)		37,074
Other operating revenues	3,798		6,621		1,950
Total operating revenues and other income	2,067,072		1,129,376		1,217,450
Operating Expenses:
Oil, gas, and NGL production expense	487,367		507,906		597,565
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	665,313		557,036		790,745
Exploration	55,166		54,713		64,970
Impairment of proved properties	0		3,806		354,614
Abandonment and impairment of unproved properties	49,889		12,272		80,367
General and administrative	116,504		117,283		124,828
Net derivative (gain) loss	(161,832)		26,414		250,633
Other operating expenses, net	18,328		13,667		10,772
Total operating expenses	1,230,735		1,293,097		2,274,494
Income (loss) from operations	836,337		(163,721)		(1,057,044)
Interest expense	(160,906)		(179,257)		(158,685)
Gain (loss) on extinguishment of debt	(26,740)		(35)		15,722
Other non-operating income (expense), net	3,086		(800)		(1,909)
Income (loss) before income taxes	651,777		(343,813)		(1,201,916)
Income tax (expense) benefit	(143,370)		182,970		444,172
Net income (loss)	$ 508,407		$ (160,843)		$ (757,744)
Basic weighted-average common shares outstanding	111,912		111,428		76,568
Diluted weighted-average common shares outstanding	113,502		111,428		76,568
Basic net income (loss) per common share	$ 4.54		$ (1.44)		$ (9.90)
Diluted net income (loss) per common share	$ 4.48		$ (1.44)		$ (9.90)
[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, 2018	Dec. 31, 2017	Dec. 31, 2016
Statement of Comprehensive Income [Abstract]
Net income (loss)		$ 508,407	$ (160,843)	$ (757,744)
Other comprehensive income (loss), net of tax:
Pension liability adjustment	[1]	4,378	767	(1,154)
Other comprehensive income (loss), net of tax		4,378	767	(1,154)
Total comprehensive income (loss)		$ 512,785	$ (160,076)	$ (758,898)
[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, 2015				68,075,700
Balances, Total stockholders' equity, beginning at Dec. 31, 2015		$ 1,852,401		$ 681	$ 305,607	$ 1,559,515		$ (13,402)
Increase (Decrease) in Stockholders' Equity
Net income (loss)		(757,744)				(757,744)
Other comprehensive income (loss)		(1,154)						(1,154)
Cash dividends, $ 0.10 per share		(7,751)				(7,751)
Issuance of common stock under Employee Stock Purchase Plan (in shares)				218,135
Issuance of common stock under Employee Stock Purchase Plan		4,198		$ 2	4,196
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings (in shares)				199,243
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings		(2,354)		$ 2	(2,356)
Stock-based compensation expense (in shares)				53,473
Stock-based compensation expense		26,897		$ 1	26,896
Issuance of common stock from stock offerings, net of tax (in shares)				42,710,949
Issuance of common stock from stock offerings, net of tax		1,383,093		$ 427	1,382,666
Equity component of 1.50% Senior Convertible Notes due 2021 issuance, net of tax		33,575			33,575
Purchase of capped call transactions		(24,195)			(24,195)
Adjustments to Additional Paid in Capital, Other		(9,833)			(9,833)
Balances, Common Stock, Shares, Outstanding, Ending at Dec. 31, 2016				111,257,500
Balances, Total stockholders' equity, ending at Dec. 31, 2016		$ 2,497,133		$ 1,113	1,716,556	794,020		(14,556)
Cash dividends per share		$ 0.10
Increase (Decrease) in Stockholders' Equity
Net income (loss)		$ (160,843)				(160,843)
Other comprehensive income (loss)		767						767
Cash dividends, $ 0.10 per share		(11,144)				(11,144)
Issuance of common stock under Employee Stock Purchase Plan (in shares)				186,665
Issuance of common stock under Employee Stock Purchase Plan		2,623		$ 2	2,621
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings (in shares)				171,278
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings		(1,240)		$ 1	(1,241)
Stock-based compensation expense (in shares)				71,573
Stock-based compensation expense		$ 22,700		$ 1	22,699
Issuance of common stock from stock offerings, net of tax (in shares)		0
Adjustments to Additional Paid in Capital, Other		$ (120)			(120)
Balances, Common Stock, Shares, Outstanding, Ending at Dec. 31, 2017		111,687,016		111,687,016
Balances, Total stockholders' equity, ending at Dec. 31, 2017		$ 2,394,608		$ 1,117	1,741,623	665,657		(13,789)
Increase (Decrease) in Stockholders' Equity
Cumulative effect of accounting change	[1]	$ 44,732			1,108	43,624
Cash dividends per share		$ 0.10
Net income (loss)		$ 508,407				508,407
Other comprehensive income (loss)		4,378						4,378
Cash dividends, $ 0.10 per share		(11,191)				(11,191)
Issuance of common stock under Employee Stock Purchase Plan (in shares)				199,464
Issuance of common stock under Employee Stock Purchase Plan		3,187		$ 2	3,185
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings (in shares)				291,745
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings		(2,975)		$ 3	(2,978)
Stock-based compensation expense (in shares)				63,741
Stock-based compensation expense		$ 23,908		$ 0	23,908
Issuance of common stock from stock offerings, net of tax (in shares)		0
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)
Increase (Decrease) in Stockholders' Equity
Cumulative effect of accounting change		$ 0	[1]		$ 0	$ 2,969	[1]	$ (2,969)	[1]
[1]	(1) Refer to Recently Issued Accounting Standards in Note 1 – Summary of Significant Accounting Policies for additional information.

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017		Dec. 31, 2016
Cash flows from operating activities:
Net income (loss)		$ 508,407	$ (160,843)		$ (757,744)
Adjustments to reconcile net loss to net cash provided by operating activities:
Net (gain) loss on divestiture activity		(426,917)	131,028		(37,074)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion		665,313	557,036		790,745
Impairment of proved properties		0	3,806		354,614
Abandonment and impairment of unproved properties		49,889	12,272		80,367
Stock-based compensation expense		23,908	22,700		26,897
Net derivative (gain) loss		(161,832)	26,414		250,633
Derivative settlement gain (loss)		(135,803)	21,234		329,478
Amortization of debt discount and deferred financing costs		15,258	16,276		9,938
(Gain) loss on extinguishment of debt		26,740	35		(15,722)
Deferred income taxes		141,708	(192,066)		(448,643)
Other, net		287	7,885		(9,931)
Changes in current assets and liabilities:
Accounts receivable		(30,152)	13,997		(10,562)
Prepaid expenses and other		(729)	(1,953)		8,478
Accounts payable and accrued expenses		23,819	44,985		(53,210)
Accrued derivative settlements		20,733	12,584		34,540
Net cash provided by operating activities		720,629	515,390		552,804
Cash flows from investing activities:
Net proceeds from the sale of oil and gas properties		748,509	776,719		946,062
Capital expenditures		(1,303,188)	(888,353)		(629,911)
Acquisition of proved and unproved oil and gas properties		(33,255)	(89,896)		(2,183,790)
Net cash used in investing activities		(587,934)	(201,530)		(1,867,639)
Cash flows from financing activities:
Proceeds from credit facility		0	406,000		947,000
Repayment of credit facility		0	(406,000)		(1,149,000)
Net proceeds from Senior Notes		492,079	0		491,640
Cash paid to repurchase senior notes, including premium		(845,002)	(2,357)		(29,904)
Net proceeds from Senior Convertible Notes		0	0		166,617
Cash paid for capped call transactions		0	0		(24,195)
Net proceeds from sale of common stock		3,187	2,623		938,268
Dividends paid		(11,191)	(11,144)		(7,751)
Other, net		(7,746)	(1,411)		(5,486)
Net cash provided by (used in) financing activities		(368,673)	(12,289)		1,327,189
Net change in cash, cash equivalents, and restricted cash		(235,978)	301,571		12,354	[1]
Cash, cash equivalents, and restricted cash at beginning of period		313,943	12,372	[1]	18	[1]
Cash, cash equivalents, and restricted cash at end of period		77,965	313,943		12,372	[1]
Supplemental Cash Flow Information - Operating Activities [Abstract]
Cash paid for interest, net of capitalized interest		(150,727)	(164,097)		(129,761)
Net cash (refunded) paid for income taxes		2,995	5,986		(4,690)
Supplemental Cash Flow Information - Investing Activities [Abstract]
Changes in capital expenditure accruals and other		(2,774)	7,309		8,044
Supplemental Cash Flow Information - Non-Cash Investing Activities [Abstract]
Carrying value of properties exchanged		95,121			733
Supplemental Cash Flow Information - Non-Cash Financing Activities [Abstract]
Issuance of common stock for an asset acquisition	[2]	0	0		437,194
Non-cash (gain) loss on extinguishment of debt, net		$ 6,334	$ 22		$ (15,722)
[1]	(1) Cash, cash equivalents, and restricted cash for the year ended December 31, 2016, includes $3.0 million of restricted cash which is included in other noncurrent assets on the accompanying balance sheets.
[2]	(1) Refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions and Note 13 – Equity for additional discussion.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2018
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 onshore North America. 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, 2018 , 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 and Restricted Cash 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. Restricted cash includes cash that is contractually restricted for its use through an agreement with a non-related party. The Company includes restricted cash in other noncurrent assets on the accompanying balance sheets. 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 15 – 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 Company had the following major customers and sales to entities under common ownership, which 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, 2018 2017 2016 Major customer #1 (1) 18 % 6 % — % Major customer #2 (1) 10 % 10 % 5 % Group #1 of entities under common ownership (2) 18 % 17 % 15 % Group #2 of entities under common ownership (2) 12 % 8 % 8 % ____________________________________________ (1) These major customers are purchasers of a portion of the Company’s production from its Permian region. (2) In the aggregate, these groups of entities under common ownership represented 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 represented more than 10 percent of the Company’s total oil, gas, and NGL production revenue. The Company’s policy is to use the commodity affiliates of the lenders under its Credit Agreement as its derivative counterparties, and each counterparty must have investment grade senior unsecured debt ratings. Each of the Company’s 10 derivative counterparties meet both of these requirements as of the filing of this report. 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 with a common geological structure) 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 cash flows from investing activities 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. Assets Held for Sale Any properties held for sale as of the balance sheet date have been classified as assets held for sale and are separately presented on the accompanying balance sheets at the lower of carrying value or fair value less the estimated cost to sell. Properties classified as held for sale, including any corresponding asset retirement obligation liability, are valued using a market approach, based on an estimated net selling price, as evidenced by the most current bid prices received from third-parties, if available. If an estimated selling price is not available, the Company utilizes the various valuation techniques discussed above. Please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions . Asset Retirement Obligations The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties, including facilities requiring decommissioning. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is drilled or acquired, or a facility is constructed. The increase in carrying value is included in proved oil and gas properties 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 operating section of the Company’s 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, 2018 , and 2017 . Derivative Financial Instruments The Company periodically enters into derivative commodity instruments to reduce its exposure to pricing volatility for a portion of its expected future oil, natural gas, and NGL production. These instruments typically include commodity price swaps and costless collars, as well as, basis differential swaps. Derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as assets and/or liabilities. The Company does not designate its derivative instruments to qualify for hedge accounting. 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 cash flows from operations in the accompanying consolidated statement of cash flows. For additional discussion on derivatives, please see 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 control of the product transfers to the customer, which differs depending on the contractual terms of each of the Company’s arrangements. 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, 2018 , the Company had stock-based employee compensation plans that included restricted stock units (“RSUs”) and performance share units (“PSUs”) issued to employees and RSUs and restricted stock issued to non-employee directors, as well as 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 general and administrative and exploration expense 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 restricted stock units, contingent Performance Share Units, 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). 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 zero balance under its credit facility as of December 31, 2018 , and 2017 . The Company’s Senior Notes and Senior Convertible Notes are recorded at cost, net of any unamortized discount and deferred financing costs, and the respective fair values are disclosed in Note 11 – Fair Value Measurements . 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 2018 or 2017 . 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 adjustment 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. Please refer to Note 4 – Income Taxes for additional discussion . Effective December 31, 2017, the Company early adopted, on a retrospective basis, FASB ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”) and FASB ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (“ASU 2016-18”). ASU 2016-15 is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The Company determined that of the eight issues addressed in ASU 2016-15, only the issue related to debt extinguishment costs impacted the Company’s consolidated financial statements and disclosures. In accordance with ASU 2016-15, the Company reclassified certain debt extinguishment costs from operating activities to financing activities. ASU 2016-18 is intended to clarify guidance on the classification and presentation of restricted cash and restricted cash equivalents in the statement of cash flows. In accordance with ASU 2016-18, the Company reclassified $3.0 million of restricted cash out of investing activities and combined it with cash and cash equivalents in the accompanying statements of cash flows for the year ended December 31, 2016. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”) . Under the new standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. The standard requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The FASB issued several additional ASUs related to ASU 2014-09 that provide clarified implementation guidance and deferred the effective date of ASU 2014-09. Effective January 1, 2018, the Company adopted ASU 2014-09 and all related ASUs using the modified retrospective transition method, which was applied to all active contracts as of the effective date. The adoption of ASU 2014-09 did not result in a change to current or prior period results nor did it result in a material change to the Company’s business processes, systems, or controls. However, upon adoption, the Company expanded its disclosures to comply with the disclosure requirements of ASU 2014-09. Please refer to Note 2 - Revenue from Contracts with Customers for additional discussion. 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”). ASU 2016-02 requires lessees to recognize right-of-use assets and lease payment liabilities on the balance sheet for leases representing the Company’s right to use the underlying assets for the lease term. Each lease that is recognized in the balance sheet will be classified as either finance or operating, with such classification affecting the pattern and classification of expense recognition in the consolidated statements of operations and presentation within the statements of cash flows. The Company leveraged a dedicated project team and external consultants to evaluate the impacts of ASU 2016-02, which included an analysis of contracts for office leases, drilling rig agreements, well completion agreements, midstream agreements, water handling agreements, certain field equipment rentals, land easements, and other arrangements that included potential lease components. 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. The Company has completed the process of reviewing and determining contracts to which the new guidance applies, and has implemented policies, internal controls, and processes that are necessary to support the additional accounting and disclosure requirements going forward. The lease administration system that will support the on-going maintenance and accounting after adoption is operational and is currently being populated with the necessary lease data and relevant assumptions. Policy elections and practical expedients the Company has implemented as part of adopting 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 allows the Company to avoid reassessing contracts that commenced prior to adoption that were properly evaluated under legacy GAAP, (d) excluding land easements that existed or expired before adoption of ASU 2016-02, and (e) the policy election that eliminates the need for adjusting prior period comparable financial statements prepared under legacy lease accounting guidance. The Company adopted ASU 2016-02 on January 1, 2019, using the modified retrospective approach, and has necessary staff and processes in place to ensure on-going compliance. Adoption of this guidance will result in an increase in right-of-use assets and related liabilities on the Company’s consolidated balance sheets. In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU 2017-01”). ASU 2017-01 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The Company adopted ASU 2017-01 on the effective date of January 1, 2018, on a prospective basis. 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. The accompanying statements of operations line items that were adjusted as a result of the adoption of ASU 2017-07 for the years ended December 31, 2017 , and 2016 are summarized as follows: For the Year Ended December 31, 2017 For the Year Ended December 31, 2016 As Reported As Adjusted As Reported As Adjusted (in thousands) Operating expenses: Exploration $ 56,179 $ 54,713 $ 65,641 $ 64,970 General and administrative $ 120,585 $ 117,283 $ 126,428 $ 124,828 Total operating expenses $ 1,297,865 $ 1,293,097 $ 2,276,765 $ 2,274,494 Income (loss) from operations $ (168,489 ) $ (163,721 ) $ (1,059,315 ) $ (1,057,044 ) Other non-operating income (expense), net $ 3,968 $ (800 ) $ 362 $ (1,909 ) 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. 2018-14, Compensation-Retirement Benefits-Defined Benefit Plans-General (Subtopic 715-20): Disclosure Framework-Changes to the Disclosure Requirements for Defined Benefit Plans (“ASU 2018-14”). ASU 2018-14 provides updated disclosure requirements related to retirement benefits and defined pension plans with the purpose of improving the effectiveness of disclosures with regard to such topics. The guidance is to be applied using a retrospective method and is effective for fiscal years ending after December 15, 2020, with early adoption permitted. The Company early adopted ASU 2018-14 on December 31, 2018, and it did not result in a material impact to the Company’s consolidated financial statements or disclosures. In August 2018, the FASB issued ASU No. 2018-15, Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”). ASU 2018-1

Revenue from Contracts with Cus

Revenue from Contracts with Customers	12 Months Ended
	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Revenue from Contracts with Customer	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 Permian, South Texas & Gulf Coast, and Rocky Mountain regions. During the first quarter of 2018, the Company entered into two definitive agreements to sell all of its producing properties in its Rocky Mountain region. One transaction closed in the first quarter of 2018, and the second transaction closed in the second quarter of 2018. As a result of these divestitures, there has been no production revenue from the Rocky Mountain region after the second quarter of 2018. Please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions for additional detail. 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 disaggregation of oil, gas, and NGL production revenue by product type for each of the Company’s operating regions for the years ended December 31, 2018 , 2017 , and 2016 : For the year ended December 31, 2018 Permian South Texas & Gulf Coast Rocky Mountain Total (in thousands) Oil, gas, and NGL production revenue: 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 Permian South Texas & Gulf Coast Rocky Mountain Total (in thousands) Oil, gas, and NGL production revenue: 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. For the year ended December 31, 2016 Permian South Texas & Gulf Coast Rocky Mountain Total (in thousands) Oil, gas, and NGL production revenue: Oil production revenue $ 117,399 $ 189,313 $ 305,126 $ 611,838 Gas production revenue 17,315 308,829 11,144 337,288 NGL production revenue 92 225,821 3,387 229,300 Total $ 134,806 $ 723,963 $ 319,657 $ 1,178,426 Relative percentage 11 % 62 % 27 % 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 customer, which differs depending on the contractual terms of each of the Company’s arrangements. 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 prior to control transfer are recorded within the oil, gas, and NGL production expense line item on the accompanying statements of operations, while fees and other deductions incurred subsequent to control transfer are recorded as a reduction of oil, gas, and NGL production revenue. The Company has four categories under which oil, gas, and NGL production revenue is generated. Each of the Company’s operating regions generate production revenue from a combination of some or all of the four different contract types summarized below: 1) The Company sells oil production at or near the wellhead and receives an agreed-upon index price from the purchaser, net of basis, quality, and transportation differentials. Under this arrangement, control transfers at or near the wellhead. 2) The Company sells unprocessed gas to a midstream processor at the wellhead or inlet of the midstream processing facility. The midstream processor gathers and processes the raw gas stream and remits proceeds to the Company from the ultimate sale of the processed NGLs and residue gas to third parties. In such arrangements, the midstream processor obtains control of the product at the wellhead or inlet of the facility and is considered the customer. Proceeds received for unprocessed gas under these arrangements are reflected as gas production revenue and are recorded net of transportation and processing fees incurred by the midstream processor after control has transferred. 3) 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 it generates from selling the NGLs to other 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 gathering, transportation, and processing fees 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. 4) The Company has certain midstream processing arrangements where unprocessed gas is delivered to the inlet of the midstream processor’s facility for processing. Upon completion of processing, the midstream processor purchases the processed NGLs and residue gas and remits the proceeds to the Company from the sale of the products to third-party customers. In these arrangements, control transfers at the tailgate of the midstream processing facility for both products. Given the structure of these arrangements and where control transfers, the Company separately recognizes gathering, transportation, and processing fees 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 predictable differentials. Accordingly, the Company does not consider estimates of variable consideration to be constrained. The Company’s contractual 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 customer 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 contractual 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 accounts receivable 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, 2018 and December 31, 2017 , were $107.2 million and $96.6 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. Revenue recognized for the year ended December 31, 2018 , that related to performance obligations satisfied in prior reporting periods, was immaterial.

Divestitures, Assets Held for S

Divestitures, Assets Held for Sale, and Acquisitions	12 Months Ended
	Dec. 31, 2018
Acquisitions, Divestitures, and Assets Held for Sale Disclosure [Abstract]
Divestitures, Assets Held for Sale, and Acquisitions [Text Block]	Note 3 – Divestitures, Assets Held for Sale, and Acquisitions 2018 Divestiture Activity PRB Divestiture. On March 26, 2018 , the Company divested approximately 112,000 net acres of its Powder River Basin assets for net divestiture proceeds of $492.2 million , and recorded a final net gain of $410.6 million for the year ended December 31, 2018 . These assets were recorded as properties held for sale as of December 31, 2017. 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 . A portion of these assets were recorded as properties held for sale as of December 31, 2017. The following table presents loss before income taxes from the Divide County, North Dakota assets sold for the years ended December 31, 2018 , 2017 , and 2016 . The Divide County Divestiture was considered a disposal of a significant asset group. For the Years Ended December 31, 2018 2017 2016 (in thousands) Loss before income taxes (1) $ (28,975 ) $ (468,786 ) $ (50,034 ) ____________________________________________ (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 previously held for sale. 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. The following table presents income (loss) before income taxes from the outside-operated Eagle Ford shale assets sold for the years ended December 31, 2018 , 2017 , and 2016 . This divestiture was considered a disposal of a significant asset group. For the Years Ended December 31, 2018 2017 2016 (in thousands) Income (loss) before income taxes (1) $ — $ 24,324 $ (218,506 ) ____________________________________________ (1) Income (loss) before income taxes reflects oil, gas, and NGL production revenue, less oil, gas, and NGL production expense, and depletion, depreciation, amortization, and asset retirement obligation liability accretion. Additionally, income (loss) before income taxes includes $269.6 million of impairment of proved properties expense for the year ended December 31, 2016 . Rocky Mountain and Permian Divestitures. During 2017, the Company divested certain non-core properties in its Rocky Mountain and Permian regions for net divestiture proceeds of $36.2 million and recognized an insignificant final net gain. 2016 Divestiture Activity Rocky Mountain Divestitures. During the third quarter of 2016, the Company divested certain non-core properties in the Williston Basin and Powder River Basin in two separate transactions for combined net divestiture proceeds of $110.3 million and a final net gain of $16.4 million . During the fourth quarter of 2016, the Company divested certain Williston Basin assets located outside of Divide County, North Dakota (referred to as “Raven/Bear Den” throughout this report) for net divestiture proceeds of $755.7 million and a final net gain of $29.5 million . In conjunction with this divestiture, the Company closed its Billings, Montana regional office. Permian Divestiture. During the third quarter of 2016, the Company divested its non-core properties in southeast New Mexico for net divestiture proceeds of $54.7 million and recorded a final net loss of $10.0 million . The Company finalized these divestitures in 2017. The Company determined that neither planned nor executed asset sales in 2018 , 2017 , and 2016 qualify for discontinued operations accounting under financial statement presentation authoritative guidance. Properties Held for Sale Assets are classified as held for sale when the Company commits to a plan to sell the assets and it is probable the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and a measurement for impairment is performed to identify and expense any excess of carrying value over fair value less estimated costs to sell. When assets no longer meet the criteria of assets held for sale, they are measured at the lower of the carrying value of the assets before being classified as held for sale, adjusted for any depletion, depreciation, and amortization expense that would have been recognized, or the fair value at the date they are reclassified to assets held for use. Any gain or loss recognized on assets held for sale or on assets held for sale that are subsequently reclassified to assets held for use is reflected in the net gain (loss) on divestiture activity line item on the accompanying statements of operations. As of December 31, 2018 , and 2017 , there were $5.3 million and $111.7 million , respectively, of assets held for sale presented on the accompanying balance sheets. The balance as of December 31, 2017, consisted primarily of approximately 112,000 net acres in the Powder River Basin, and is presented net of accumulated depletion, depreciation, and amortization expense. As discussed above, the Company sold these assets in the first quarter of 2018. 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 unproved properties, located in Howard and Martin Counties, Texas, resulting in the Company exchanging approximately 2,650 net acres, with $95.1 million of carrying value attributed to the properties surrendered by the Company. These trades were recorded at carryover basis with no gain or loss recognized. Subsequent to December 31, 2018 , the Company completed several non-monetary acreage trades of primarily unproved properties, located in Howard, Martin, and Upton Counties, Texas, resulting in the Company receiving approximately 1,580 net acres in exchange for approximately 1,650 net acres. 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 considered asset acquisitions and the properties were recorded based on the fair value of the total consideration transferred on the acquisition date and 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 Company acquiring approximately 8,125 net acres in exchange for approximately 7,580 net acres with $294.0 million of carrying value attributed to the properties surrendered by the Company in such trades. These trades were recorded at carryover basis with no gain or loss recognized. 2016 Acquisition Activity Rock Oil Acquisition. During the fourth quarter of 2016, the Company acquired all membership interests of JPM EOC Opal, LLC, which owned proved and unproved properties in the Midland Basin, from Rock Oil Holdings, LLC (referred to as the “Rock Oil Acquisition”). The Company finalized the Rock Oil Acquisition during 2017 by paying $7.7 million of cash consideration in addition to the initial adjusted purchase price of $991.0 million , resulting in total consideration of $998.7 million paid after final closing adjustments. The Company funded the acquisition with proceeds from divestitures in 2016, the Senior Convertible Notes and equity offerings in August 2016, and the 2026 Senior Notes offering in September 2016, as discussed in Note 5 – Long-Term Debt and Note 13 – Equity , respectively. The Company determined that the Rock Oil Acquisition met the criteria of a business combination under ASC Topic 805, Business Combinations . The Company allocated the final adjusted purchase price to the acquired assets and liabilities based on fair value as of the acquisition date, as summarized in the table below. This measurement resulted in no goodwill or bargain purchase gain being recognized. The acquisition costs were insignificant and were expensed as incurred. As of October 4, 2016 (in thousands) Cash consideration $ 998,691 Fair value of assets and liabilities acquired: Wells in progress $ 5,672 Proved oil and gas properties 82,584 Unproved oil and gas properties 913,819 Other assets 5,338 Total fair value of oil and gas properties acquired 1,007,413 Working capital (1,127 ) Asset retirement obligations (7,595 ) Total fair value of net assets acquired $ 998,691 QStar Acquisition. During the fourth quarter of 2016, the Company acquired additional proved and unproved properties in the Midland Basin from QStar LLC and RRP-QStar, LLC (referred to as the “QStar Acquisition”). The Company finalized the QStar Acquisition during the third quarter of 2017 by paying $7.3 million of cash consideration in addition to the initial consideration of $1.2 billion in cash consideration and the issuance of approximately 13.4 million shares of the Company’s common stock, resulting in total consideration of approximately $1.6 billion paid after final closing adjustments. The Company funded the acquisition with proceeds from the 2016 divestitures and the December 2016 equity offering. Please refer to Note 13 – Equity for additional discussion. Under authoritative accounting guidance, the transaction was considered an asset acquisition, and therefore, the properties were recorded based on the fair value of the total consideration transferred on the acquisition date and transaction costs were capitalized as a component of the cost of the assets acquired. The Company allocated the final adjusted purchase price to the acquired assets and liabilities, as summarized in the table below. As of December 21, 2016 (in thousands) Cash consideration, including acquisition costs paid $ 1,174,628 Fair value of equity consideration (1) 437,194 Total consideration $ 1,611,822 Assets and liabilities acquired: Wells in progress $ 21,812 Proved oil and gas properties 61,239 Unproved oil and gas properties 1,538,264 Total oil and gas properties acquired 1,621,315 Working capital (1,852 ) Asset retirement obligations (7,641 ) Total net assets acquired $ 1,611,822 ____________________________________________ (1) The Company issued approximately 13.4 million shares of common stock, par value $0.01 per share, in a private placement to the sellers in the QStar Acquisition on December 21, 2016. The equity consideration was valued on this date using Level 1 and Level 2 inputs with a discount applied due to the lack of marketability in the near term in accordance with the Lock-Up and Registration Rights Agreement that prohibited the sale of such stock until no earlier than the 90th day after issuance.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2018
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, 2018 2017 2016 (in thousands) Current portion of income tax expense (benefit) Federal $ — $ 5,698 $ 2,932 State 1,662 3,398 1,539 Deferred portion of income tax expense (benefit) 141,708 (192,066 ) (448,643 ) Total income tax expense (benefit) $ 143,370 $ (182,970 ) $ (444,172 ) Effective tax rate 22.0 % 53.2 % 37.0 % The components of the net deferred tax liabilities are as follows: As of December 31, 2018 2017 (in thousands) Deferred tax liabilities Oil and gas properties $ 218,094 $ 142,467 Derivative assets 35,247 — Other 4,812 3,412 Total deferred tax liabilities 258,153 145,879 Deferred tax assets Derivative liabilities — 29,463 Credit carryover 22,554 22,537 Pension 6,427 7,986 Federal and state tax net operating loss carryovers 4,217 3,867 Stock compensation 3,263 3,545 Other liabilities 1,497 1,470 Total deferred tax assets 37,958 68,868 Valuation allowance (3,083 ) (2,978 ) Net deferred tax assets 34,875 65,890 Total net deferred tax liabilities $ 223,278 $ 79,989 Current federal income tax refundable $ 59 $ 37 Current state income tax payable $ 1,331 $ 3,009 The enactment of the 2017 Tax Act on December 22, 2017 reduced the Company’s federal tax rate for 2018 and future years from 35 percent to 21 percent . With the conclusion of the one-year measurement period and considering subsequent guidance, the Company believes it has properly analyzed the tax accounting impacts of the 2017 Tax Act, including the $1.0 million limitation on the compensation of certain covered individuals, which impacts the Company’s tax rate. There are no new estimates or finalized income tax items associated with the 2017 Tax Act included in income tax (expense) benefit for the year ended December 31, 2018 . As of December 31, 2018 , the Company estimated its federal net operating loss (“NOL”) carryforward at $2.3 million , which reflects the planning strategies to utilize NOLs for the 2017 and 2016 tax years. In 2017, the Company re-evaluated various factors affecting deferred tax assets related to net operating losses and tax credits and determined utilization would be appropriate. The change in the current quarter portion of income tax (expense) benefit between periods reflects the effect of this determination. The Company expects to receive the 2018 federal current portion of income tax expense as a credit against tax in a future period. See the credit discussion below. After the adoption of ASU 2016-09 in 2017, the Company no longer records a deferred tax amount for unrecognized excess income tax benefits associated with employee share-based payment awards. A cumulative effect adjustment was recorded to the beginning deferred income tax balance and retained earnings as of January 1, 2017. Please refer to Note 1 – Summary of Significant Accounting Policies above for additional information regarding the adoption of ASU 2016-09. The Company has federal research and development (“R&D”) and AMT credit carryforwards of $7.4 million and $15.6 million , respectively. The federal R&D credit carryforwards expire between 2028 and 2034. The Company’s AMT credit carryforwards do not expire and are expected to be fully refunded by 2022. State NOL carryforwards were $79.7 million and state tax credits were $212,000 as of December 31, 2018 . Federal and state NOLs and state credits expire between 2019 and 2038. 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. The change in the valuation allowance from 2017 to 2018 primarily relates to an allocable change to the Company’s mix of state apportioned losses and anticipated utilization of state cumulative NOLs. Federal income tax expense (benefit) differs from the amount that would be provided by applying the statutory United States federal income tax rate to income before income taxes primarily due to the effect of state income taxes, excess tax benefits and deficiencies from share-based payment awards, changes in valuation allowances, R&D credits, and accumulated impacts of other smaller permanent differences, and is reported as follows: For the Years Ended December 31, 2018 2017 2016 (in thousands) Federal statutory tax expense (benefit) $ 136,873 $ (120,335 ) $ (420,671 ) Increase (decrease) in tax resulting from: Federal tax reform changes - 2017 Tax Act — (63,675 ) — State tax expense (benefit) (net of federal benefit) 2,771 (3,286 ) (17,549 ) Change in valuation allowance 105 (2,727 ) (5,059 ) Employee share-based compensation 2,508 8,190 — Other 1,113 (1,137 ) (893 ) Income tax expense (benefit) $ 143,370 $ (182,970 ) $ (444,172 ) Acquisitions, divestitures, drilling activity, and basis differentials, which impact the prices received for oil, gas, and NGLs, impact the apportionment of taxable income to the states where the Company owns oil and gas properties. As these factors change, the Company’s state income tax rate changes. This change, when applied to the Company’s total temporary differences, impacts the total state income tax expense (benefit) reported in the current year. Items affecting state apportionment factors are evaluated upon completion of the prior year income tax return, after significant acquisitions and divestitures, if there are significant changes in drilling activity, or if estimated state revenue changes occur during the year. As a result of the 2018 divestitures, the Company’s state apportionment rate reflects its significant Texas presence. The Company and its subsidiaries file federal income tax returns and various state income tax returns. The Company is generally no longer subject to United States federal or state income tax examinations by tax authorities for years before 2015. During the third quarter of 2018, the IRS finalized its examination of the net operating loss (“NOL”) claims back to tax years 2003 through 2005 with no changes to claimed amounts. The Company received $5.9 million and $5.5 million of cash refunds in 2018 and 2017, respectively, for NOL carryback claims. During 2016, the Company’s 2007 - 2011 IRS examination was finalized, with no material adjustments to previously recorded amounts. 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 2019 . The total amount recorded for unrecognized tax benefits is presented below: For the Years Ended December 31, 2018 2017 2016 (in thousands) Beginning balance $ 446 $ 446 $ 2,782 Additions for tax positions of prior years — — 9 Settlements — — (2,345 ) Ending balance $ 446 $ 446 $ 446

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Long-Term Debt	Note 5 – Long-Term Debt Credit Agreement On September 28, 2018 , the Company and its lenders entered into the Sixth Amended and Restated Credit Agreement. The Credit Agreement, which replaced the Company’s Fifth Amended and Restated Credit Agreement, provides for a senior secured revolving credit facility with a maximum loan amount of $2.5 billion , an initial borrowing base of $1.5 billion , and initial aggregate lender commitments totaling $1.0 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 Company does not expect a material change to the borrowing base or the aggregate lender commitments during the next scheduled redetermination on April 1, 2019 . 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 will use 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, 2018 , and through the filing of this report. Interest and commitment fees are accrued based on a borrowing base utilization grid set forth in the Credit Agreement. Eurodollar loans accrue interest at the London Interbank Offered Rate, plus the applicable margin from the utilization grid, and Alternate Base Rate (“ABR”) or 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 1.500 % 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 % 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 7, 2019 , and December 31, 2018 , and under the Company’s Fifth Amended and Restated Credit Agreement as of December 31, 2017 : As of February 7, 2019 As of December 31, 2018 As of December 31, 2017 (in thousands) Credit facility balance (1) $ — $ — $ — Letters of credit (2) — 200 200 Available borrowing capacity 1,000,000 999,800 924,800 Total aggregate lender commitment amount $ 1,000,000 $ 1,000,000 $ 925,000 ____________________________________________ (1) Unamortized deferred financing costs attributable to the credit facility are presented as a component of other noncurrent assets on the accompanying balance sheets and totaled $6.4 million and $3.1 million as of December 31, 2018 , and 2017 , 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 During the third quarter of 2018, the Company redeemed its 2021 Senior Notes, repurchased or redeemed all of its 2023 Senior Notes, repurchased a portion of its 2022 Senior Notes, and issued its 2027 Senior Notes. As of December 31, 2018 , the Company’s Senior Notes consisted of 6.125% Senior Notes due 2022, 5.0% Senior Notes due 2024 (“2024 Senior Notes”), 5.625% Senior Notes due 2025 (“2025 Senior Notes”), 6.75% Senior Notes due 2026 (“2026 Senior Notes”), and 6.625% Senior Notes due 2027 (collectively referred to as “Senior Notes”). Please refer to the discussion below for additional information. The Senior Notes, net of unamortized deferred financing costs line on the accompanying balance sheets as of December 31, 2018 , and 2017 , consisted of the following: As of December 31, 2018 2017 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) 6.50% Senior Notes due 2021 $ — $ — $ — $ 344,611 $ 2,656 $ 341,955 6.125% Senior Notes due 2022 476,796 3,921 472,875 561,796 5,800 555,996 6.50% Senior Notes due 2023 — — — 394,985 3,707 391,278 5.0% Senior Notes due 2024 500,000 4,688 495,312 500,000 5,610 494,390 5.625% Senior Notes due 2025 500,000 5,808 494,192 500,000 6,714 493,286 6.75% Senior Notes due 2026 500,000 6,407 493,593 500,000 7,242 492,758 6.625% Senior Notes due 2027 500,000 7,533 492,467 — — — Total $ 2,476,796 $ 28,357 $ 2,448,439 $ 2,801,392 $ 31,729 $ 2,769,663 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, 2018 , 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. 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 retire $395.0 million of its 2023 Senior Notes and $85.0 million of its 2022 Senior Notes through the Tender Offer and subsequent redemption of the remaining 2023 Senior Notes not repurchased as part of the Tender Offer (“2023 Senior Notes Redemption”). Total consideration paid, including accrued interest, for the retirement of the 2023 Senior Notes and the 2022 Senior Notes was $497.8 million . As a result of the Tender Offer and the 2023 Senior Notes Redemption, the Company recorded a loss on extinguishment of debt of $16.9 million for the year ended December 31, 2018 . This amount included $12.9 million of premiums paid for the Tender Offer and 2023 Senior Notes Redemption and $4.0 million of accelerated unamortized deferred financing costs. During the first quarter of 2016, the Company repurchased in open market transactions a total of $46.3 million in aggregate principal amount of certain of its 6.50% Senior Notes due 2021, 6.125% Senior Notes due 2022, and 6.50% Senior Notes due 2023 for a settlement amount of $29.9 million , excluding interest, which resulted in a net gain on extinguishment of debt of approximately $15.7 million . This amount includes a gain of $16.4 million associated with the discount realized upon repurchase, which was partially offset by approximately $700,000 related to the acceleration of unamortized deferred financing costs. 2021 Senior Notes. On June 15, 2018 , the Company called for redemption all of the $344.6 million principal outstanding on its 2021 Senior Notes at a redemption price of 102.167% of the principal amount, plus accrued and unpaid interest on the principal amount of the 2021 Senior Notes redeemed (“2021 Senior Notes Redemption”). On July 16, 2018, the Company completed the 2021 Senior Notes Redemption, which resulted in the payment of total cash consideration, including accrued interest, of $355.9 million . The Company recorded a loss on extinguishment of debt of $9.8 million for the year ended December 31, 2018. This amount included $7.5 million associated with the premium paid for the 2021 Senior Notes Redemption and $2.3 million of accelerated unamortized deferred financing costs. 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 Notes. During the first quarter of 2016, the Company repurchased $38.2 million in aggregate principal amount of its 2022 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 . 2023 Senior Notes. During the first quarter of 2016, the Company repurchased $5.0 million in aggregate principal amount of its 2023 Notes for a settlement amount of $3.3 million . During the third quarter of 2018, through the Tender Offer and 2023 Senior Notes Redemption discussed above, the Company redeemed the remaining outstanding $395.0 million in aggregate principal amount of its 2023 Senior Notes for total consideration, including accrued interest, of $408.3 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 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 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 Notes. The net proceeds were used to partially fund the Rock Oil Acquisition that closed during the fourth quarter of 2016. 2027 Senior Notes. On August 20, 2018 , the Company issued $500.0 million in aggregate principal amount of 6.625% Senior Notes due 2027. The 2027 Senior Notes were issued at par and 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. The net proceeds were used to fund the Tender Offer and 2023 Senior Notes Redemption discussed above. 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, 2018 , 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, 2018 , 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 $10.5 million , $9.9 million , and $3.7 million for the years ended December 31, 2018 , 2017 , and 2016, respectively. The net carrying amount of the liability component of the Senior Convertible Notes, as reflected on the accompanying balance sheets, consisted of the following as of December 31, 2018 and 2017 : As of December 31, 2018 2017 (in thousands) Principal amount of Senior Convertible Notes $ 172,500 $ 172,500 Unamortized debt discount (22,313 ) (30,183 ) Unamortized deferred financing costs (2,293 ) (3,210 ) Net carrying amount $ 147,894 $ 139,107 The net carrying amount of the equity component of the Senior Convertible Notes recorded in additional paid-in capital on the accompanying balance sheets consisted of the following as of December 31, 2018 and 2017 : As of December 31, 2018 2017 (in thousands) Equity component due to allocation of proceeds to equity $ 40,217 $ 40,217 Related issuance costs (1,375 ) (1,375 ) Deferred tax liability (5,267 ) (5,267 ) Net carrying amount $ 33,575 $ 33,575 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, 2018 , 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 evaluated the capped call transactions under authoritative accounting guidance and determined that they should be accounted for as separate transactions and classified as equity instruments with no recurring fair value measurement recorded. Capitalized Interest Capitalized interest costs for the Company for the years ended December 31, 2018 , 2017 , and 2016 , were $20.6 million , $12.6 million , and $17.0 million , respectively.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2018
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 $86.9 million , gathering, processing, transportation throughput, and delivery commitments of $287.8 million , office leases, including maintenance, of $35.5 million , fixed price contracts to purchase electricity of $29.0 million , and other miscellaneous contracts and leases of $18.3 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) 2019 $ 132,502 2020 103,169 2021 88,785 2022 70,741 2023 37,334 Thereafter 24,931 Total $ 457,462 Drilling Rig and Completion Service Contracts The Company has several drilling rig and completion service contracts in place to facilitate drilling and completion plans. Early termination of these contracts as of December 31, 2018 , would have resulted in termination penalties of $45.9 million , which would be in lieu of paying the remaining commitments of $86.9 million included in the table above. For the year ended December 31, 2016 , the Company incurred $8.7 million of expenses related to the early termination of drilling rig contracts or fees incurred for rigs placed on standby, which are recorded in the other operating expenses line item in the accompanying statements of operations. No material expenses related to early termination or standby fees were recorded by the Company for the years ended December 31, 2018 , or 2017. 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, 2018 , the Company has commitments to deliver a minimum of 29 MMBbl of oil, 595 Bcf of gas, and 21 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, 2018 , if the Company fails to deliver any product, as applicable, the aggregate undiscounted deficiency payments total approximately $287.8 million . This amount does not include deficiency payment estimates associated with approximately 18.6 MMBbl of future oil delivery commitments where we 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. As of the filing of this report, the Company does not expect to incur any material shortfalls with regard to these commitments. Drilling and Completion Commitments In December 2018, the Company entered into an agreement that included minimum drilling and completion requirements for certain existing leases. If these minimum requirements are not satisfied by March 31, 2020, the Company would be required to pay penalties based on the difference between actual development progress and the minimum development requirements. The penalties could range from zero to a maximum of $60.0 million , with the maximum exposure assuming no development activity occurred prior to March 31, 2020. As of the filing of this report, the Company is committed to and expects to meet the minimum development requirements set forth in the agreement. Office Leases The Company leases office space under various operating leases with terms extending as far as 2026 . Rent expense, net of sublease income, for the years ended December 31, 2018 , 2017 , and 2016 , was $4.5 million , $4.8 million , and $5.2 million , respectively. During the third quarter of 2015, the Company closed its office in Tulsa, Oklahoma and has subleased the space through the expiration of the lease. In the fourth quarter of 2018, the Company paid $1.3 million to the lessor to terminate the lease effective September 2019. The Company closed its office in Billings, Montana in November 2016 and paid $3.2 million to the lessor to terminate the lease. These lease termination fees are not reflected in the rent expense amounts above. 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, 2018
Compensation Related Costs [Abstract]
Compensation Plans	Note 7 – Compensation Plans Equity Incentive Compensation Plan There are several components to the Company’s Equity Plan that are described in this section. Various types of equity awards have been granted by the Company in different periods. As of December 31, 2018 , approximately 5.9 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. 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. PSUs issued in 2017 and 2016, which the Company has determined to be equity awards, are subject to a combination of market and service vesting criteria. These awards are based on annualized Total Shareholder Return (“TSR”) for the performance period and the relative performance of the Company’s TSR compared with the annualized TSR of the Company’s peer group for the performance period. The fair value of these PSUs is measured at the grant date using the GBM Model. Compensation expense for these market-based PSUs is recognized on a straight-line basis within general and administrative expense and exploration expense over the vesting periods of the respective awards. Beginning in 2018, PSUs awarded to employees include both a market criteria component and a performance criteria component. For the performance criteria component, the grant-date fair value is equal to the Company's stock price on the grant date, and compensation expense for the performance-based PSUs will be recorded over the vesting period of the award. The value being recorded will be evaluated on a quarterly basis and may be adjusted as the number of units expected to vest increases or decreases. For awards granted in 2018, the Company uses relative debt adjusted per share cash flow growth (“DACFG”) compared with the DACFG, as calculated by the Company, of its peer group as the performance criteria that is evaluated over the three-year performance period for these PSUs. 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 $10.3 million , $9.7 million , and $11.0 million for the years ended December 31, 2018 , 2017 , and 2016 , respectively. As of December 31, 2018 , there was $19.0 million of total unrecognized expense related to PSUs, which is being amortized through 2021 . A summary of the status and activity of non-vested PSUs is presented in the following table: For the Years Ended December 31, 2018 2017 2016 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 1,533,491 $ 22.97 828,923 $ 43.25 626,328 $ 61.81 Granted 572,924 $ 24.45 977,731 $ 15.86 447,971 $ 26.56 Vested (233,102 ) $ 44.25 (94,338 ) $ 85.85 (130,353 ) $ 64.17 Forfeited (162,054 ) $ 21.79 (178,825 ) $ 44.99 (115,023 ) $ 55.59 Non-vested at end of year 1,711,259 $ 20.68 1,533,491 $ 22.97 828,923 $ 43.25 ____________________________________________ (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 2018 , 2017 , and 2016 was $14.0 million , $15.5 million , and $11.9 million , respectively. The PSUs fully vest on the third anniversary of the date of the grant; however, 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. During the year ended December 31, 2018 , the Company granted 572,924 PSUs to eligible employees (“2018 PSU Grant”). As outlined in the award agreement for the 2018 PSU Grant, performance measurements affecting vesting are based on a combination of relative performance of the Company’s annualized TSR compared with the annualized TSR of the Company’s peer group over the three-year performance period, and relative performance of the Company’s DACFG compared with its peer group DACFG over the three-year performance period. In addition to these performance measures, the award agreement for the 2018 PSU Grant also stipulates 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 DACFG performance relative to its peer group. During the years ended December 31, 2018 and 2017, PSUs that were granted in 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. A summary of the shares of common stock issued to settle PSUs for the year ended December 31, 2016 , is presented in the table below: For the Year Ended December 31, 2016 Shares of common stock issued to settle PSUs (1) 44,870 Less: shares of common stock withheld for income and payroll taxes (14,809 ) Net shares of common stock issued 30,061 Multiplier earned 0.2 ____________________________________________ (1) During the year ended December 31, 2016 , the Company issued shares of common stock to settle PSUs that related to awards granted in 2013. 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 PSUs that vested during the years ended December 31, 2018 , 2017 , and 2016 was $10.3 million , $8.1 million , and $8.4 million , respectively. Employee Restricted Stock Units The Company grants RSUs to eligible persons as part of its long-term 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. 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, 2018 , 2017 , and 2016 , was $10.8 million , $10.3 million , and $11.9 million , respectively. As of December 31, 2018 , there was $20.0 million of total unrecognized compensation expense related to non-vested RSU awards, which is being amortized through 2021 . 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. 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, 2018 2017 2016 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 1,244,262 $ 20.25 604,116 $ 37.39 543,737 $ 55.01 Granted 583,552 $ 25.77 1,020,780 $ 16.64 417,065 $ 28.08 Vested (407,529 ) $ 24.30 (246,025 ) $ 43.99 (241,363 ) $ 58.06 Forfeited (177,122 ) $ 17.26 (134,609 ) $ 26.38 (115,323 ) $ 43.52 Non-vested at end of year 1,243,163 $ 21.50 1,244,262 $ 20.25 604,116 $ 37.39 The fair value of RSUs granted to eligible employees in 2018 , 2017 , and 2016 was $15.0 million , $17.0 million , and $11.7 million , respectively. The RSUs granted generally vest one-third of the total grant on each anniversary of the grant dates, unless the employee is retirement eligible, in which case the RSUs generally 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. 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, 2018 2017 2016 Shares of common stock issued to settle RSUs (1) 407,529 246,025 241,363 Less: shares of common stock withheld for income and payroll taxes (115,784 ) (74,747 ) (72,181 ) Net shares of common stock issued 291,745 171,278 169,182 ____________________________________________ (1) During the years ended December 31, 2018 , 2017 , and 2016 , 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, 2018 , 2017 , and 2016 was $9.9 million , $10.8 million , and $14.0 million , respectively. Director Shares In 2018 , 2017 , and 2016 , the Company issued 63,741 , 71,573 , and 53,473 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, 2018 , 2017 , and 2016 , the Company recorded $1.7 million , $1.6 million , and $2.0 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 1.6 million shares of its common stock available for issuance under the ESPP as of December 31, 2018 . There were 199,464 , 186,665 , and 218,135 shares issued under the ESPP in 2018 , 2017 , and 2016 , respectively. Total proceeds to the Company for the issuance of these shares were $3.2 million , $2.6 million , and $4.2 million for the years ended December 31, 2018 , 2017 , and 2016 , respectively. 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, 2018 2017 2016 Risk free interest rate 1.8 % 0.9 % 0.4 % Dividend yield 0.4 % 0.5 % 0.4 % Volatility factor of the expected market price of the Company’s common stock 55.9 % 62.5 % 95.0 % Expected life (in years) 0.5 0.5 0.5 The Company expensed $1.1 million , $1.0 million , and $2.0 million for the years ended December 31, 2018 , 2017 , and 2016 , respectively, based on the estimated fair value of the ESPP grants. 401(k) Plan The Company has a defined contribution plan (the “401(k) Plan”) that is subject to the Employee Retirement Income Security Act of 1974. The 401(k) Plan allows eligible employees to contribute a maximum of 60 percent of their base salaries up to the contribution limits established under the IRC. For employees hired before December 31, 2014, the Company matches 100 percent of each employee’s contribution in cash on a dollar for dollar basis, up to six percent of the employee’s base salary and performance bonus, and may make additional contributions at its discretion. The Company matches 150 percent of contributions made by employees hired after December 31, 2014, up to six percent of the employee’s base salary and performance bonus in lieu of pension plan benefits, and may make additional contributions at its discretion. Please refer to Note 8 – Pension Benefits for additional discussion of pension benefits. The Company’s matching contributions to the 401(k) Plan were $4.9 million , $4.5 million , and $5.4 million for the years ended December 31, 2018 , 2017 , and 2016 , respectively. Net Profits Plan Under the Company’s Net Profits Plan, all oil and gas wells that were completed or acquired during each year were designated within a specific pool with key employees designated as participants that became entitled to payments under the Net Profits Plan after the Company has received net cash flows returning 100 percent of all costs associated with that pool. Thereafter, 10 percent of future net cash flows generated by the pool are allocated among the participants and distributed at least annually. The portion of net cash flows from the pool to be allocated among the participants increases to 20 percent after the Company has recovered 200 percent of the total costs for the pool, including payments made under the Net Profits Plan at the 10 percent level. In December 2007, the Board of Directors discontinued the creation of new pools under the Net Profits Plan. As a result, the 2007 pool was the last Net Profits Plan pool established by the Company. The following table presents cash payments made or accrued under the Net Profits Plan related to periodic operations, of which the majority is recorded as general and administrative expense, and cash payments made or accrued as a result of divestitures of properties subject to the Net Profits Plan, which are recorded as a reduction to the net gain (loss) on divestiture activity line item in the accompanying statements of operations. For the Years Ended December 31, 2018 2017 2016 (in thousands) Cash payments made or accrued related to operations $ 63 $ (54 ) $ 6,608 Cash payments made or accrued related to divestitures — 2,753 24,349 Total net settlements $ 63 $ 2,699 $ 30,957

Pension Benefits

Pension Benefits	12 Months Ended
	Dec. 31, 2018
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 it 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 to other comprehensive income (loss), net of tax, in the accompanying statements of comprehensive income. 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, 2018 2017 (in thousands) Change in benefit obligation: Projected benefit obligation at beginning of year $ 71,937 $ 69,659 Service cost 6,730 6,638 Interest cost 2,622 2,689 Actuarial (gain) loss (7,155 ) 3,708 Benefits paid (8,048 ) (10,757 ) Projected benefit obligation at end of year 66,086 71,937 Change in plan assets: Fair value of plan assets at beginning of year 30,978 31,731 Actual return on plan assets (964 ) 2,956 Employer contribution 8,134 7,048 Benefits paid (8,048 ) (10,757 ) Fair value of plan assets at end of year 30,100 30,978 Funded status at end of year $ (35,986 ) $ (40,959 ) The Company’s underfunded status for the Pension Plans as of December 31, 2018 , and 2017 , was $36.0 million and $41.0 million , respectively, and is recognized in the accompanying balance sheets as a portion of other noncurrent liabilities. 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, 2018 2017 (in thousands) Projected benefit obligation $ 66,086 $ 71,937 Accumulated benefit obligation $ 52,368 $ 56,045 Less: fair value of plan assets (30,100 ) (30,978 ) Underfunded accumulated benefit obligation $ 22,268 $ 25,067 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 accumulated other comprehensive loss as of December 31, 2018 , and 2017 , were as follows: As of December 31, 2018 2017 (in thousands) Unrecognized actuarial losses $ 15,741 $ 21,397 Unrecognized prior service costs 48 66 Accumulated other comprehensive loss $ 15,789 $ 21,463 The pension liability adjustments recognized in other comprehensive income (loss) during 2018 , 2017 , and 2016 , were as follows: For the Years Ended December 31, 2018 2017 2016 (in thousands) Net actuarial gain (loss) $ 4,329 $ (2,995 ) $ (3,322 ) Amortization of prior service cost 18 17 16 Amortization of net actuarial loss 1,327 1,297 1,582 Settlements — 3,009 — Total pension liability adjustment, pre-tax 5,674 1,328 (1,724 ) Tax (expense) benefit (4,265 ) (561 ) 570 Cumulative effect of accounting change (1) 2,969 — — Total pension liability adjustment, net $ 4,378 $ 767 $ (1,154 ) _________________________________________ (1) 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, 2018 2017 2016 (in thousands) Components of net periodic benefit cost: Service cost $ 6,730 $ 6,638 $ 8,200 Interest cost 2,622 2,689 2,908 Expected return on plan assets that reduces periodic pension benefit cost (1,862 ) (2,244 ) (2,235 ) Amortization of prior service cost 18 17 16 Amortization of net actuarial loss 1,327 1,297 1,582 Settlements — 3,009 — Net periodic benefit cost $ 8,835 $ 11,406 $ 10,471 Pension Plan Assumptions The weighted-average assumptions used to measure the Company’s projected benefit obligation are as follows: As of December 31, 2018 2017 Projected benefit obligation: Discount rate 4.4% 3.8% Rate of compensation increase 6.2% 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, 2018 2017 2016 Net periodic benefit cost: Discount rate 3.8% 4.2% 4.7% Expected return on plan assets (1) 5.5% 6.5% 7.5% 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 2019 2018 2017 Equity securities 35.0 % 31.8 % 38.4 % Fixed income securities 43.0 % 41.3 % 39.8 % Other securities 22.0 % 26.9 % 21.8 % 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 5.5 percent , 6.5 percent , and 7.5 percent was used to calculate the Company’s net periodic pension cost under the Qualified Pension Plan for the years ended December 31, 2018 , 2017 , and 2016 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. We evaluate 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, 2018 , and 2017 , 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, 2018 Cash — % $ — $ — $ — $ — 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: High-yield bonds (4) — % — — — — Core fixed income (5) 34.4 % 10,342 10,342 — — Floating rate corporate loans (6) 6.9 % 2,078 2,078 — — Total fixed income securities 41.3 % 12,420 12,420 — — Other securities: Commodities (7) — % — — — — Real estate (8) 6.0 % 1,820 — — 1,820 Collective investment trusts (9) 3.1 % 934 — 934 — Hedge fund (10) 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 As of December 31, 2017 Cash — % $ — $ — $ — $ — Equity securities: Domestic (2) 22.2 % 6,865 4,805 2,060 — International (3) 16.2 % 5,032 3,806 1,226 — Total equity securities 38.4 % 11,897 8,611 3,286 — Fixed income securities: High-yield bonds (4) 2.8 % 876 876 — — Core fixed income (5) 28.6 % 8,842 8,842 — — Floating rate corporate loans (6) 8.4 % 2,607 2,607 — — Total fixed income securities 39.8 % 12,325 12,325 — — Other securities: Commodities (7) 1.9 % 588 588 — — Real estate (8) 5.6 % 1,735 — — 1,735 Collective investment trusts (9) 3.1 % 959 — 959 — Hedge fund (10) 11.2 % 3,474 — — 3,474 Total other securities 21.8 % 6,756 588 959 5,209 Total investments 100.0 % $ 30,978 $ 21,524 $ 4,245 $ 5,209 ____________________________________________ (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) High-yield bonds consist of non-investment grade fixed income securities. The investment objective is to obtain high current income. Due to the increased level of default risk, security selection focuses on credit-risk analysis. (5) 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. (6) 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. (7) Investments with exposure to commodity price movements, primarily through the use of futures, swaps, and other commodity-linked securities. (8) 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. (9) 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. (10) 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, 2017 $ 5,214 Purchases 300 Realized gain on assets 130 Unrealized gain on assets 120 Disposition (555 ) Balance at December 31, 2017 $ 5,209 Purchases — Realized gain on assets 191 Unrealized gain on assets 152 Disposition (45 ) Balance at December 31, 2018 $ 5,507 Contributions The Company contributed $8.1 million , $7.0 million , and $11.0 million to the Pension Plans for the years ended December 31, 2018 , 2017 , and 2016 , respectively. The Company expects to make a $4.0 million contribution to the Pension Plans in 2019 . Benefit Payments The Pension Plans made actual benefit payments of $8.0 million , $10.8 million , and $6.7 million in the years ended December 31, 2018 , 2017 , and 2016 , respectively. Expected benefit payments over the next 10 years are as follows: Years Ending December 31, (in thousands) 2019 $ 5,429 2020 $ 5,066 2021 $ 4,913 2022 $ 5,715 2023 $ 7,693 2024 through 2028 $ 30,400

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2018
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 adjusted net income or loss 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, 2018 , and 2017 , and for the portion of the year ended December 31, 2016 , during which the Senior Convertible Notes were outstanding; 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, 2017 , and 2016 , 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 dilutive and anti-dilutive securities for the years presented: For the Years Ended December 31, 2018 2017 2016 (in thousands) Dilutive 1,590 — — Anti-dilutive — 264 280 The following table sets forth the calculations of basic and diluted net income (loss) per common share: For the Years Ended December 31, 2018 2017 2016 (in thousands, except per share data) Net income (loss) $ 508,407 $ (160,843 ) $ (757,744 ) Basic weighted-average common shares outstanding 111,912 111,428 76,568 Dilutive effect of non-vested RSUs and contingent PSUs 1,590 — — Dilutive effect of Senior Convertible Notes — — — Diluted weighted-average common shares outstanding 113,502 111,428 76,568 Basic net income (loss) per common share $ 4.54 $ (1.44 ) $ (9.90 ) Diluted net income (loss) per common share $ 4.48 $ (1.44 ) $ (9.90 )

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2018
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, 2018 , 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 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, 2018 , 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 2019 826 $ 60.16 Second quarter 2019 575 $ 55.52 Third quarter 2019 1,217 $ 61.41 Fourth quarter 2019 1,115 $ 59.97 2020 2,491 $ 65.68 Total 6,224 Oil Collars Contract Period NYMEX WTI Volumes Weighted-Average Floor Price Weighted-Average Ceiling Price (MBbl) (per Bbl) (per Bbl) First quarter 2019 2,503 $ 51.66 $ 64.32 Second quarter 2019 2,802 $ 52.18 $ 64.61 Third quarter 2019 2,364 $ 49.07 $ 62.67 Fourth quarter 2019 2,386 $ 49.08 $ 62.65 2020 1,165 $ 55.00 $ 66.47 Total 11,220 Oil Basis Swaps Contract Period WTI Midland-NYMEX WTI Volumes Weighted-Average Contract Price (1) NYMEX WTI-ICE Brent Volumes Weighted-Average (2) (MBbl) (per Bbl) (MBbl) (per Bbl) First quarter 2019 2,433 $ (4.44 ) — $ — Second quarter 2019 2,571 $ (4.49 ) — $ — Third quarter 2019 3,291 $ (2.86 ) — $ — Fourth quarter 2019 3,338 $ (2.87 ) — $ — 2020 11,601 $ (1.03 ) 2,750 $ (8.03 ) 2021 — $ — 3,650 $ (7.86 ) 2022 — $ — 3,650 $ (7.78 ) Total 23,234 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 2019 19,805 $ 2.99 — $ — Second quarter 2019 10,439 $ 2.82 2,803 $ 0.69 Third quarter 2019 12,531 $ 2.82 2,984 $ 1.28 Fourth quarter 2019 14,433 $ 2.88 2,962 $ 1.75 2020 9,123 $ 2.98 2,060 $ 2.20 Total (1) 66,331 10,809 ____________________________________________ (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, 2018, total volumes for gas swaps are comprised of 86 percent IF HSC , four percent IF Waha , and 10 percent GD Waha . Gas Collars Contract Period IF HSC Volumes Weighted- Average Floor Price Weighted- Average Ceiling Price (BBtu) (per MMBtu) (per MMBtu) First quarter 2019 — $ — $ — Second quarter 2019 4,358 $ 2.50 $ 2.83 Third quarter 2019 5,066 $ 2.50 $ 2.83 Fourth quarter 2019 4,818 $ 2.50 $ 2.83 Total 14,242 NGL Swaps OPIS Ethane Purity Mont Belvieu OPIS Propane Mont Belvieu Non-TET OPIS Normal Butane Mont Belvieu Non-TET OPIS Isobutane Mont Belvieu Non-TET OPIS Natural Gasoline Mont Belvieu Non-TET Contract Period Volumes Weighted-Average Contract Price Volumes Weighted-Average Volumes Weighted-Average Volumes Weighted-Average Volumes Weighted-Average (MBbl) (per Bbl) (MBbl) (per Bbl) (MBbl) (per Bbl) (MBbl) (per Bbl) (MBbl) (per Bbl) First quarter 2019 853 $ 12.25 540 $ 28.72 38 $ 35.64 29 $ 35.70 48 $ 50.93 Second quarter 2019 877 $ 12.29 561 $ 31.32 38 $ 35.64 29 $ 35.70 49 $ 50.93 Third quarter 2019 907 $ 12.34 637 $ 31.29 39 $ 35.64 30 $ 35.70 50 $ 50.93 Fourth quarter 2019 896 $ 12.36 651 $ 31.64 39 $ 35.64 29 $ 35.70 50 $ 50.93 2020 539 $ 11.13 — $ — — $ — — $ — — $ — Total 4,072 2,389 154 117 197 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. The Company does not designate its derivative commodity contracts as hedging instruments. The fair value of the derivative commodity contracts was a net asset of $158.3 million at December 31, 2018 , and net liability of $139.4 million at December 31, 2017 . The following tables detail the fair value of derivatives recorded in the accompanying balance sheets, by category: As of December 31, 2018 Derivative Assets Derivative Liabilities Balance Sheet Classification Fair Value Balance Sheet Classification Fair Value (in thousands) Commodity contracts Current assets $ 175,130 Current liabilities $ 62,853 Commodity contracts Noncurrent assets 58,499 Noncurrent liabilities 12,496 Total commodity contracts $ 233,629 $ 75,349 As of December 31, 2017 Derivative Assets Derivative Liabilities Balance Sheet Classification Fair Value Balance Sheet Classification Fair Value (in thousands) Commodity contracts Current assets $ 64,266 Current liabilities $ 172,582 Commodity contracts Noncurrent assets 40,362 Noncurrent liabilities 71,402 Total commodity contracts $ 104,628 $ 243,984 Offsetting of Derivative Assets and Liabilities As of December 31, 2018 , and 2017 , 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 derivative contracts: Derivative Assets Derivative Liabilities As of December 31, As of December 31, Offsetting of Derivative Assets and Liabilities 2018 2017 2018 2017 (in thousands) Gross amounts presented in the accompanying balance sheets $ 233,629 $ 104,628 $ (75,349 ) $ (243,984 ) Amounts not offset in the accompanying balance sheets (56,041 ) (100,035 ) 56,041 100,035 Net amounts $ 177,588 $ 4,593 $ (19,308 ) $ (143,949 ) The Company recognizes all gains and losses from changes in commodity derivative fair values immediately in earnings rather than deferring any such amounts in accumulated other comprehensive income (loss). The Company had no derivatives designated as hedging instruments for the years ended December 31, 2018 , 2017 , and 2016 . 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 components of the net derivative (gain) loss line item presented in the accompanying statements of operations: For the Years Ended December 31, 2018 2017 2016 (in thousands) Derivative settlement (gain) loss: Oil contracts $ 68,860 $ 31,176 $ (243,102 ) Gas contracts 13,029 (87,857 ) (94,936 ) NGL contracts 53,914 35,447 8,560 Total derivative settlement (gain) loss $ 135,803 $ (21,234 ) $ (329,478 ) Net derivative (gain) loss: Oil contracts $ (192,002 ) $ 71,502 $ 85,370 Gas contracts 35,411 (76,315 ) 81,060 NGL contracts (5,241 ) 31,227 84,203 Total net derivative (gain) loss $ (161,832 ) $ 26,414 $ 250,633 Credit Related Contingent Features As of December 31, 2018 , 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 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, 2018
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, 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. 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, 2017 : Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 104,628 $ — Liabilities: Derivatives (1) $ — $ 243,984 $ — ____________________________________________ (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. Proved and Unproved 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. There were no material proved oil and gas properties recorded at fair value on the accompanying balance sheets as of December 31, 2018 , or December 31, 2017 . The Company recorded impairment of proved properties expense of $354.6 million for the year ended December 31, 2016 , related primarily to the decline in expected reserve cash flows from the Company’s outside-operated Eagle Ford shale assets driven by commodity price declines during the first quarter of 2016, and downward performance reserve revisions in the fourth quarter of 2016 for the Company’s Powder River Basin assets. 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. The following table presents abandonment and impairment of unproved properties expense recorded for the periods presented: For the Years Ended December 31, 2018 2017 2016 (in millions) Abandonment and impairment of unproved properties $ 49.9 $ 12.3 $ 80.4 Abandonment and impairment of unproved properties expense recorded during the years ended December 31, 2018 , and 2017 , related primarily 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. During the year ended December 31, 2016 , abandonment and impairment expense related primarily to a decrease in the fair value of the Company’s unproved Powder River Basin properties due to downward performance reserve revisions and lower market prices based on third-party acreage transactions. 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, 2018 , or 2017 , 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, 2018 2017 Principal Amount Fair Value Principal Amount Fair Value (in thousands) 6.50% Senior Notes due 2021 $ — $ — $ 344,611 $ 351,682 6.125% Senior Notes due 2022 $ 476,796 $ 452,336 $ 561,796 $ 571,627 6.50% Senior Notes due 2023 $ — $ — $ 394,985 $ 403,434 5.0% Senior Notes due 2024 $ 500,000 $ 439,265 $ 500,000 $ 483,440 5.625% Senior Notes due 2025 $ 500,000 $ 436,460 $ 500,000 $ 494,355 6.75% Senior Notes due 2026 $ 500,000 $ 448,305 $ 500,000 $ 516,350 6.625% Senior Notes due 2027 $ 500,000 $ 442,500 $ — $ — 1.50% Senior Convertible Notes due 2021 $ 172,500 $ 158,614 $ 172,500 $ 168,291 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, 2018
Suspended Well Costs [Abstract]
Suspended Well Costs [Text Block]	Note 12 – Suspended Well Costs The following table reflects the net changes in capitalized exploratory well costs during 2018 , 2017 , and 2016 . 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, 2018 2017 2016 (in thousands) Beginning balance $ 49,446 $ 19,846 $ 11,952 Additions to capitalized exploratory well costs pending the determination of proved reserves 11,197 49,446 19,846 Divestitures (109 ) — — Reclassifications to wells, facilities, and equipment based on the determination of proved reserves (49,337 ) (19,846 ) (11,952 ) Capitalized exploratory well costs charged to expense — — — Ending balance $ 11,197 $ 49,446 $ 19,846 As of December 31, 2018 , there were no exploratory well costs that were capitalized for more than one year.

Equity

Equity	12 Months Ended
	Dec. 31, 2018
Equity [Abstract]
Equity [Text Block]	Note 13 – Equity On August 12, 2016 , the Company completed an underwritten public offering of approximately 18.4 million shares of its common stock at an offering price of $30.00 per share. Net proceeds from the offering totaled $530.9 million , after deducting underwriting discounts and commissions and offering expenses, which the Company used to partially fund the Rock Oil Acquisition that closed during the fourth quarter of 2016. On December 7, 2016 , the Company completed an underwritten public offering of approximately 10.9 million shares of its common stock at an offering price of $38.25 per share. Net proceeds from the offering totaled $403.2 million , after deducting underwriting discounts and commissions and offering expenses, which the Company used to partially fund the QStar Acquisition that also closed during the fourth quarter of 2016. The Company’s 2016 public equity offerings were made pursuant to an effective shelf registration statement on Form S-3 filed with the SEC. On December 21, 2016, and as part of the QStar Acquisition, the Company issued approximately 13.4 million shares of its common stock valued at approximately $437.2 million in a private placement to the sellers as partial consideration for the acquired properties. Please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions for additional discussion. The Company did not conduct any equity offerings during 2018 or 2017.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2018
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, 2018 2017 (in thousands) Beginning asset retirement obligations $ 114,470 $ 123,307 Liabilities incurred (1) 4,054 7,588 Liabilities settled (2) (33,024 ) (30,432 ) Accretion expense 4,438 5,988 Revision to estimated cash flows 4,256 8,019 Ending asset retirement obligations (3)(4) $ 94,194 $ 114,470 ____________________________________________ (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) Balance as of December 31, 2017 , included $11.4 million of asset retirement obligations associated with oil and gas properties held for sale. (4) Balances as of December 31, 2018 , and 2017 , included $2.3 million and $75,000 , 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, 2018
Accounts Receivable and Accounts Payable and Accrued Expenses [Abstract]
Accounts Receivable and Accounts Payable and Accrued Expenses [Text Block]	Note 15 – Accounts Receivable and Accounts Payable and Accrued Expenses Accounts receivable are comprised of the following accruals: As of December 31, 2018 2017 (in thousands) Oil, gas, and NGL production revenue $ 107,230 $ 96,610 Amounts due from joint interest owners 31,497 56,929 State severance tax refunds 4,415 2,276 Derivative settlements 9,475 99 Other 14,919 4,240 Total accounts receivable $ 167,536 $ 160,154 Accounts payable and accrued expenses are comprised of the following accruals: As of December 31, 2018 2017 (in thousands) Drilling and lease operating cost accruals $ 139,711 $ 126,500 Trade accounts payable 56,047 77,573 Revenue and severance tax payable 94,806 60,328 Property taxes 18,694 13,222 Compensation 31,486 39,471 Derivative settlements 1,287 12,644 Interest 40,840 45,057 Other 20,328 11,835 Total accounts payable and accrued expenses $ 403,199 $ 386,630

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2018
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, 2018 , 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 [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 and Restricted Cash [Policy Text Block]	Cash and Cash Equivalents and Restricted Cash 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. Restricted cash includes cash that is contractually restricted for its use through an agreement with a non-related party. The Company includes restricted cash in other noncurrent assets on the accompanying balance sheets.
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.
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 Company had the following major customers and sales to entities under common ownership, which 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, 2018 2017 2016 Major customer #1 (1) 18 % 6 % — % Major customer #2 (1) 10 % 10 % 5 % Group #1 of entities under common ownership (2) 18 % 17 % 15 % Group #2 of entities under common ownership (2) 12 % 8 % 8 % ____________________________________________ (1) These major customers are purchasers of a portion of the Company’s production from its Permian region. (2) In the aggregate, these groups of entities under common ownership represented 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 represented more than 10 percent of the Company’s total oil, gas, and NGL production revenue. The Company’s policy is to use the commodity affiliates of the lenders under its Credit Agreement as its derivative counterparties, and each counterparty must have investment grade senior unsecured debt ratings. Each of the Company’s 10 derivative counterparties meet both of these requirements as of the filing of this report. 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]	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 with a common geological structure) 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 Drilling Costs [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 cash flows from investing activities 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.
Assets Held For Sale [Policy Text Block]	Assets Held for Sale Any properties held for sale as of the balance sheet date have been classified as assets held for sale and are separately presented on the accompanying balance sheets at the lower of carrying value or fair value less the estimated cost to sell. Properties classified as held for sale, including any corresponding asset retirement obligation liability, are valued using a market approach, based on an estimated net selling price, as evidenced by the most current bid prices received from third-parties, if available. If an estimated selling price is not available, the Company utilizes the various valuation techniques discussed above.
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 proved oil and gas properties 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 operating section of the Company’s 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.
Derivative Financial Instruments [PolicyText Block]	Derivative Financial Instruments The Company periodically enters into derivative commodity instruments to reduce its exposure to pricing volatility for a portion of its expected future oil, natural gas, and NGL production. These instruments typically include commodity price swaps and costless collars, as well as, basis differential swaps. Derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as assets and/or liabilities. The Company does not designate its derivative instruments to qualify for hedge accounting. 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 cash flows from operations in the accompanying consolidated statement of cash flows.
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 control of the product transfers to the customer, which differs depending on the contractual terms of each of the Company’s arrangements. 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.
Share-based Compensation [Policy Text Block]	Stock-Based Compensation At December 31, 2018 , the Company had stock-based employee compensation plans that included restricted stock units (“RSUs”) and performance share units (“PSUs”) issued to employees and RSUs and restricted stock issued to non-employee directors, as well as 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 general and administrative and exploration expense 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.
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 restricted stock units, contingent Performance Share Units, and Senior Convertible Notes.
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).
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 zero balance under its credit facility as of December 31, 2018 , and 2017 . The Company’s Senior Notes and Senior Convertible Notes are recorded at cost, net of any unamortized discount and deferred financing costs, and the respective fair values are disclosed in Note 11 – Fair Value Measurements . 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 [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.
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 adjustment 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. Please refer to Note 4 – Income Taxes for additional discussion . Effective December 31, 2017, the Company early adopted, on a retrospective basis, FASB ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”) and FASB ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (“ASU 2016-18”). ASU 2016-15 is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The Company determined that of the eight issues addressed in ASU 2016-15, only the issue related to debt extinguishment costs impacted the Company’s consolidated financial statements and disclosures. In accordance with ASU 2016-15, the Company reclassified certain debt extinguishment costs from operating activities to financing activities. ASU 2016-18 is intended to clarify guidance on the classification and presentation of restricted cash and restricted cash equivalents in the statement of cash flows. In accordance with ASU 2016-18, the Company reclassified $3.0 million of restricted cash out of investing activities and combined it with cash and cash equivalents in the accompanying statements of cash flows for the year ended December 31, 2016. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”) . Under the new standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. The standard requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The FASB issued several additional ASUs related to ASU 2014-09 that provide clarified implementation guidance and deferred the effective date of ASU 2014-09. Effective January 1, 2018, the Company adopted ASU 2014-09 and all related ASUs using the modified retrospective transition method, which was applied to all active contracts as of the effective date. The adoption of ASU 2014-09 did not result in a change to current or prior period results nor did it result in a material change to the Company’s business processes, systems, or controls. However, upon adoption, the Company expanded its disclosures to comply with the disclosure requirements of ASU 2014-09. Please refer to Note 2 - Revenue from Contracts with Customers for additional discussion. 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”). ASU 2016-02 requires lessees to recognize right-of-use assets and lease payment liabilities on the balance sheet for leases representing the Company’s right to use the underlying assets for the lease term. Each lease that is recognized in the balance sheet will be classified as either finance or operating, with such classification affecting the pattern and classification of expense recognition in the consolidated statements of operations and presentation within the statements of cash flows. The Company leveraged a dedicated project team and external consultants to evaluate the impacts of ASU 2016-02, which included an analysis of contracts for office leases, drilling rig agreements, well completion agreements, midstream agreements, water handling agreements, certain field equipment rentals, land easements, and other arrangements that included potential lease components. 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. The Company has completed the process of reviewing and determining contracts to which the new guidance applies, and has implemented policies, internal controls, and processes that are necessary to support the additional accounting and disclosure requirements going forward. The lease administration system that will support the on-going maintenance and accounting after adoption is operational and is currently being populated with the necessary lease data and relevant assumptions. Policy elections and practical expedients the Company has implemented as part of adopting 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 allows the Company to avoid reassessing contracts that commenced prior to adoption that were properly evaluated under legacy GAAP, (d) excluding land easements that existed or expired before adoption of ASU 2016-02, and (e) the policy election that eliminates the need for adjusting prior period comparable financial statements prepared under legacy lease accounting guidance. The Company adopted ASU 2016-02 on January 1, 2019, using the modified retrospective approach, and has necessary staff and processes in place to ensure on-going compliance. Adoption of this guidance will result in an increase in right-of-use assets and related liabilities on the Company’s consolidated balance sheets. In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU 2017-01”). ASU 2017-01 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The Company adopted ASU 2017-01 on the effective date of January 1, 2018, on a prospective basis. 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. The accompanying statements of operations line items that were adjusted as a result of the adoption of ASU 2017-07 for the years ended December 31, 2017 , and 2016 are summarized as follows: For the Year Ended December 31, 2017 For the Year Ended December 31, 2016 As Reported As Adjusted As Reported As Adjusted (in thousands) Operating expenses: Exploration $ 56,179 $ 54,713 $ 65,641 $ 64,970 General and administrative $ 120,585 $ 117,283 $ 126,428 $ 124,828 Total operating expenses $ 1,297,865 $ 1,293,097 $ 2,276,765 $ 2,274,494 Income (loss) from operations $ (168,489 ) $ (163,721 ) $ (1,059,315 ) $ (1,057,044 ) Other non-operating income (expense), net $ 3,968 $ (800 ) $ 362 $ (1,909 ) 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. 2018-14, Compensation-Retirement Benefits-Defined Benefit Plans-General (Subtopic 715-20): Disclosure Framework-Changes to the Disclosure Requirements for Defined Benefit Plans (“ASU 2018-14”). ASU 2018-14 provides updated disclosure requirements related to retirement benefits and defined pension plans with the purpose of improving the effectiveness of disclosures with regard to such topics. The guidance is to be applied using a retrospective method and is effective for fiscal years ending after December 15, 2020, with early adoption permitted. The Company early adopted ASU 2018-14 on December 31, 2018, and it did not result in a material impact to the Company’s consolidated financial statements or disclosures. In August 2018, the FASB issued ASU No. 2018-15, Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”). ASU 2018-15 aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The Company expects to adopt ASU 2018-15 on January 1, 2020, with prospective application. The Company is evaluating the impact of ASU 2018-15 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, 2018 , 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 to other comprehensive income (loss), net of tax, in the accompanying statements of comprehensive income. 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.
Derivatives, Methods of Accounting, Derivatives Not Designated or Qualifying as Hedges [Policy Text Block]	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.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Schedule of Major Customers [Table Text Block]	The Company had the following major customers and sales to entities under common ownership, which 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, 2018 2017 2016 Major customer #1 (1) 18 % 6 % — % Major customer #2 (1) 10 % 10 % 5 % Group #1 of entities under common ownership (2) 18 % 17 % 15 % Group #2 of entities under common ownership (2) 12 % 8 % 8 % ____________________________________________ (1) These major customers are purchasers of a portion of the Company’s production from its Permian region. (2) In the aggregate, these groups of entities under common ownership represented 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 represented more than 10 percent of the Company’s total oil, gas, and NGL production revenue.
Schedule of New Accounting Pronouncements and Changes in Accounting Principles [Table Text Block]	The accompanying statements of operations line items that were adjusted as a result of the adoption of ASU 2017-07 for the years ended December 31, 2017 , and 2016 are summarized as follows: For the Year Ended December 31, 2017 For the Year Ended December 31, 2016 As Reported As Adjusted As Reported As Adjusted (in thousands) Operating expenses: Exploration $ 56,179 $ 54,713 $ 65,641 $ 64,970 General and administrative $ 120,585 $ 117,283 $ 126,428 $ 124,828 Total operating expenses $ 1,297,865 $ 1,293,097 $ 2,276,765 $ 2,274,494 Income (loss) from operations $ (168,489 ) $ (163,721 ) $ (1,059,315 ) $ (1,057,044 ) Other non-operating income (expense), net $ 3,968 $ (800 ) $ 362 $ (1,909 )

Revenue from Contracts with C_2

Revenue from Contracts with Customers (Tables)	12 Months Ended
	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue [Table Text Block]	The tables below present the disaggregation of oil, gas, and NGL production revenue by product type for each of the Company’s operating regions for the years ended December 31, 2018 , 2017 , and 2016 : For the year ended December 31, 2018 Permian South Texas & Gulf Coast Rocky Mountain Total (in thousands) Oil, gas, and NGL production revenue: 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 Permian South Texas & Gulf Coast Rocky Mountain Total (in thousands) Oil, gas, and NGL production revenue: 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. For the year ended December 31, 2016 Permian South Texas & Gulf Coast Rocky Mountain Total (in thousands) Oil, gas, and NGL production revenue: Oil production revenue $ 117,399 $ 189,313 $ 305,126 $ 611,838 Gas production revenue 17,315 308,829 11,144 337,288 NGL production revenue 92 225,821 3,387 229,300 Total $ 134,806 $ 723,963 $ 319,657 $ 1,178,426 Relative percentage 11 % 62 % 27 % 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, 2018
Acquisitions, Divestitures, and Assets Held for Sale 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, 2018 , 2017 , and 2016 . The Divide County Divestiture was considered a disposal of a significant asset group. For the Years Ended December 31, 2018 2017 2016 (in thousands) Loss before income taxes (1) $ (28,975 ) $ (468,786 ) $ (50,034 ) ____________________________________________ (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 previously held for sale. The following table presents income (loss) before income taxes from the outside-operated Eagle Ford shale assets sold for the years ended December 31, 2018 , 2017 , and 2016 . This divestiture was considered a disposal of a significant asset group. For the Years Ended December 31, 2018 2017 2016 (in thousands) Income (loss) before income taxes (1) $ — $ 24,324 $ (218,506 ) ____________________________________________ (1) Income (loss) before income taxes reflects oil, gas, and NGL production revenue, less oil, gas, and NGL production expense, and depletion, depreciation, amortization, and asset retirement obligation liability accretion. Additionally, income (loss) before income taxes includes $269.6 million of impairment of proved properties expense for the year ended December 31, 2016 .
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]	The Company determined that the Rock Oil Acquisition met the criteria of a business combination under ASC Topic 805, Business Combinations . The Company allocated the final adjusted purchase price to the acquired assets and liabilities based on fair value as of the acquisition date, as summarized in the table below. This measurement resulted in no goodwill or bargain purchase gain being recognized. The acquisition costs were insignificant and were expensed as incurred. As of October 4, 2016 (in thousands) Cash consideration $ 998,691 Fair value of assets and liabilities acquired: Wells in progress $ 5,672 Proved oil and gas properties 82,584 Unproved oil and gas properties 913,819 Other assets 5,338 Total fair value of oil and gas properties acquired 1,007,413 Working capital (1,127 ) Asset retirement obligations (7,595 ) Total fair value of net assets acquired $ 998,691
Schedule of Noncash or Part Noncash Acquisitions [Table Text Block]	Under authoritative accounting guidance, the transaction was considered an asset acquisition, and therefore, the properties were recorded based on the fair value of the total consideration transferred on the acquisition date and transaction costs were capitalized as a component of the cost of the assets acquired. The Company allocated the final adjusted purchase price to the acquired assets and liabilities, as summarized in the table below. As of December 21, 2016 (in thousands) Cash consideration, including acquisition costs paid $ 1,174,628 Fair value of equity consideration (1) 437,194 Total consideration $ 1,611,822 Assets and liabilities acquired: Wells in progress $ 21,812 Proved oil and gas properties 61,239 Unproved oil and gas properties 1,538,264 Total oil and gas properties acquired 1,621,315 Working capital (1,852 ) Asset retirement obligations (7,641 ) Total net assets acquired $ 1,611,822 ____________________________________________ (1) The Company issued approximately 13.4 million shares of common stock, par value $0.01 per share, in a private placement to the sellers in the QStar Acquisition on December 21, 2016. The equity consideration was valued on this date using Level 1 and Level 2 inputs with a discount applied due to the lack of marketability in the near term in accordance with the Lock-Up and Registration Rights Agreement that prohibited the sale of such stock until no earlier than the 90th day after issuance.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 2017 2016 (in thousands) Current portion of income tax expense (benefit) Federal $ — $ 5,698 $ 2,932 State 1,662 3,398 1,539 Deferred portion of income tax expense (benefit) 141,708 (192,066 ) (448,643 ) Total income tax expense (benefit) $ 143,370 $ (182,970 ) $ (444,172 ) Effective tax rate 22.0 % 53.2 % 37.0 %
Schedule of components of net deferred income tax liabilities [Table Text Block]	The components of the net deferred tax liabilities are as follows: As of December 31, 2018 2017 (in thousands) Deferred tax liabilities Oil and gas properties $ 218,094 $ 142,467 Derivative assets 35,247 — Other 4,812 3,412 Total deferred tax liabilities 258,153 145,879 Deferred tax assets Derivative liabilities — 29,463 Credit carryover 22,554 22,537 Pension 6,427 7,986 Federal and state tax net operating loss carryovers 4,217 3,867 Stock compensation 3,263 3,545 Other liabilities 1,497 1,470 Total deferred tax assets 37,958 68,868 Valuation allowance (3,083 ) (2,978 ) Net deferred tax assets 34,875 65,890 Total net deferred tax liabilities $ 223,278 $ 79,989 Current federal income tax refundable $ 59 $ 37 Current state income tax payable $ 1,331 $ 3,009
Schedule of effective income tax rate reconciliation [Table Text Block]	Federal income tax expense (benefit) differs from the amount that would be provided by applying the statutory United States federal income tax rate to income before income taxes primarily due to the effect of state income taxes, excess tax benefits and deficiencies from share-based payment awards, changes in valuation allowances, R&D credits, and accumulated impacts of other smaller permanent differences, and is reported as follows: For the Years Ended December 31, 2018 2017 2016 (in thousands) Federal statutory tax expense (benefit) $ 136,873 $ (120,335 ) $ (420,671 ) Increase (decrease) in tax resulting from: Federal tax reform changes - 2017 Tax Act — (63,675 ) — State tax expense (benefit) (net of federal benefit) 2,771 (3,286 ) (17,549 ) Change in valuation allowance 105 (2,727 ) (5,059 ) Employee share-based compensation 2,508 8,190 — Other 1,113 (1,137 ) (893 ) Income tax expense (benefit) $ 143,370 $ (182,970 ) $ (444,172 )
Schedule of unrecognized tax benefits [Table Text Block]	The total amount recorded for unrecognized tax benefits is presented below: For the Years Ended December 31, 2018 2017 2016 (in thousands) Beginning balance $ 446 $ 446 $ 2,782 Additions for tax positions of prior years — — 9 Settlements — — (2,345 ) Ending balance $ 446 $ 446 $ 446

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2018
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 1.500 % 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 %
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 7, 2019 , and December 31, 2018 , and under the Company’s Fifth Amended and Restated Credit Agreement as of December 31, 2017 : As of February 7, 2019 As of December 31, 2018 As of December 31, 2017 (in thousands) Credit facility balance (1) $ — $ — $ — Letters of credit (2) — 200 200 Available borrowing capacity 1,000,000 999,800 924,800 Total aggregate lender commitment amount $ 1,000,000 $ 1,000,000 $ 925,000 ____________________________________________ (1) Unamortized deferred financing costs attributable to the credit facility are presented as a component of other noncurrent assets on the accompanying balance sheets and totaled $6.4 million and $3.1 million as of December 31, 2018 , and 2017 , 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 on the accompanying balance sheets as of December 31, 2018 , and 2017 , consisted of the following: As of December 31, 2018 2017 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) 6.50% Senior Notes due 2021 $ — $ — $ — $ 344,611 $ 2,656 $ 341,955 6.125% Senior Notes due 2022 476,796 3,921 472,875 561,796 5,800 555,996 6.50% Senior Notes due 2023 — — — 394,985 3,707 391,278 5.0% Senior Notes due 2024 500,000 4,688 495,312 500,000 5,610 494,390 5.625% Senior Notes due 2025 500,000 5,808 494,192 500,000 6,714 493,286 6.75% Senior Notes due 2026 500,000 6,407 493,593 500,000 7,242 492,758 6.625% Senior Notes due 2027 500,000 7,533 492,467 — — — Total $ 2,476,796 $ 28,357 $ 2,448,439 $ 2,801,392 $ 31,729 $ 2,769,663
Schedule of Senior Convertible Notes [Table Text Block]	The net carrying amount of the liability component of the Senior Convertible Notes, as reflected on the accompanying balance sheets, consisted of the following as of December 31, 2018 and 2017 : As of December 31, 2018 2017 (in thousands) Principal amount of Senior Convertible Notes $ 172,500 $ 172,500 Unamortized debt discount (22,313 ) (30,183 ) Unamortized deferred financing costs (2,293 ) (3,210 ) Net carrying amount $ 147,894 $ 139,107 The net carrying amount of the equity component of the Senior Convertible Notes recorded in additional paid-in capital on the accompanying balance sheets consisted of the following as of December 31, 2018 and 2017 : As of December 31, 2018 2017 (in thousands) Equity component due to allocation of proceeds to equity $ 40,217 $ 40,217 Related issuance costs (1,375 ) (1,375 ) Deferred tax liability (5,267 ) (5,267 ) Net carrying amount $ 33,575 $ 33,575

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2018
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) 2019 $ 132,502 2020 103,169 2021 88,785 2022 70,741 2023 37,334 Thereafter 24,931 Total $ 457,462

Compensation Plans (Tables)

Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 2017 2016 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 1,533,491 $ 22.97 828,923 $ 43.25 626,328 $ 61.81 Granted 572,924 $ 24.45 977,731 $ 15.86 447,971 $ 26.56 Vested (233,102 ) $ 44.25 (94,338 ) $ 85.85 (130,353 ) $ 64.17 Forfeited (162,054 ) $ 21.79 (178,825 ) $ 44.99 (115,023 ) $ 55.59 Non-vested at end of year 1,711,259 $ 20.68 1,533,491 $ 22.97 828,923 $ 43.25 ____________________________________________ (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 shares settled, performance share units [Table Text Block]	A summary of the shares of common stock issued to settle PSUs for the year ended December 31, 2016 , is presented in the table below: For the Year Ended December 31, 2016 Shares of common stock issued to settle PSUs (1) 44,870 Less: shares of common stock withheld for income and payroll taxes (14,809 ) Net shares of common stock issued 30,061 Multiplier earned 0.2 ____________________________________________ (1) During the year ended December 31, 2016 , the Company issued shares of common stock to settle PSUs that related to awards granted in 2013. 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 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, 2018 2017 2016 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 1,244,262 $ 20.25 604,116 $ 37.39 543,737 $ 55.01 Granted 583,552 $ 25.77 1,020,780 $ 16.64 417,065 $ 28.08 Vested (407,529 ) $ 24.30 (246,025 ) $ 43.99 (241,363 ) $ 58.06 Forfeited (177,122 ) $ 17.26 (134,609 ) $ 26.38 (115,323 ) $ 43.52 Non-vested at end of year 1,243,163 $ 21.50 1,244,262 $ 20.25 604,116 $ 37.39
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, 2018 2017 2016 Shares of common stock issued to settle RSUs (1) 407,529 246,025 241,363 Less: shares of common stock withheld for income and payroll taxes (115,784 ) (74,747 ) (72,181 ) Net shares of common stock issued 291,745 171,278 169,182 ____________________________________________ (1) During the years ended December 31, 2018 , 2017 , and 2016 , 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, 2018 2017 2016 Risk free interest rate 1.8 % 0.9 % 0.4 % Dividend yield 0.4 % 0.5 % 0.4 % Volatility factor of the expected market price of the Company’s common stock 55.9 % 62.5 % 95.0 % Expected life (in years) 0.5 0.5 0.5
Schedule of net profits plan cash payment allocation [Table Text Block]	The following table presents cash payments made or accrued under the Net Profits Plan related to periodic operations, of which the majority is recorded as general and administrative expense, and cash payments made or accrued as a result of divestitures of properties subject to the Net Profits Plan, which are recorded as a reduction to the net gain (loss) on divestiture activity line item in the accompanying statements of operations. For the Years Ended December 31, 2018 2017 2016 (in thousands) Cash payments made or accrued related to operations $ 63 $ (54 ) $ 6,608 Cash payments made or accrued related to divestitures — 2,753 24,349 Total net settlements $ 63 $ 2,699 $ 30,957
[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, 2018
Defined Benefit Plan [Abstract]
Schedule of net funded status [Table Text Block]	For the Years Ended December 31, 2018 2017 (in thousands) Change in benefit obligation: Projected benefit obligation at beginning of year $ 71,937 $ 69,659 Service cost 6,730 6,638 Interest cost 2,622 2,689 Actuarial (gain) loss (7,155 ) 3,708 Benefits paid (8,048 ) (10,757 ) Projected benefit obligation at end of year 66,086 71,937 Change in plan assets: Fair value of plan assets at beginning of year 30,978 31,731 Actual return on plan assets (964 ) 2,956 Employer contribution 8,134 7,048 Benefits paid (8,048 ) (10,757 ) Fair value of plan assets at end of year 30,100 30,978 Funded status at end of year $ (35,986 ) $ (40,959 )
Schedule of accumulated benefit obligation in excess of plan assets [Table Text Block]	As of December 31, 2018 2017 (in thousands) Projected benefit obligation $ 66,086 $ 71,937 Accumulated benefit obligation $ 52,368 $ 56,045 Less: fair value of plan assets (30,100 ) (30,978 ) Underfunded accumulated benefit obligation $ 22,268 $ 25,067
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 accumulated other comprehensive loss as of December 31, 2018 , and 2017 , were as follows: As of December 31, 2018 2017 (in thousands) Unrecognized actuarial losses $ 15,741 $ 21,397 Unrecognized prior service costs 48 66 Accumulated other comprehensive loss $ 15,789 $ 21,463
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 2018 , 2017 , and 2016 , were as follows: For the Years Ended December 31, 2018 2017 2016 (in thousands) Net actuarial gain (loss) $ 4,329 $ (2,995 ) $ (3,322 ) Amortization of prior service cost 18 17 16 Amortization of net actuarial loss 1,327 1,297 1,582 Settlements — 3,009 — Total pension liability adjustment, pre-tax 5,674 1,328 (1,724 ) Tax (expense) benefit (4,265 ) (561 ) 570 Cumulative effect of accounting change (1) 2,969 — — Total pension liability adjustment, net $ 4,378 $ 767 $ (1,154 ) _________________________________________ (1) 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, 2018 2017 2016 (in thousands) Components of net periodic benefit cost: Service cost $ 6,730 $ 6,638 $ 8,200 Interest cost 2,622 2,689 2,908 Expected return on plan assets that reduces periodic pension benefit cost (1,862 ) (2,244 ) (2,235 ) Amortization of prior service cost 18 17 16 Amortization of net actuarial loss 1,327 1,297 1,582 Settlements — 3,009 — Net periodic benefit cost $ 8,835 $ 11,406 $ 10,471
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, 2018 2017 Projected benefit obligation: Discount rate 4.4% 3.8% Rate of compensation increase 6.2% 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, 2018 2017 2016 Net periodic benefit cost: Discount rate 3.8% 4.2% 4.7% Expected return on plan assets (1) 5.5% 6.5% 7.5% 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 2019 2018 2017 Equity securities 35.0 % 31.8 % 38.4 % Fixed income securities 43.0 % 41.3 % 39.8 % Other securities 22.0 % 26.9 % 21.8 % 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, 2018 , and 2017 , 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, 2018 Cash — % $ — $ — $ — $ — 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: High-yield bonds (4) — % — — — — Core fixed income (5) 34.4 % 10,342 10,342 — — Floating rate corporate loans (6) 6.9 % 2,078 2,078 — — Total fixed income securities 41.3 % 12,420 12,420 — — Other securities: Commodities (7) — % — — — — Real estate (8) 6.0 % 1,820 — — 1,820 Collective investment trusts (9) 3.1 % 934 — 934 — Hedge fund (10) 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 As of December 31, 2017 Cash — % $ — $ — $ — $ — Equity securities: Domestic (2) 22.2 % 6,865 4,805 2,060 — International (3) 16.2 % 5,032 3,806 1,226 — Total equity securities 38.4 % 11,897 8,611 3,286 — Fixed income securities: High-yield bonds (4) 2.8 % 876 876 — — Core fixed income (5) 28.6 % 8,842 8,842 — — Floating rate corporate loans (6) 8.4 % 2,607 2,607 — — Total fixed income securities 39.8 % 12,325 12,325 — — Other securities: Commodities (7) 1.9 % 588 588 — — Real estate (8) 5.6 % 1,735 — — 1,735 Collective investment trusts (9) 3.1 % 959 — 959 — Hedge fund (10) 11.2 % 3,474 — — 3,474 Total other securities 21.8 % 6,756 588 959 5,209 Total investments 100.0 % $ 30,978 $ 21,524 $ 4,245 $ 5,209 ____________________________________________ (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) High-yield bonds consist of non-investment grade fixed income securities. The investment objective is to obtain high current income. Due to the increased level of default risk, security selection focuses on credit-risk analysis. (5) 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. (6) 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. (7) Investments with exposure to commodity price movements, primarily through the use of futures, swaps, and other commodity-linked securities. (8) 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. (9) 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. (10) 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, 2017 $ 5,214 Purchases 300 Realized gain on assets 130 Unrealized gain on assets 120 Disposition (555 ) Balance at December 31, 2017 $ 5,209 Purchases — Realized gain on assets 191 Unrealized gain on assets 152 Disposition (45 ) Balance at December 31, 2018 $ 5,507
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) 2019 $ 5,429 2020 $ 5,066 2021 $ 4,913 2022 $ 5,715 2023 $ 7,693 2024 through 2028 $ 30,400

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2018
Earnings Per Share [Abstract]
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share	The following table details the weighted-average dilutive and anti-dilutive securities for the years presented: For the Years Ended December 31, 2018 2017 2016 (in thousands) Dilutive 1,590 — — Anti-dilutive — 264 280
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, 2018 2017 2016 (in thousands, except per share data) Net income (loss) $ 508,407 $ (160,843 ) $ (757,744 ) Basic weighted-average common shares outstanding 111,912 111,428 76,568 Dilutive effect of non-vested RSUs and contingent PSUs 1,590 — — Dilutive effect of Senior Convertible Notes — — — Diluted weighted-average common shares outstanding 113,502 111,428 76,568 Basic net income (loss) per common share $ 4.54 $ (1.44 ) $ (9.90 ) Diluted net income (loss) per common share $ 4.48 $ (1.44 ) $ (9.90 )

Derivative Financial Instrume_2

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2018
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Schedule of Notional Amounts of Outstanding Derivative Positions	Oil Swaps Contract Period NYMEX WTI Volumes Weighted-Average Contract Price (MBbl) (per Bbl) First quarter 2019 826 $ 60.16 Second quarter 2019 575 $ 55.52 Third quarter 2019 1,217 $ 61.41 Fourth quarter 2019 1,115 $ 59.97 2020 2,491 $ 65.68 Total 6,224 Oil Collars Contract Period NYMEX WTI Volumes Weighted-Average Floor Price Weighted-Average Ceiling Price (MBbl) (per Bbl) (per Bbl) First quarter 2019 2,503 $ 51.66 $ 64.32 Second quarter 2019 2,802 $ 52.18 $ 64.61 Third quarter 2019 2,364 $ 49.07 $ 62.67 Fourth quarter 2019 2,386 $ 49.08 $ 62.65 2020 1,165 $ 55.00 $ 66.47 Total 11,220 Oil Basis Swaps Contract Period WTI Midland-NYMEX WTI Volumes Weighted-Average Contract Price (1) NYMEX WTI-ICE Brent Volumes Weighted-Average (2) (MBbl) (per Bbl) (MBbl) (per Bbl) First quarter 2019 2,433 $ (4.44 ) — $ — Second quarter 2019 2,571 $ (4.49 ) — $ — Third quarter 2019 3,291 $ (2.86 ) — $ — Fourth quarter 2019 3,338 $ (2.87 ) — $ — 2020 11,601 $ (1.03 ) 2,750 $ (8.03 ) 2021 — $ — 3,650 $ (7.86 ) 2022 — $ — 3,650 $ (7.78 ) Total 23,234 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 2019 19,805 $ 2.99 — $ — Second quarter 2019 10,439 $ 2.82 2,803 $ 0.69 Third quarter 2019 12,531 $ 2.82 2,984 $ 1.28 Fourth quarter 2019 14,433 $ 2.88 2,962 $ 1.75 2020 9,123 $ 2.98 2,060 $ 2.20 Total (1) 66,331 10,809 ____________________________________________ (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, 2018, total volumes for gas swaps are comprised of 86 percent IF HSC , four percent IF Waha , and 10 percent GD Waha . Gas Collars Contract Period IF HSC Volumes Weighted- Average Floor Price Weighted- Average Ceiling Price (BBtu) (per MMBtu) (per MMBtu) First quarter 2019 — $ — $ — Second quarter 2019 4,358 $ 2.50 $ 2.83 Third quarter 2019 5,066 $ 2.50 $ 2.83 Fourth quarter 2019 4,818 $ 2.50 $ 2.83 Total 14,242 NGL Swaps OPIS Ethane Purity Mont Belvieu OPIS Propane Mont Belvieu Non-TET OPIS Normal Butane Mont Belvieu Non-TET OPIS Isobutane Mont Belvieu Non-TET OPIS Natural Gasoline Mont Belvieu Non-TET Contract Period Volumes Weighted-Average Contract Price Volumes Weighted-Average Volumes Weighted-Average Volumes Weighted-Average Volumes Weighted-Average (MBbl) (per Bbl) (MBbl) (per Bbl) (MBbl) (per Bbl) (MBbl) (per Bbl) (MBbl) (per Bbl) First quarter 2019 853 $ 12.25 540 $ 28.72 38 $ 35.64 29 $ 35.70 48 $ 50.93 Second quarter 2019 877 $ 12.29 561 $ 31.32 38 $ 35.64 29 $ 35.70 49 $ 50.93 Third quarter 2019 907 $ 12.34 637 $ 31.29 39 $ 35.64 30 $ 35.70 50 $ 50.93 Fourth quarter 2019 896 $ 12.36 651 $ 31.64 39 $ 35.64 29 $ 35.70 50 $ 50.93 2020 539 $ 11.13 — $ — — $ — — $ — — $ — Total 4,072 2,389 154 117 197
Schedule of fair value of derivatives in accompanying balance sheets	The following tables detail the fair value of derivatives recorded in the accompanying balance sheets, by category: As of December 31, 2018 Derivative Assets Derivative Liabilities Balance Sheet Classification Fair Value Balance Sheet Classification Fair Value (in thousands) Commodity contracts Current assets $ 175,130 Current liabilities $ 62,853 Commodity contracts Noncurrent assets 58,499 Noncurrent liabilities 12,496 Total commodity contracts $ 233,629 $ 75,349 As of December 31, 2017 Derivative Assets Derivative Liabilities Balance Sheet Classification Fair Value Balance Sheet Classification Fair Value (in thousands) Commodity contracts Current assets $ 64,266 Current liabilities $ 172,582 Commodity contracts Noncurrent assets 40,362 Noncurrent liabilities 71,402 Total commodity contracts $ 104,628 $ 243,984
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 derivative contracts: Derivative Assets Derivative Liabilities As of December 31, As of December 31, Offsetting of Derivative Assets and Liabilities 2018 2017 2018 2017 (in thousands) Gross amounts presented in the accompanying balance sheets $ 233,629 $ 104,628 $ (75,349 ) $ (243,984 ) Amounts not offset in the accompanying balance sheets (56,041 ) (100,035 ) 56,041 100,035 Net amounts $ 177,588 $ 4,593 $ (19,308 ) $ (143,949 )
Schedule of gains and losses on derivative instruments in the statement of operations	The following table summarizes the components of the net derivative (gain) loss line item presented in the accompanying statements of operations: For the Years Ended December 31, 2018 2017 2016 (in thousands) Derivative settlement (gain) loss: Oil contracts $ 68,860 $ 31,176 $ (243,102 ) Gas contracts 13,029 (87,857 ) (94,936 ) NGL contracts 53,914 35,447 8,560 Total derivative settlement (gain) loss $ 135,803 $ (21,234 ) $ (329,478 ) Net derivative (gain) loss: Oil contracts $ (192,002 ) $ 71,502 $ 85,370 Gas contracts 35,411 (76,315 ) 81,060 NGL contracts (5,241 ) 31,227 84,203 Total net derivative (gain) loss $ (161,832 ) $ 26,414 $ 250,633

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2018
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, 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. 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, 2017 : Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 104,628 $ — Liabilities: Derivatives (1) $ — $ 243,984 $ — ____________________________________________ (1) This represents a financial asset or liability that is measured at fair value on a recurring basis.	[1],[2]
Abandonment And Impairment Of Unproved Properties [Table Text Block]	The following table presents abandonment and impairment of unproved properties expense recorded for the periods presented: For the Years Ended December 31, 2018 2017 2016 (in millions) Abandonment and impairment of unproved properties $ 49.9 $ 12.3 $ 80.4
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, 2018 , or 2017 , 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, 2018 2017 Principal Amount Fair Value Principal Amount Fair Value (in thousands) 6.50% Senior Notes due 2021 $ — $ — $ 344,611 $ 351,682 6.125% Senior Notes due 2022 $ 476,796 $ 452,336 $ 561,796 $ 571,627 6.50% Senior Notes due 2023 $ — $ — $ 394,985 $ 403,434 5.0% Senior Notes due 2024 $ 500,000 $ 439,265 $ 500,000 $ 483,440 5.625% Senior Notes due 2025 $ 500,000 $ 436,460 $ 500,000 $ 494,355 6.75% Senior Notes due 2026 $ 500,000 $ 448,305 $ 500,000 $ 516,350 6.625% Senior Notes due 2027 $ 500,000 $ 442,500 $ — $ — 1.50% Senior Convertible Notes due 2021 $ 172,500 $ 158,614 $ 172,500 $ 168,291
[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, 2018
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 2018 , 2017 , and 2016 . 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, 2018 2017 2016 (in thousands) Beginning balance $ 49,446 $ 19,846 $ 11,952 Additions to capitalized exploratory well costs pending the determination of proved reserves 11,197 49,446 19,846 Divestitures (109 ) — — Reclassifications to wells, facilities, and equipment based on the determination of proved reserves (49,337 ) (19,846 ) (11,952 ) Capitalized exploratory well costs charged to expense — — — Ending balance $ 11,197 $ 49,446 $ 19,846

Reconciliation of Asset Retirem

Reconciliation of Asset Retirement Obligation Liability (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 2017 (in thousands) Beginning asset retirement obligations $ 114,470 $ 123,307 Liabilities incurred (1) 4,054 7,588 Liabilities settled (2) (33,024 ) (30,432 ) Accretion expense 4,438 5,988 Revision to estimated cash flows 4,256 8,019 Ending asset retirement obligations (3)(4) $ 94,194 $ 114,470 ____________________________________________ (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) Balance as of December 31, 2017 , included $11.4 million of asset retirement obligations associated with oil and gas properties held for sale. (4) Balances as of December 31, 2018 , and 2017 , included $2.3 million and $75,000 , 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, 2018
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, 2018 2017 (in thousands) Oil, gas, and NGL production revenue $ 107,230 $ 96,610 Amounts due from joint interest owners 31,497 56,929 State severance tax refunds 4,415 2,276 Derivative settlements 9,475 99 Other 14,919 4,240 Total accounts receivable $ 167,536 $ 160,154
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, 2018 2017 (in thousands) Drilling and lease operating cost accruals $ 139,711 $ 126,500 Trade accounts payable 56,047 77,573 Revenue and severance tax payable 94,806 60,328 Property taxes 18,694 13,222 Compensation 31,486 39,471 Derivative settlements 1,287 12,644 Interest 40,840 45,057 Other 20,328 11,835 Total accounts payable and accrued expenses $ 403,199 $ 386,630

Summary of Significant Accoun_4

Summary of Significant Accounting Policies Other (Details)		Dec. 31, 2018USD ($)	Dec. 31, 2018USD ($)		Dec. 31, 2017USD ($)		Dec. 31, 2016		Feb. 21, 2019
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]
Long-term Line of Credit		$ 0	$ 0		$ 0
Minimum [Member]
Revenues [Abstract]
Revenue Receipt, Days After Sale			30
Maximum [Member]
Revenues [Abstract]
Revenue Receipt, Days After Sale			90
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
Property, Plant and Equipment, Other Types [Member] | Minimum [Member]
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment, Estimated Useful Lives			3 years
Property, Plant and Equipment, Other Types [Member] | Maximum [Member]
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment, Estimated Useful Lives			30 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%		6.00%		0.00%
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]		10.00%		10.00%		5.00%
Customer Concentration Risk [Member] | Oil, gas, and NGLS revenue [Member] | Unnamed Major Customer One with Related Entities [Member]
Concentration of Credit Risk and Major Customers [Abstract]
Entity-Wide Revenue, Major Customer, Percentage	[5]		18.00%		17.00%		15.00%
Customer Concentration Risk [Member] | Oil, gas, and NGLS revenue [Member] | Unnamed Major Customer Two with Related Entities [Member]
Concentration of Credit Risk and Major Customers [Abstract]
Entity-Wide Revenue, Major Customer, Percentage	[5]		12.00%		8.00%		8.00%
Measurement Input, Discount Rate [Member] | Oil and Gas Properties [Member] | Minimum [Member]
Basis of Presentation and Significant Accounting Policies [Line Items]
Fair Value Assumptions, Measurement Input		0.10	0.10
Measurement Input, Discount Rate [Member] | Oil and Gas Properties [Member] | Maximum [Member]
Basis of Presentation and Significant Accounting Policies [Line Items]
Fair Value Assumptions, Measurement Input		0.15	0.15
Measurement Input, Risk Free Interest Rate [Member] | Asset Retirement Obligation Costs [Member] | Minimum [Member]
Basis of Presentation and Significant Accounting Policies [Line Items]
Fair Value Assumptions, Measurement Input		0.055	0.055
Measurement Input, Risk Free Interest Rate [Member] | Asset Retirement Obligation Costs [Member] | Maximum [Member]
Basis of Presentation and Significant Accounting Policies [Line Items]
Fair Value Assumptions, Measurement Input		0.12	0.12
Subsequent Event [Member]
Concentration of Credit Risk and Major Customers [Abstract]
Number of Derivative Counterparties									10
[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 Permian region.
[5]	(2) In the aggregate, these groups of entities under common ownership represented 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 represented 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 ($) $ in Thousands		12 Months Ended
		Dec. 31, 2018		Dec. 31, 2017	Dec. 31, 2016	Jan. 01, 2018	Jan. 01, 2017
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Retained earnings		$ (1,165,842)	[1]	$ (665,657)
Deferred Tax Assets, Net of Valuation Allowance, Noncurrent		34,875		65,890
Exploration		55,166		54,713	$ 64,970
General and administrative		116,504		117,283	124,828
Total operating expenses		1,230,735		1,293,097	2,274,494
Income (loss) from operations		836,337		(163,721)	(1,057,044)
Other non-operating income (expense), net		3,086		(800)	(1,909)
Cumulative effect of accounting change	[2]	0		44,732
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							$ (44,300)
ASU 2016-09 Cumulative Effect of Actual Forfeiture Rate [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Retained earnings							700
Additional Paid in Capital							1,100
Deferred Tax Assets, Net of Valuation Allowance, Noncurrent							$ (400)
Accounting Standards Update 2016-15, 2016-18 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Restricted Cash					3,000
Accounting Standards Update 2018-02 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative effect of accounting change	[3]	$ 2,969		0	0	$ (2,969)
Previously Reported [Member] | Accounting Standards Update 2017-07 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Exploration				56,179	65,641
General and administrative				120,585	126,428
Total operating expenses				1,297,865	2,276,765
Income (loss) from operations				(168,489)	(1,059,315)
Other non-operating income (expense), net				$ 3,968	$ 362
[1]	(1) The Company reclassified $3.0 million of tax effects stranded in accumulated other comprehensive loss to retained earnings as of January 1, 2018. Please refer to Note 1 – Summary of Significant Accounting Policies for further detail.
[2]	(1) Refer to Recently Issued Accounting Standards in Note 1 – Summary of Significant Accounting Policies for additional information.
[3]	(1) 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, 2018		Dec. 31, 2017		Dec. 31, 2016
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	$ 1,636,357	[1]	$ 1,253,783	[2]	$ 1,178,426	[3]
Concentration Risk, Percentage	100.00%	[1]	100.00%	[2]	100.00%	[3]
Revenue, Remaining Performance Obligation, Amount	$ 0
Permian Region [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	1,064,607	[1]	$ 482,060	[2]	$ 134,806	[3]
South Texas & Gulf Coast [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	514,514	[1]	610,485	[2]	723,963	[3]
Rocky Mountain Region [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	$ 57,236	[1]	$ 161,238	[2]	$ 319,657	[3]
Sales Revenue, Net [Member] | Geographic Concentration Risk [Member] | Permian Region [Member]
Segment Reporting Information [Line Items]
Concentration Risk, Percentage	65.00%	[1]	38.00%	[2]	11.00%	[3]
Sales Revenue, Net [Member] | Geographic Concentration Risk [Member] | South Texas & Gulf Coast [Member]
Segment Reporting Information [Line Items]
Concentration Risk, Percentage	32.00%	[1]	49.00%	[2]	62.00%	[3]
Sales Revenue, Net [Member] | Geographic Concentration Risk [Member] | Rocky Mountain Region [Member]
Segment Reporting Information [Line Items]
Concentration Risk, Percentage	3.00%	[1]	13.00%	[2]	27.00%	[3]
Oil production revenue [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	$ 1,065,676	[1]	$ 654,250	[2]	$ 611,838	[3]
Oil production revenue [Member] | Permian Region [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	938,004		419,732		117,399
Oil production revenue [Member] | South Texas & Gulf Coast [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	72,821		82,674		189,313
Oil production revenue [Member] | Rocky Mountain Region [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	54,851		151,844		305,126
Gas production revenue [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	354,450	[1]	369,410	[2]	337,288	[3]
Gas production revenue [Member] | Permian Region [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	125,603		61,781		17,315
Gas production revenue [Member] | South Texas & Gulf Coast [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	227,252		301,780		308,829
Gas production revenue [Member] | Rocky Mountain Region [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	1,595		5,849		11,144
NGL production revenue [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	216,231	[1]	230,123	[2]	229,300	[3]
NGL production revenue [Member] | Permian Region [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	1,000		547		92
NGL production revenue [Member] | South Texas & Gulf Coast [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	214,441		226,031		225,821
NGL production revenue [Member] | Rocky Mountain Region [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	$ 790		$ 3,545		$ 3,387
[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	Dec. 31, 2018	Dec. 31, 2017
Accounts Receivable
Accounts receivable	$ 167,536	$ 160,154
Oil, gas, and NGL production revenue [Member]
Accounts Receivable
Accounts receivable	$ 107,230	$ 96,610

Divestitures and Assets Held fo

Divestitures and Assets Held for Sale (Details) $ in Thousands		12 Months Ended
		Dec. 31, 2018USD ($)a	Dec. 31, 2017USD ($)a	Dec. 31, 2016USD ($)
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		$ 748,509	$ 776,719	$ 946,062
Net gain (loss) on divestiture activity		426,917	(131,028)	37,074
Impairment of proved properties		$ 0	3,806	354,614
Assets Held-for-sale
Probable period within which sale will take place (in years)		1 year
Properties held for sale, net		$ 5,280	111,700
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 and Halff East Divestiture 2018 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Income (loss) before income taxes	[1]	(28,975)	(468,786)	(50,034)
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	[2]	0	24,324	(218,506)
Impairment of proved properties				269,600
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
Disposal group, disposed of by sale, not discontinued operations [Member] | Rocky Mountain divestiture 2016 [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				110,300
Net gain (loss) on divestiture activity				16,400
Disposal group, disposed of by sale, not discontinued operations [Member] | Raven/Bear Den divestiture 2016 [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				755,700
Net gain (loss) on divestiture activity				29,500
Disposal group, disposed of by sale, not discontinued operations [Member] | Permian divestiture 2016 [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				54,700
Net gain (loss) on divestiture activity				$ (10,000)
Disposal group, held-for-sale, not discontinued operations [Member]
Assets Held-for-sale
Properties held for sale, net		$ 5,280	$ 111,700
Net acres held for sale | a			112,000
[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 previously held for sale.
[2]	(1) Income (loss) before income taxes reflects oil, gas, and NGL production revenue, less oil, gas, and NGL production expense, and depletion, depreciation, amortization, and asset retirement obligation liability accretion. Additionally, income (loss) before income taxes includes $269.6 million of impairment of proved properties expense for the year ended December 31, 2016.

Acquisitions (Details)

Acquisitions (Details) $ / shares in Units, shares in Millions		Dec. 21, 2016USD ($)$ / sharesshares	Oct. 04, 2016USD ($)	Feb. 21, 2019a	Sep. 30, 2018USD ($)a	Sep. 30, 2017USD ($)	Sep. 30, 2017USD ($)	Dec. 31, 2018USD ($)a$ / shares	Dec. 31, 2017USD ($)a$ / shares	Dec. 31, 2016USD ($)	Dec. 31, 2017USD ($)$ / shares
Business Acquisition [Line Items]
Payments to acquire oil and gas property and equipment								$ 33,255,000	$ 89,896,000	$ 2,183,790,000
Carrying value of properties exchanged or acquired								95,121,000		$ 733,000
Wells in progress								295,529,000	321,347,000		$ 321,347,000
Proved oil and gas properties								7,278,362,000	6,139,379,000		6,139,379,000
Unproved oil and gas properties								$ 1,581,401,000	$ 2,047,203,000		$ 2,047,203,000
Common Stock, par value per share | $ / shares		$ 0.01						$ 0.01	$ 0.01		$ 0.01
Rock Oil Acquisition 2016 [Member]
Business Acquisition [Line Items]
Payments to acquire a business			$ 991,000,000						$ 7,700,000		$ 998,691,000
Wells in progress			5,672,000
Proved oil and gas properties			82,584,000
Unproved oil and gas properties			913,819,000
Other assets			5,338,000
Total fair value of oil and gas properties acquired			1,007,413,000
Working capital			(1,127,000)
Asset retirement obligations			(7,595,000)
Total fair value of net assets acquired			$ 998,691,000
Other Martin County Acquisition 2018 [Member]
Business Acquisition [Line Items]
Net acres acquired | a								1,030
Payments to acquire oil and gas property and equipment								$ 33,300,000
Other Howard and Martin Counties acquisitions 2017 [Member]
Business Acquisition [Line Items]
Net acres acquired | a									3,600
Payments to acquire oil and gas property and equipment									$ 76,500,000
QStar Acquisition 2016 [Member]
Business Acquisition [Line Items]
Payments to acquire oil and gas property and equipment		$ 1,200,000,000				$ 7,300,000	$ 1,174,628,000
Carrying value of properties exchanged or acquired		1,611,822,000
Wells in progress		21,812,000
Proved oil and gas properties		61,239,000
Unproved oil and gas properties		1,538,264,000
Working capital		(1,852,000)
Asset retirement obligations		$ (7,641,000)
Private issuance of Common Stock for an acquisition | shares		13.4
Total consideration							$ 1,611,822,000
Fair value of equity consideration	[1]	$ 437,194,000
Total oil and gas properties acquired		$ 1,621,315,000
Subsequent Event [Member]
Business Acquisition [Line Items]
Non-monetary trade, acreage acquired | a				1,580
Non-monetary trade, acreage exchanged | a				1,650
Howard and Martin Counties Trades 2018 [Member]
Business Acquisition [Line Items]
Non-monetary trade, acreage acquired | a					2,650
Carrying value of properties exchanged or acquired					$ 95,100,000
Gain (loss) recognized on trade					$ 0
Other Howard and Martin Counties trades [Member]
Business Acquisition [Line Items]
Non-monetary trade, acreage acquired | a									8,125
Carrying value of properties exchanged or acquired									$ 293,963,000
Non-monetary trade, acreage exchanged | a									7,580
[1]	(1) The Company issued approximately 13.4 million shares of common stock, par value $0.01 per share, in a private placement to the sellers in the QStar Acquisition on December 21, 2016. The equity consideration was valued on this date using Level 1 and Level 2 inputs with a discount applied due to the lack of marketability in the near term in accordance with the Lock-Up and Registration Rights Agreement that prohibited the sale of such stock until no earlier than the 90th day after issuance.

Income Taxes (Details)

Income Taxes (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Components of the provision for income taxes
Federal	$ 0	$ 5,698,000	$ 2,932,000
State	1,662,000	3,398,000	1,539,000
Deferred portion of income tax expense (benefit)	141,708,000	(192,066,000)	(448,643,000)
Total income tax expense (benefit)	$ 143,370,000	$ (182,970,000)	$ (444,172,000)
Effective tax rate (as a percent)	22.00%	53.20%	37.00%
Deferred income taxes [Abstract]
Deferred tax liabilities, oil and gas properties	$ 218,094,000	$ 142,467,000
Deferred tax liabilities, derivatives assets	35,247,000	0
Deferred tax liabilities, other	4,812,000	3,412,000
Total deferred tax liabilities	258,153,000	145,879,000
Deferred tax assets, derivative liabilities	0	29,463,000
Deferred tax assets, credit carryover	22,554,000	22,537,000
Deferred tax assets, pension	6,427,000	7,986,000
Deferred tax assets, federal and state tax net operating loss carryovers	4,217,000	3,867,000
Deferred tax assets, stock compensation	3,263,000	3,545,000
Deferred tax assets, other liabilities	1,497,000	1,470,000
Total deferred tax assets	37,958,000	68,868,000
Deferred tax assets, valuation allowance	(3,083,000)	(2,978,000)
Net deferred tax assets	34,875,000	65,890,000
Total net deferred tax liabilities	223,278,000	79,989,000
Effective Income Tax Rate Reconciliation, Other Reconciling Items, Amount	1,000,000
Proceeds from income tax refunds	5,900,000	5,500,000
Reconciliation of unrecognized tax benefits [Roll Forward]
Unrecognized tax benefits, Beginning balance	446,000	446,000	$ 2,782,000
Unrecognized tax benefits, additions for tax positions of prior years	0	0	9,000
Unrecognized tax benefits, settlements	0	0	(2,345,000)
Unrecognized tax benefits, Ending balance	$ 446,000	446,000	$ 446,000
Tax year 2017 [Member]
Deferred income taxes [Abstract]
Federal enacted statutory income tax rate, percent	35.00%
Future tax years [Member]
Deferred income taxes [Abstract]
Federal enacted statutory income tax rate, percent	21.00%
State and local jurisdiction [Member]
Deferred income taxes [Abstract]
Current state income tax payable	$ 1,331,000	3,009,000
Net operating loss carryforwards	79,700,000
State tax credits [Member] | State and local jurisdiction [Member]
Deferred income taxes [Abstract]
Tax credit carryforwards	212,000
Internal Revenue Service (IRS) [Member] | Domestic tax authority [Member]
Deferred income taxes [Abstract]
Current federal income tax refundable	59,000	$ 37,000
Net operating loss carryforwards	2,300,000
Internal Revenue Service (IRS) [Member] | R&D tax credit carryforwards [Member] | Domestic tax authority [Member]
Deferred income taxes [Abstract]
Tax credit carryforwards	7,400,000
Internal Revenue Service (IRS) [Member] | Alternative minimum tax credit carryforward [Member] | Domestic tax authority [Member]
Deferred income taxes [Abstract]
Tax credit carryforwards	$ 15,600,000

Income Taxes Reconciliation of

Income Taxes Reconciliation of Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Federal statutory tax benefit	$ 136,873	$ (120,335)	$ (420,671)
Federal tax reform changes - 2017 Tax Act	0	(63,675)	0
State tax benefit (net of federal benefit)	2,771	(3,286)	(17,549)
Change in valuation allowance	105	(2,727)	(5,059)
Employee share based compensation	2,508	8,190	0
Other	1,113	(1,137)	(893)
Total income tax expense (benefit)	$ 143,370	$ (182,970)	$ (444,172)

Long-term Debt Revolving Credit

Long-term Debt Revolving Credit Facility (Details) $ in Thousands		12 Months Ended
		Dec. 31, 2018USD ($)		Feb. 07, 2019USD ($)	Dec. 31, 2017USD ($)
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
Credit facility balance		$ 0			$ 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		1,500,000
Line of credit agreement, aggregate lender commitments		1,000,000			925,000
Credit facility balance	[1]	0			0
Letters of credit outstanding, amount		200	[2]		200
Available borrowing capacity		999,800			924,800
Credit facility, unamortized deferred financing costs		$ 6,400			$ 3,100
Subsequent Event [Member] | Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, aggregate lender commitments				$ 1,000,000
Credit facility balance				0
Letters of credit outstanding, amount	[2]			0
Available borrowing capacity				$ 1,000,000
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		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		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		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		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		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
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
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
[1]	(1) Unamortized deferred financing costs attributable to the credit facility are presented as a component of other noncurrent assets on the accompanying balance sheets and totaled $6.4 million and $3.1 million as of December 31, 2018, and 2017, 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.

Long-term Debt Senior Notes (De

Long-term Debt Senior Notes (Details) - USD ($) $ in Thousands	Aug. 20, 2018	Jul. 16, 2018	Jun. 15, 2018	Sep. 12, 2016	May 21, 2015	Nov. 17, 2014	May 20, 2013	Sep. 30, 2018	Mar. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Senior Notes [Line Items]
Principal amount, net of unamortized deferred financing costs										$ 2,448,439	$ 2,769,663
Gain (loss) on extinguishment of debt										(26,740)	(35)	$ 15,722
Loss on extinguishment of debt, acceleration of unamortized deferred financing costs										$ 6,334	22	(15,722)
6.50% Senior Notes Due 2021 [Member]
Senior Notes [Line Items]
Senior Notes, interest rate, stated percentage										6.50%
Principal amount										$ 0	344,611
Unamortized deferred financing costs										0	(2,656)
Principal amount, net of unamortized deferred financing costs										0	341,955
Senior Notes, repurchased face amount			$ 344,611
Premiums paid for extinguishment of debt										7,500
Senior Notes repurchased, settlement amount		$ 355,900
Gain (loss) on extinguishment of debt										9,800
Loss on extinguishment of debt, acceleration of unamortized deferred financing costs										$ 2,300
Senior Notes, redemption price, percentage			102.167%
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	561,796
Unamortized deferred financing costs										(3,921)	(5,800)
Principal amount, net of unamortized deferred financing costs										$ 472,875	555,996
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
6.50% Senior Notes Due 2023 [Member]
Senior Notes [Line Items]
Senior Notes, interest rate, stated percentage										6.50%
Principal amount										$ 0	394,985
Unamortized deferred financing costs										0	(3,707)
Principal amount, net of unamortized deferred financing costs										$ 0	391,278
Senior Notes, repurchased face amount								394,985	5,000
Senior Notes repurchased, settlement amount								408,300	3,300
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										(4,688)	(5,610)
Principal amount, net of unamortized deferred financing costs										$ 495,312	494,390
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										(5,808)	(6,714)
Principal amount, net of unamortized deferred financing costs										$ 494,192	493,286
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										(6,407)	(7,242)
Principal amount, net of unamortized deferred financing costs										$ 493,593	492,758
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	0
Unamortized deferred financing costs										(7,533)	0
Principal amount, net of unamortized deferred financing costs										492,467	0
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	2,801,392
Unamortized deferred financing costs										(28,357)	(31,729)
Principal amount, net of unamortized deferred financing costs										2,448,439	$ 2,769,663
Senior Notes, repurchased face amount									46,300
Senior Notes repurchased, settlement amount									$ 29,900
Gain (loss) on extinguishment of debt												15,700
Senior Notes repurchased, discount												16,400
Loss on extinguishment of debt, acceleration of unamortized deferred financing costs												$ 700
6.125% Senior Notes Due 2022 and 6.50% Senior Notes Due 2023 [Member]
Senior Notes [Line Items]
Premiums paid for extinguishment of debt										12,900
Senior Notes repurchased, settlement amount								$ 497,800
Gain (loss) on extinguishment of debt										16,900
Loss on extinguishment of debt, acceleration of unamortized deferred financing costs										$ 4,000

Long-term Debt Senior Convertib

Long-term Debt Senior Convertible Notes (Details) - USD ($)	Aug. 12, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Senior Convertible Notes [Line Items]
Senior Convertible Notes, net proceeds	$ 166,600,000
Senior Convertible Notes, net carrying amount		$ 147,894,000	$ 139,107,000
Capped call transaction costs				$ 24,200,000
Capped Call, Cap Price	$ 60
Capitalized interest costs		20,600,000	12,600,000	17,000,000
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%
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		$ 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	$ 40,217,000	$ 40,217,000	40,217,000
Senior Convertible Notes, interest expense		10,500,000	9,900,000	$ 3,700,000
Senior Convertible Notes, unamortized debt discount		(22,313,000)	(30,183,000)
Unamortized deferred financing costs		(2,293,000)	(3,210,000)
Senior Convertible Notes, net carrying amount		147,894,000	139,107,000
Senior Convertible Notes, related issuance costs, equity component		(1,375,000)	(1,375,000)
Senior Convertible Notes, deferred tax liability, equity component		(5,267,000)	(5,267,000)
Senior Convertible Notes, net carrying amount, equity component		$ 33,575,000	$ 33,575,000

Commitments (Details)

Commitments (Details) Bcf in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)MMBblsBcf	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Commitments and Contingencies
Contractual obligation, due in next fiscal year	$ 132,502
Contractual obligation, due in second year	103,169
Contractual obligation, due in third year	88,785
Contractual obligation, due in fourth year	70,741
Contractual obligation, due in fifth year	37,334
Contractual obligation, due after fifth year	24,931
Contractual obligation	457,462
Minimum [Member]
Commitments and Contingencies
Potential Penalty for not Meeting Minimum Drilling and Completion Requirements	0
Maximum [Member]
Commitments and Contingencies
Potential Penalty for not Meeting Minimum Drilling and Completion Requirements	$ 60,000
Crude oil pipeline commitment [Member]
Commitments and Contingencies
Oil and gas delivery commitments, remaining minimum contractual volumes | MMBbls	29
Natural gas pipeline commitment [Member]
Commitments and Contingencies
Oil and gas delivery commitments, remaining minimum contractual volumes | Bcf	595
Crude Oil Pipeline Commitment Excluded from Remaining Deficiency Payment Amount [Member]
Commitments and Contingencies
Oil and gas delivery commitments, remaining minimum contractual volumes | MMBbls	18.6
Drilling rig leasing contracts [Member]
Commitments and Contingencies
Contractual obligation	$ 86,900
Early Termination Penalty for Rig Contract Cancellation	45,900
Expenses related to early contract termination	0	$ 0	$ 8,700
Pipeline transportation commitments [Member]
Commitments and Contingencies
Contractual obligation	287,800
Office space leases [Member]
Commitments and Contingencies
Contractual obligation	35,500
Expenses related to early contract termination	1,300		3,200
Operating leases, rent expense, net of sublease income	4,500	$ 4,800	$ 5,200
Other miscellaneous contracts and leases [Member]
Commitments and Contingencies
Contractual obligation	18,300
Electricity purchase agreement [Member]
Commitments and Contingencies
Contractual obligation	$ 29,000
Water pipeline commitment [Member]
Commitments and Contingencies
Water delivery commitments, remaining minimum contractual volumes | MMBbls	21

Compensation Plans_ Stock Based

Compensation Plans: Stock Based (Details) $ / shares in Units, $ in Millions		Dec. 31, 2018USD ($)$ / sharesshares	Dec. 31, 2018USD ($)shares$ / shares	Dec. 31, 2017USD ($)$ / sharesshares	Dec. 31, 2016USD ($)$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares of common stock available for grant		5,900,000	5,900,000
Impact outright issuance of one share has on number of available shares			1
Director [Member]
Director Shares
Stock Issued During Period, Shares, Share-based Compensation, Gross			63,741	71,573	53,473
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	0.2
Award vesting period		3 years
Stock-based compensation expense | $			$ 10.3	$ 9.7	$ 11
Unrecognized stock based compensation expense | $		$ 19	$ 19
Multiplier assumed			1
Fair value of PSUs/RSUs granted in period | $			$ 14	$ 15.5	$ 11.9
Performance Share Units Shares Settled Gross of Shares for Tax Withholdings	[1]				44,870
Shares held for settlement of income and payroll tax obligations (in shares)					(14,809)
Shares Issued in Period			0	0	30,061
Fair value of PSUs/RSUs Vested in Period | $			$ 10.3	$ 8.1	$ 8.4
Weighted Average Grant Date Fair Value
Non-vested at beginning of year (in shares)	[2]		1,533,491	828,923	626,328
Granted (in shares)	[2]		572,924	977,731	447,971
Vested (in shares)	[2]		(233,102)	(94,338)	(130,353)
Forfeited (in shares)	[2]		(162,054)	(178,825)	(115,023)
Non-vested at end of year (in shares)	[2]	1,711,259	1,711,259	1,533,491	828,923
Non-vested outstanding at the beginning of the period (in dollars per share) | $ / shares			$ 22.97	$ 43.25	$ 61.81
Granted (in dollars per share) | $ / shares			24.45	15.86	26.56
Vested (in dollars per share) | $ / shares			44.25	85.85	64.17
Forfeited (in dollars per share) | $ / shares			21.79	44.99	55.59
Non-vested outstanding at the end of the period (in dollars per share) | $ / shares		$ 20.68	$ 20.68	$ 22.97	$ 43.25
Director Shares
Shares held for settlement of income and payroll tax obligations (in shares)					(14,809)
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]
Stock-based compensation expense | $			$ 10.8	$ 10.3	$ 11.9
Unrecognized stock based compensation expense | $		$ 20	20
Fair value of PSUs/RSUs granted in period | $			$ 15	$ 17	$ 11.7
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vesting Increment			0.33	0.33	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	[3]		407,529	246,025	241,363
Shares held for settlement of income and payroll tax obligations (in shares)			(115,784)	(74,747)	(72,181)
Shares Issued in Period			291,745	171,278	169,182
Fair value of PSUs/RSUs Vested in Period | $			$ 9.9	$ 10.8	$ 14
Number of Shares Represented by Each RSU			1
Weighted Average Grant Date Fair Value
Non-vested at beginning of year (in shares)			1,244,262	604,116	543,737
Granted (in shares)			583,552	1,020,780	417,065
Vested (in shares)			(407,529)	(246,025)	(241,363)
Forfeited (in shares)			(177,122)	(134,609)	(115,323)
Non-vested at end of year (in shares)		1,243,163	1,243,163	1,244,262	604,116
Non-vested outstanding at the beginning of the period (in dollars per share) | $ / shares			$ 20.25	$ 37.39	$ 55.01
Granted (in dollars per share) | $ / shares			25.77	16.64	28.08
Vested (in dollars per share) | $ / shares			24.30	43.99	58.06
Forfeited (in dollars per share) | $ / shares			17.26	26.38	43.52
Non-vested outstanding at the end of the period (in dollars per share) | $ / shares		$ 21.50	$ 21.50	$ 20.25	$ 37.39
Director Shares
Shares held for settlement of income and payroll tax obligations (in shares)			(115,784)	(74,747)	(72,181)
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 | $			$ 1.7	$ 1.6	$ 2
[1]	(1) During the year ended December 31, 2016, the Company issued shares of common stock to settle PSUs that related to awards granted in 2013. 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.
[2]	(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.
[3]	(1) During the years ended December 31, 2018, 2017, and 2016, 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, 2018	Dec. 31, 2017	Dec. 31, 2016
Compensation plans
Number of shares of common stock available for grant	5,900,000
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	1,600,000
Issuance of common stock under Employee Stock Purchase Plan (in shares)	199,464	186,665	218,135
Proceeds from issuance of shares under incentive and share-based compensation plans, excluding stock options	$ 3,200,000	$ 2,600,000	$ 4,200,000
Risk free interest rate	1.80%	0.90%	0.40%
Dividend yield	0.40%	0.50%	0.40%
Volatility factor of the expected market price of the Company's common stock	55.90%	62.50%	95.00%
Expected life (in years)	6 months	6 months	6 months
Stock-based compensation expense	$ 1,100,000	$ 1,000,000	$ 2,000,000

Compensation Plans Non Stock-Ba

Compensation Plans Non Stock-Based Compensation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Net Profits Plan [Member]
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Minimum percentage of oil and gas wells, costs recovered for payment to employees from Net Profit Plan	100.00%
Percentage of future net cash flow received by participants from Net Profit Plan	10.00%
Percentage of future net cash flow received by participants from Net Profit Plan increased to	20.00%
Percentage of oil and gas wells costs recovered for additional payment employees from Net Profit Plan	200.00%
Cash payments made or accrued related to operations	$ 63	$ (54)	$ 6,608
Cash payments made or accrued related to divestitures	0	2,753	24,349
Total net settlements	$ 63	2,699	30,957
401K Plan [Member]
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	$ 4,900	$ 4,500	$ 5,400
Prior to 2014 [Member] | 401K Plan [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] | 401K Plan [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, 2018	Dec. 31, 2017	Dec. 31, 2016	Jan. 01, 2018
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Projected benefit obligation at beginning of year		$ 71,937,000	$ 69,659,000
Defined Benefit Plan, service cost		6,730,000	6,638,000	$ 8,200,000
Defined Benefit Plan, interest cost		2,622,000	2,689,000	2,908,000
Defined Benefit Plan, actuarial (gain) loss		(7,155,000)	3,708,000
Defined Benefit Plan, benefits paid		(8,048,000)	(10,757,000)
Projected benefit obligation at end of year		66,086,000	71,937,000	69,659,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, fair value of plan assets at beginning of year		30,978,000	31,731,000
Defined Benefit Plan, actual return on plan assets		(964,000)	2,956,000
Defined Benefit Plan, employer contribution		8,134,000	7,048,000	11,000,000
Defined Benefit Plan, benefits paid		(8,048,000)	(10,757,000)	(6,700,000)
Defined Benefit Plan, fair value of plan assets at end of year		30,100,000	30,978,000	31,731,000
Defined Benefit Plan, funded status at end of year		(35,986,000)	(40,959,000)
Defined Benefit Plan, Plan with Accumulated Benefit Obligation in Excess of Plan Assets [Abstract]
Defined Benefit Plan, projected benefit obligation		66,086,000	71,937,000
Defined Benefit Plan, accumulated benefit obligation		52,368,000	56,045,000
Defined Benefit Plan, fair value of plan assets		30,100,000	30,978,000
Defined Benefit Plan, unfunded accumulated benefit obligation		$ 22,268,000	25,067,000
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		$ 15,741,000	21,397,000
Defined Benefit Plan, unrecognized prior service costs		48,000	66,000
Defined Benefit Plan, accumulated other comprehensive loss		15,789,000	21,463,000
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Other Comprehensive Income (Loss), Defined Benefit Plan, net actuarial gain (loss)		4,329,000	(2,995,000)	(3,322,000)
Other Comprehensive Income (Loss), Defined Benefit Plan, amortization of prior service cost		18,000	17,000	16,000
Other Comprehensive Income (Loss), Defined Benefit Plan, amortization of net actuarial loss		1,327,000	1,297,000	1,582,000
Other Comprehensive Income (Loss), Defined Benefit Plan, settlements		0	3,009,000	0
Other Comprehensive Income (Loss), Defined Benefit Plan, total pension liability adjustment, pre-tax		5,674,000	1,328,000	(1,724,000)
Other Comprehensive Income (Loss), Defined Benefit Plan, tax (expense) benefit		(4,265,000)	(561,000)	570,000
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]	(4,378,000)	(767,000)	1,154,000
Components of Net Periodic Benefit Costs for Both Pension Plans
Defined Benefit Plan, service cost		6,730,000	6,638,000	8,200,000
Defined Benefit Plan, interest cost		2,622,000	2,689,000	2,908,000
Defined Benefit Plan, expected return on plan assets that reduces periodic pension benefit cost		(1,862,000)	(2,244,000)	(2,235,000)
Defined Benefit Plan, amortization of prior service cost		18,000	17,000	16,000
Defined Benefit Plan, amortization of net actuarial loss		1,327,000	1,297,000	1,582,000
Defined Benefit Plan, settlements		0	3,009,000	0
Defined Benefit Plan, net periodic benefit cost		$ 8,835,000	$ 11,406,000	$ 10,471,000
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation and Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, discount rate		4.40%	3.80%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, rate of compensation increase		6.20%	6.20%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, discount rate		3.80%	4.20%	4.70%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, expected return on plan assets	[3]	5.50%	6.50%	7.50%
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		$ 4,000,000
Future Benefit Payments
Defined Benefit Plan, Expected Future Benefit Payments in Year One		5,429,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Two		5,066,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Three		4,913,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Four		5,715,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Five		7,693,000
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter		30,400,000
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		$ 11,897,000
Defined Benefit Plan, fair value of plan assets at end of year		9,580,000	$ 11,897,000
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		12,325,000
Defined Benefit Plan, fair value of plan assets at end of year		12,420,000	12,325,000
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		6,756,000
Defined Benefit Plan, fair value of plan assets at end of year		8,100,000	6,756,000
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	[4]	$ 2,969,000	$ 0	$ 0	$ (2,969,000)
[1]	(1) 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) 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, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		100.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	[1]	100.00%	100.00%
Defined Benefit Plan, Plan Assets, Amount		$ 30,100,000	$ 30,978,000	$ 31,731,000
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, expected return on plan assets	[2]	5.50%	6.50%	7.50%
Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		$ 19,259,000	$ 21,524,000
Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		5,334,000	4,245,000
Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		5,507,000	5,209,000	$ 5,214,000
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases		0	300,000
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Realized Gain on Assets		191,000	130,000
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Unrealized Gain on Assets		152,000	120,000
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Disposition		$ (45,000)	$ (555,000)
Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	[1]	0.00%	0.00%
Defined Benefit Plan, Plan Assets, Amount		$ 0	$ 0
Cash [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0	0
Cash [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0	0
Cash [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		$ 0	$ 0
Domestic equity securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	[1],[3]	15.40%	22.20%
Defined Benefit Plan, Plan Assets, Amount	[3]	$ 4,639,000	$ 6,865,000
Domestic equity securities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[3]	3,197,000	4,805,000
Domestic equity securities [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[3]	1,442,000	2,060,000
Domestic equity securities [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[3]	$ 0	$ 0
International equity securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	[1],[4]	16.40%	16.20%
Defined Benefit Plan, Plan Assets, Amount	[4]	$ 4,941,000	$ 5,032,000
International equity securities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[4]	3,642,000	3,806,000
International equity securities [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[4]	1,299,000	1,226,000
International equity securities [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[4]	$ 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	[1]	31.80%	38.40%
Defined Benefit Plan, Plan Assets, Amount		$ 9,580,000	$ 11,897,000
Total equity securities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		6,839,000	8,611,000
Total equity securities [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		2,741,000	3,286,000
Total equity securities [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		$ 0	$ 0
High-yield bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	[1],[5]	0.00%	2.80%
Defined Benefit Plan, Plan Assets, Amount	[5]	$ 0	$ 876,000
High-yield bonds [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[5]	0	876,000
High-yield bonds [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[5]	0	0
High-yield bonds [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[5]	$ 0	$ 0
Core fixed income [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	[1],[6]	34.40%	28.60%
Defined Benefit Plan, Plan Assets, Amount	[6]	$ 10,342,000	$ 8,842,000
Core fixed income [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[6]	10,342,000	8,842,000
Core fixed income [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[6]	0	0
Core fixed income [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[6]	$ 0	$ 0
Floating rate corporate loans [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	[1],[7]	6.90%	8.40%
Defined Benefit Plan, Plan Assets, Amount	[7]	$ 2,078,000	$ 2,607,000
Floating rate corporate loans [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[7]	2,078,000	2,607,000
Floating rate corporate loans [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[7]	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	[7]	$ 0	$ 0
Total fixed income securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		43.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	[1]	41.30%	39.80%
Defined Benefit Plan, Plan Assets, Amount		$ 12,420,000	$ 12,325,000
Total fixed income securities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		12,420,000	12,325,000
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
Commodities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	[1],[8]	0.00%	1.90%
Defined Benefit Plan, Plan Assets, Amount	[8]	$ 0	$ 588,000
Commodities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[8]	0	588,000
Commodities [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[8]	0	0
Commodities [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[8]	$ 0	$ 0
Real estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	[1],[9]	6.00%	5.60%
Defined Benefit Plan, Plan Assets, Amount	[9]	$ 1,820,000	$ 1,735,000
Real estate [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[9]	0	0
Real estate [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[9]	0	0
Real estate [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[9]	$ 1,820,000	$ 1,735,000
Collective investment trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	[1],[10]	3.10%	3.10%
Defined Benefit Plan, Plan Assets, Amount	[10]	$ 934,000	$ 959,000
Collective investment trusts [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[10]	0	0
Collective investment trusts [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[10]	934,000	959,000
Collective investment trusts [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[10]	$ 0	$ 0
Hedge fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	[1],[11]	17.80%	11.20%
Defined Benefit Plan, Plan Assets, Amount	[11]	$ 5,346,000	$ 3,474,000
Hedge fund [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[11]	0	0
Hedge fund [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[11]	1,659,000	0
Hedge fund [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[11]	$ 3,687,000	$ 3,474,000
Total other securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		22.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	[1]	26.90%	21.80%
Defined Benefit Plan, Plan Assets, Amount		$ 8,100,000	$ 6,756,000
Total other securities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0	588,000
Total other securities [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		2,593,000	959,000
Total other securities [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		5,507,000	5,209,000
Nonqualified Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		$ 0	$ 0	$ 0
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, expected return on plan assets		0.00%	0.00%	0.00%
[1]	(1) Percentages may not calculate due to rounding.
[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.
[3]	(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.
[4]	(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.
[5]	(4) High-yield bonds consist of non-investment grade fixed income securities. The investment objective is to obtain high current income. Due to the increased level of default risk, security selection focuses on credit-risk analysis.
[6]	(5) 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.
[7]	(6) 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.
[8]	(7) Investments with exposure to commodity price movements, primarily through the use of futures, swaps, and other commodity-linked securities.
[9]	(8) 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.
[10]	(9) 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.
[11]	(10) 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, 2018USD ($)$ / shares	Dec. 31, 2018USD ($)$ / sharesshares	Dec. 31, 2017USD ($)$ / sharesshares	Dec. 31, 2016USD ($)$ / sharesshares	Aug. 12, 2016USD ($)$ / shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Capped Call, Cap Price | $ / shares					$ 60
Dilutive effect of non-vested RSUs and contingent PSUs		1,590	0	0
Anti-dilutive shares excluded from earnings per share		0	264	280
Earnings Per Share Reconciliation [Abstract]
Net income (loss) | $		$ 508,407	$ (160,843)	$ (757,744)
Basic weighted-average common shares outstanding		111,912	111,428	76,568
Dilutive effect of Senior Convertible Notes		0	0	0
Diluted weighted-average common shares outstanding		113,502	111,428	76,568
Basic net income (loss) per common share | $ / shares		$ 4.54	$ (1.44)	$ (9.90)
Diluted net income (loss) per common share | $ / shares		$ 4.48	$ (1.44)	$ (9.90)
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	0.2
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
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

Derivative Financial Instrume_3

Derivative Financial Instruments (Details) bbl in Thousands, BTU in Billions	Dec. 31, 2018BTU$ / EnergyContent$ / Barrelsbbl
NYMEX Oil Swap Contract First Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	826
Derivative, Swap Type, Average Fixed Price | $ / Barrels	60.16
NYMEX Oil Swap Contract Second Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	575
Derivative, Swap Type, Average Fixed Price | $ / Barrels	55.52
NYMEX Oil Swap Contract Third Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	1,217
Derivative, Swap Type, Average Fixed Price | $ / Barrels	61.41
NYMEX Oil Swap Contract Fourth Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	1,115
Derivative, Swap Type, Average Fixed Price | $ / Barrels	59.97
NYMEX Oil Swap Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	2,491
Derivative, Swap Type, Average Fixed Price | $ / Barrels	65.68
NYMEX Oil Swap Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	6,224
NYMEX Oil Collar Contract First Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	2,503
Derivative, Floor Price | $ / Barrels	51.66
Derivative, Ceiling Price | $ / Barrels	64.32
NYMEX Oil Collar Contract Second Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	2,802
Derivative, Floor Price | $ / Barrels	52.18
Derivative, Ceiling Price | $ / Barrels	64.61
NYMEX Oil Collar Contract Third Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	2,364
Derivative, Floor Price | $ / Barrels	49.07
Derivative, Ceiling Price | $ / Barrels	62.67
NYMEX Oil Collar Contract Fourth Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	2,386
Derivative, Floor Price | $ / Barrels	49.08
Derivative, Ceiling Price | $ / Barrels	62.65
NYMEX Oil Collar Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	1,165
Derivative, Floor Price | $ / Barrels	55
Derivative, Ceiling Price | $ / Barrels	66.47
NYMEX Oil Collar Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	11,220
WTI Midland NYMEX WTI [Member] | Oil Basis Swap Contract First Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	2,433
Derivative, Weighted-Average Contract Price | $ / Barrels	(4.44)	[1]
WTI Midland NYMEX WTI [Member] | Oil Basis Swap Contract Second Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	2,571
Derivative, Weighted-Average Contract Price | $ / Barrels	(4.49)	[1]
WTI Midland NYMEX WTI [Member] | Oil Basis Swap Contract Third Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	3,291
Derivative, Weighted-Average Contract Price | $ / Barrels	(2.86)	[1]
WTI Midland NYMEX WTI [Member] | Oil Basis Swap Contract Fourth Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	3,338
Derivative, Weighted-Average Contract Price | $ / Barrels	(2.87)	[1]
WTI Midland NYMEX WTI [Member] | Oil Basis Swap Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	11,601
Derivative, Weighted-Average Contract Price | $ / Barrels	(1.03)	[1]
WTI Midland NYMEX WTI [Member] | Oil Basis Swap Contract 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	0
Derivative, Weighted-Average Contract Price | $ / Barrels	0	[1]
WTI Midland NYMEX WTI [Member] | Oil Basis Swap Contract 2022 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	0
Derivative, Weighted-Average Contract Price | $ / Barrels	0	[1]
WTI Midland NYMEX WTI [Member] | Oil Basis Swap [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	23,234
NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract First Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	0
Derivative, Weighted-Average Contract Price | $ / Barrels	0	[2]
NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract Second Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	0
Derivative, Weighted-Average Contract Price | $ / Barrels	0	[2]
NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract Third Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	0
Derivative, Weighted-Average Contract Price | $ / Barrels	0	[2]
NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract Fourth Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	0
Derivative, Weighted-Average Contract Price | $ / Barrels	0	[2]
NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	2,750
Derivative, Weighted-Average Contract Price | $ / Barrels	(8.03)	[2]
NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	3,650
Derivative, Weighted-Average Contract Price | $ / Barrels	(7.86)	[2]
NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract 2022 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	3,650
Derivative, Weighted-Average Contract Price | $ / Barrels	(7.78)	[2]
NYMEX WTI ICE Brent [Member] | Oil Basis Swap [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	10,050
IF HSC [Member]
Derivative Financial Instruments
Index percent of natural gas fixed swaps	86.00%
IF HSC [Member] | Gas Swaps Contract First Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent	2.99
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU	19,805
IF HSC [Member] | Gas Swaps Contract Second Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent	2.82
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU	10,439
IF HSC [Member] | Gas Swaps Contract Third Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent	2.82
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU	12,531
IF HSC [Member] | Gas Swaps Contract Fourth Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent	2.88
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU	14,433
IF HSC [Member] | Gas Swaps Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent	2.98
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU	9,123
IF HSC [Member] | Gas Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU	66,331	[3]
IF HSC [Member] | Gas Collar Contract First Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Floor Price | $ / EnergyContent	0
Derivative, Ceiling Price | $ / EnergyContent	0
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU	0
IF HSC [Member] | Gas Collar Contract Second Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Floor Price | $ / EnergyContent	2.50
Derivative, Ceiling Price | $ / EnergyContent	2.83
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU	4,358
IF HSC [Member] | Gas Collar Contract Third Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Floor Price | $ / EnergyContent	2.50
Derivative, Ceiling Price | $ / EnergyContent	2.83
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU	5,066
IF HSC [Member] | Gas Collar Contract Fourth Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Floor Price | $ / EnergyContent	2.50
Derivative, Ceiling Price | $ / EnergyContent	2.83
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU	4,818
IF HSC [Member] | Gas Collar Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU	14,242
WAHA [Member] | Gas Swaps Contract First Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent	0
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU	0
WAHA [Member] | Gas Swaps Contract Second Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent	0.69
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU	2,803
WAHA [Member] | Gas Swaps Contract Third Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent	1.28
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU	2,984
WAHA [Member] | Gas Swaps Contract Fourth Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent	1.75
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU	2,962
WAHA [Member] | Gas Swaps Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent	2.20
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU	2,060
WAHA [Member] | Gas Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU	10,809	[3]
IF Waha [Member]
Derivative Financial Instruments
Index percent of natural gas fixed swaps	4.00%
GD Waha [Member]
Derivative Financial Instruments
Index percent of natural gas fixed swaps	10.00%
OPIS Purity Ethane Mont Belvieu [Member] | NGL Swaps Contract First Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	853
Derivative, Swap Type, Average Fixed Price | $ / Barrels	12.25
OPIS Purity Ethane Mont Belvieu [Member] | NGL Swaps Contract Second Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	877
Derivative, Swap Type, Average Fixed Price | $ / Barrels	12.29
OPIS Purity Ethane Mont Belvieu [Member] | NGL Swaps Contract Third Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	907
Derivative, Swap Type, Average Fixed Price | $ / Barrels	12.34
OPIS Purity Ethane Mont Belvieu [Member] | NGL Swaps Contract Fourth Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	896
Derivative, Swap Type, Average Fixed Price | $ / Barrels	12.36
OPIS Purity Ethane Mont Belvieu [Member] | NGL Swaps Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	539
Derivative, Swap Type, Average Fixed Price | $ / Barrels	11.13
OPIS Purity Ethane Mont Belvieu [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	4,072
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract First Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	540
Derivative, Swap Type, Average Fixed Price | $ / Barrels	28.72
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Second Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	561
Derivative, Swap Type, Average Fixed Price | $ / Barrels	31.32
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	637
Derivative, Swap Type, Average Fixed Price | $ / Barrels	31.29
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	651
Derivative, Swap Type, Average Fixed Price | $ / Barrels	31.64
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	0
Derivative, Swap Type, Average Fixed Price | $ / Barrels	0
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	2,389
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract First Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	38
Derivative, Swap Type, Average Fixed Price | $ / Barrels	35.64
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Second Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	38
Derivative, Swap Type, Average Fixed Price | $ / Barrels	35.64
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	39
Derivative, Swap Type, Average Fixed Price | $ / Barrels	35.64
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	39
Derivative, Swap Type, Average Fixed Price | $ / Barrels	35.64
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	0
Derivative, Swap Type, Average Fixed Price | $ / Barrels	0
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	154
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract First Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	29
Derivative, Swap Type, Average Fixed Price | $ / Barrels	35.70
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Second Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	29
Derivative, Swap Type, Average Fixed Price | $ / Barrels	35.70
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	30
Derivative, Swap Type, Average Fixed Price | $ / Barrels	35.70
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	29
Derivative, Swap Type, Average Fixed Price | $ / Barrels	35.70
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	0
Derivative, Swap Type, Average Fixed Price | $ / Barrels	0
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	117
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract First Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	48
Derivative, Swap Type, Average Fixed Price | $ / Barrels	50.93
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract Second Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	49
Derivative, Swap Type, Average Fixed Price | $ / Barrels	50.93
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	50
Derivative, Swap Type, Average Fixed Price | $ / Barrels	50.93
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	50
Derivative, Swap Type, Average Fixed Price | $ / Barrels	50.93
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	0
Derivative, Swap Type, Average Fixed Price | $ / Barrels	0
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	197
[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, 2018, total volumes for gas swaps are comprised of 86 percent IF HSC, four percent IF Waha, and 10 percent GD Waha.

Derivative Financial Instrume_4

Derivative Financial Instruments Fair Value (Details) $ in Thousands	Dec. 31, 2018USD ($)		Dec. 31, 2017USD ($)		Dec. 31, 2016
Fair value of derivative assets and liabilities
Derivative, Fair Value, Net	$ 158,300		$ (139,400)
Derivative Assets, Current	175,130		64,266
Derivative Assets, Noncurrent	58,499		40,362
Total Derivative Assets	233,629		104,628
Derivative Liabilities, Current	62,853		172,582
Derivative Liabilities, Noncurrent	12,496		71,402
Total Derivative Liabilities	(75,349)		(243,984)
Derivative Asset, Not Offset in the Accompanying Balance Sheets	(56,041)		(100,035)
Derivative Liabilities, Not Offset in the Accompanying Balance Sheets	56,041		100,035
Derivative Asset, Fair Value, Net Amounts	177,588		4,593
Derivative Liability, Fair Value, Net Amounts	19,308		143,949
Not Designated as Hedging Instrument [Member]
Fair value of derivative assets and liabilities
Derivative Assets, Current	175,130		64,266
Derivative Assets, Noncurrent	58,499		40,362
Derivative Liabilities, Current	62,853		172,582
Derivative Liabilities, Noncurrent	12,496		71,402
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Not Designated as Hedging Instrument [Member]
Fair value of derivative assets and liabilities
Total Derivative Assets	233,629	[1]	104,628	[2]
Total Derivative Liabilities	$ (75,349)	[1]	$ (243,984)	[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, 2018	Dec. 31, 2017	Dec. 31, 2016
Derivative Instruments, (Gain) Loss [Line Items]
Derivative settlement (gain) loss	$ 135,803	$ (21,234)	$ (329,478)
Net derivative (gain) loss	(161,832)	26,414	250,633
Oil Contracts [Member]
Derivative Instruments, (Gain) Loss [Line Items]
Derivative settlement (gain) loss	68,860	31,176	(243,102)
Net derivative (gain) loss	(192,002)	71,502	85,370
Gas Contracts [Member]
Derivative Instruments, (Gain) Loss [Line Items]
Derivative settlement (gain) loss	13,029	(87,857)	(94,936)
Net derivative (gain) loss	35,411	(76,315)	81,060
NGL Contracts [Member]
Derivative Instruments, (Gain) Loss [Line Items]
Derivative settlement (gain) loss	53,914	35,447	8,560
Net derivative (gain) loss	$ (5,241)	$ 31,227	$ 84,203

Derivative Financial Instrume_6

Derivative Financial Instruments Credit Facility and Derivative Counterparties (Details)	Dec. 31, 2018
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, 2018		Dec. 31, 2017		Dec. 31, 2016	Aug. 20, 2018	Sep. 12, 2016	May 21, 2015	Nov. 17, 2014	May 20, 2013
Assets:
Derivative Assets, Fair Value, Gross Asset	$ 233,629		$ 104,628
Liabilities:
Derivative Liability, Fair Value, Gross Liability	75,349		243,984
Proved Oil and Gas Properties
Impairment of proved properties	0		3,806		$ 354,614
Abandonment and impairment of unproved properties	$ 49,889		12,272		$ 80,367
6.50% Senior Notes Due 2021 [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Senior Notes, interest rate, stated percentage	6.50%
Debt Instrument, Face Amount	$ 0		344,611
Long-term Debt, Fair Value	$ 0		351,682
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		561,796						$ 600,000
Long-term Debt, Fair Value	$ 452,336		571,627
6.50% Senior Notes Due 2023 [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Senior Notes, interest rate, stated percentage	6.50%
Debt Instrument, Face Amount	$ 0		394,985
Long-term Debt, Fair Value	$ 0		403,434
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	$ 439,265		483,440
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	$ 436,460		494,355
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	$ 448,305		516,350
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		0			$ 500,000
Long-term Debt, Fair Value	$ 442,500		0
1.50% Senior Convertible Notes Due 2021 [Domain]
Debt Instrument, Fair Value Disclosure [Abstract]
Senior Notes, interest rate, stated percentage	1.50%
Debt Instrument, Face Amount	$ 172,500		172,500
Long-term Debt, Fair Value	158,614		168,291
Not Designated as Hedging Instrument [Member] | Fair Value, Measurements, 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, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Assets:
Derivative Assets, Fair Value, Gross Asset	233,629	[1]	104,628	[2]
Liabilities:
Derivative Liability, Fair Value, Gross Liability	75,349	[1]	243,984	[2]
Not Designated as Hedging Instrument [Member] | Fair Value, Measurements, 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, 2018	Dec. 31, 2017	Dec. 31, 2016
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Beginning balance	$ 49,446	$ 19,846	$ 11,952
Additions to capitalized exploratory well costs pending the determination of proved reserves	11,197	49,446	19,846
Divestitures	(109)	0	0
Reclassification to wells, facilities, and equipment based on the determination of proved reserves	(49,337)	(19,846)	(11,952)
Capitalized exploratory well costs charged to expense	0	0	0
Ending balance	11,197	$ 49,446	$ 19,846
Exploratory well costs capitalized for more than one year	$ 0

Equity (Details)

Equity (Details) - USD ($) $ / shares in Units, $ in Thousands, shares in Millions		Dec. 21, 2016	Dec. 07, 2016	Aug. 12, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Class of Stock [Line Items]
Issuance of common stock from stock offerings, shares					0	0
Net proceeds from sale of common stock					$ 3,187	$ 2,623	$ 938,268
August issuance [Member]
Class of Stock [Line Items]
Issuance of common stock from stock offerings, shares				18.4
Issuance of common stock, offering price per share				$ 30
Net proceeds from sale of common stock				$ 530,900
December issuance [Member]
Class of Stock [Line Items]
Issuance of common stock from stock offerings, shares			10.9
Issuance of common stock, offering price per share			$ 38.25
Net proceeds from sale of common stock			$ 403,200
QStar Acquisition 2016 [Member]
Class of Stock [Line Items]
Private issuance of Common Stock for an acquisition		13.4
Fair value of equity consideration	[1]	$ 437,194
[1]	(1) The Company issued approximately 13.4 million shares of common stock, par value $0.01 per share, in a private placement to the sellers in the QStar Acquisition on December 21, 2016. The equity consideration was valued on this date using Level 1 and Level 2 inputs with a discount applied due to the lack of marketability in the near term in accordance with the Lock-Up and Registration Rights Agreement that prohibited the sale of such stock until no earlier than the 90th day after issuance.

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($)		12 Months Ended
		Dec. 31, 2018		Dec. 31, 2017
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning asset retirement obligations		$ 114,470,000	[1],[2]	$ 123,307,000
Liabilities incurred	[3]	4,054,000		7,588,000
Liabilities settled	[4]	(33,024,000)		(30,432,000)
Accretion expense		4,438,000		5,988,000
Revision to estimated cash flows		4,256,000		8,019,000
Ending asset retirement obligations	[1],[2]	94,194,000		114,470,000
Asset retirement obligations associated with oil and gas properties held for sale		0		11,369,000
Current asset retirement obligation liability		$ 2,300,000		$ 75,000
[1]	(3) Balance as of December 31, 2017, included $11.4 million of asset retirement obligations associated with oil and gas properties held for sale.
[2]	(4) Balances as of December 31, 2018, and 2017, included $2.3 million and $75,000, 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.
[3]	(1) Reflects liabilities incurred through drilling activities and acquisitions of drilled wells.
[4]	(2) Reflects liabilities settled through plugging and abandonment activities and divestitures of properties.

Accounts Receivable (Details)

Accounts Receivable (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Accounts Receivable
Accounts receivable	$ 167,536	$ 160,154
Oil, gas, and NGL production revenue [Member]
Accounts Receivable
Accounts receivable	107,230	96,610
Amounts due from joint interest owners [Member]
Accounts Receivable
Accounts receivable	31,497	56,929
State severance tax refunds [Member]
Accounts Receivable
Accounts receivable	4,415	2,276
Derivative settlements [Member]
Accounts Receivable
Accounts receivable	9,475	99
Other [Member]
Accounts Receivable
Accounts receivable	$ 14,919	$ 4,240

Accounts Payable and Accrued Ex

Accounts Payable and Accrued Expenses (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Accounts Payable and Accrued Liabilities, Current [Abstract]
Drilling and lease operating cost accruals	$ 139,711	$ 126,500
Trade accounts payable	56,047	77,573
Revenue and severance tax payable	94,806	60,328
Property taxes	18,694	13,222
Compensation	31,486	39,471
Derivative settlements	1,287	12,644
Interest	40,840	45,057
Other	20,328	11,835
Total accounts payable and accrued expenses	$ 403,199	$ 386,630