SM Energy (SM) 10-K 21 Feb 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information Document - USD ($)	12 Months Ended
	Dec. 31, 2017	Feb. 14, 2018	Jun. 30, 2017
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, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		111,687,016
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 1,825,562,522

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
ASSETS
Cash and cash equivalents	$ 313,943	$ 9,372
Accounts receivable	160,154	151,950
Derivative assets	64,266	54,521
Prepaid expenses and other	10,752	8,799
Total current assets	549,115	224,642
Proved oil and gas properties	6,139,379	5,700,418
Less - accumulated depletion, depreciation, and amortization	(3,171,575)	(2,836,532)
Unproved oil and gas properties	2,047,203	2,471,947
Wells in progress	321,347	235,147
Oil and gas properties held for sale, net	111,700	372,621
Other property and equipment, net of accumulated depreciation of $49,985 and $42,882, respectively	106,738	137,753
Total property and equipment, net	5,554,792	6,081,354
Derivative assets	40,362	67,575
Other noncurrent assets	32,507	19,940
Total other noncurrent assets	72,869	87,515
Total assets	6,176,776	6,393,511
LIABILITIES
Accounts payable and accrued expenses	386,630	299,708
Derivative liabilities	172,582	115,464
Total current liabilities	559,212	415,172
Revolving credit facility	0	0
Senior Notes, net of unamortized deferred financing costs	2,769,663	2,766,719
Senior Convertible Notes, net of unamortized discount and deferred financing costs	139,107	130,856
Asset retirement obligations	103,026	96,134
Asset retirement obligations associated with oil and gas properties held for sale	11,369	26,241
Deferred income taxes	79,989	315,672
Derivative liabilities	71,402	98,340
Other noncurrent liabilities	48,400	47,244
Total noncurrent liabilities	3,222,956	3,481,206
Commitments and contingencies (note 6)
STOCKHOLDERS' EQUITY
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 111,687,016 and 111,257,500 shares, respectively	1,117	1,113
Additional paid-in capital	1,741,623	1,716,556
Retained earnings	665,657	794,020
Accumulated other comprehensive loss	(13,789)	(14,556)
Total stockholders' equity	2,394,608	2,497,133
Total liabilities and stockholders' equity	$ 6,176,776	$ 6,393,511

CONSOLIDATED BALANCE SHEETS Par

CONSOLIDATED BALANCE SHEETS Parenthetical - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Other property and equipment, accumulated depreciation	$ 49,985,000	$ 42,882,000
Common Stock, par value per share	$ 0.01	$ 0.01
Common Stock, Shares Authorized	200,000,000	200,000,000
Common Stock, Shares, Issued	111,687,016	111,257,500
Common Stock, Shares, Outstanding	111,687,016	111,257,500

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating revenues and other income:
Oil, gas, and NGL production revenue	$ 1,253,783	$ 1,178,426	$ 1,499,905
Net gain (loss) on divestiture activity	(131,028)	37,074	43,031
Other operating revenues	6,621	1,950	14,029
Total operating revenues and other income	1,129,376	1,217,450	1,556,965
Operating Expenses:
Oil, gas, and NGL production expense	507,906	597,565	723,633
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	557,036	790,745	921,009
Exploration	56,179	65,641	120,569
Impairment of proved properties	3,806	354,614	468,679
Abandonment and impairment of unproved properties	12,272	80,367	78,643
Impairment of other property and equipment	0	0	49,369
General and administrative	120,585	126,428	157,668
Net derivative (gain) loss	26,414	250,633	(408,831)
Other operating expenses	13,667	10,772	25,009
Total operating expenses	1,297,865	2,276,765	2,135,748
Loss from operations	(168,489)	(1,059,315)	(578,783)
Non-operating income (expense):
Interest expense	(179,257)	(158,685)	(128,149)
Gain (loss) on extinguishment of debt	(35)	15,722	(16,578)
Other, net	3,968	362	649
Loss before income taxes	(343,813)	(1,201,916)	(722,861)
Income tax benefit	182,970	444,172	275,151
Net loss	$ (160,843)	$ (757,744)	$ (447,710)
Earnings Per Share, Basic [Abstract]
Basic weighted-average common shares outstanding	111,428	76,568	67,723
Basic net loss per common share	$ (1.44)	$ (9.90)	$ (6.61)
Earnings Per Share, Diluted [Abstract]
Diluted weighted-average common shares outstanding	111,428	76,568	67,723
Diluted net loss per common share	$ (1.44)	$ (9.90)	$ (6.61)

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
Net loss		$ (160,843)	$ (757,744)	$ (447,710)
Other comprehensive income (loss), net of tax:
Pension liability adjustment	[1]	767	(1,154)	(2,090)
Total other comprehensive income (loss), net of tax		767	(1,154)	(2,090)
Total comprehensive loss		$ (160,076)	$ (758,898)	$ (449,800)
[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 - 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, 2014		67,463,060
Balances, Total stockholders' equity, beginning at Dec. 31, 2014	$ 2,286,655	$ 675	$ 283,295		$ 2,013,997		$ (11,312)
Increase (Decrease) in Stockholders' Equity
Net loss	(447,710)				(447,710)
Other comprehensive income (loss)	(2,090)						(2,090)
Cash dividends, $ 0.10 per share	(6,772)				(6,772)
Issuance of common stock under Employee Stock Purchase Plan (in shares)		197,214
Issuance of common stock under Employee Stock Purchase Plan	4,844	$ 2	4,842
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings (in shares)		375,523
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings	(8,678)	$ 4	(8,682)
Stock-based compensation expense (in shares)		39,903
Stock-based compensation expense	27,467	$ 0	27,467
Adjustments to Additional Paid in Capital, Other	(1,315)		(1,315)
Balances, Common Stock, Shares, Outstanding, Ending at Dec. 31, 2015		68,075,700
Balances, Total stockholders' equity, ending at Dec. 31, 2015	$ 1,852,401	$ 681	305,607		1,559,515		(13,402)
Cash dividends per share	$ 0.10
Increase (Decrease) in Stockholders' Equity
Net 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
Adjustments to Additional Paid in Capital, Other	(9,833)		(9,833)
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)
Balances, Common Stock, Shares, Outstanding, Ending at Dec. 31, 2016	111,257,500	111,257,500
Balances, Total stockholders' equity, ending at Dec. 31, 2016	$ 2,497,133	$ 1,113	1,716,556		794,020		(14,556)
Increase (Decrease) in Stockholders' Equity
Cumulative effect of accounting change	$ 44,732		1,108	[1]	43,624	[1]
Cash dividends per share	$ 0.10
Net 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
Adjustments to Additional Paid in Capital, Other	$ (120)		(120)
Issuance of common stock from stock offerings, net of tax (in shares)	0
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)
[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 - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash flows from operating activities:
Net loss		$ (160,843)	$ (757,744)	$ (447,710)
Adjustments to reconcile net loss to net cash provided by operating activities:
Net (gain) loss on divestiture activity		131,028	(37,074)	(43,031)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion		557,036	790,745	921,009
Exploratory dry hole expense		2,381	(16)	36,612
Impairment of proved properties		3,806	354,614	468,679
Abandonment and impairment of unproved properties		12,272	80,367	78,643
Impairment of other property and equipment		0	0	49,369
Stock-based compensation expense		22,700	26,897	27,467
Net derivative (gain) loss		26,414	250,633	(408,831)
Derivative settlement gain		21,234	329,478	512,566
Amortization of debt discount and deferred financing costs		16,276	9,938	7,710
(Gain) loss on extinguishment of debt		35	(15,722)	16,578
Deferred income taxes		(192,066)	(448,643)	(276,722)
Plugging and abandonment		(2,735)	(6,214)	(7,496)
Other, net		8,239	(3,701)	(5,764)
Changes in current assets and liabilities:
Accounts receivable		13,997	(10,562)	140,200
Prepaid expenses and other		(1,953)	8,478	2,563
Accounts payable and accrued expenses		44,985	(53,210)	(86,267)
Accrued derivative settlements		12,584	34,540	5,232
Net cash provided by operating activities		515,390	552,804	990,807
Cash flows from investing activities:
Net proceeds from the sale of oil and gas properties		776,719	946,062	357,938
Capital expenditures		(888,353)	(629,911)	(1,493,608)
Acquisition of proved and unproved oil and gas properties		(89,896)	(2,183,790)	(7,984)
Other, net		0	0	(985)
Net cash used in investing activities		(201,530)	(1,867,639)	(1,144,639)
Cash flows from financing activities:
Proceeds from credit facility		406,000	947,000	1,872,500
Repayment of credit facility		(406,000)	(1,149,000)	(1,836,500)
Debt issuance costs related to credit facility		0	(3,132)	0
Net proceeds from Senior Notes		0	491,640	490,951
Cash paid to repurchase Senior Notes		(2,344)	(29,904)	(350,000)
Cash paid for extinguishment of debt		13	0	12,455
Net proceeds from Senior Convertible Notes		0	166,617	0
Cash paid for capped call transactions		0	(24,195)	0
Net proceeds from sale of common stock		2,623	938,268	4,844
Dividends paid		(11,144)	(7,751)	(6,772)
Net share settlement from issuance of stock awards		(1,240)	(2,354)	(8,678)
Other, net		(171)	0	(160)
Net cash provided by (used in) financing activities		(12,289)	1,327,189	153,730
Net change in cash, cash equivalents, and restricted cash	[1]	301,571	12,354	(102)
Cash, cash equivalents, and restricted cash at beginning of period	[1]	12,372	18	120
Cash, cash equivalents, and restricted cash at end of period	[1]	313,943	12,372	18
Supplemental schedule of additional cash flow information and non-cash activities:
Cash paid for interest, net of capitalized interest		(164,097)	(129,761)	(126,988)
Net cash (refunded) paid for income taxes		5,986	(4,690)	1,630
Changes in capital expenditure accruals and other		7,309	8,044	(210,819)
Carrying value of properties exchanged		293,963	733	0
Issuance of common stock for an asset acquisition	[2]	0	437,194	0
Non-cash (gain) loss on extinguishment of debt, net		$ 22	$ (15,722)	$ 4,123
[1]	(1) Refer to Note 1 – Summary of Significant Accounting Policies for a reconciliation of cash, cash equivalents, and restricted cash reported to the amounts reported within the accompanying balance sheets.
[2]	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, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Summary of Significant Accounting Policies [Text Block]	Note 1 – Summary of Significant Accounting Policies Description of Operations SM Energy Company 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 its wholly-owned subsidiaries 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 subsequent events after the balance sheet date of December 31, 2017 , 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 consist mainly of receivables from oil, gas, and NGL purchasers and from joint interest owners on properties the Company operates. For receivables from joint interest owners, the Company typically 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 two months and the Company has had minimal bad debts. Although diversified among many companies, collectability 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 2 – 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, 2017 2016 2015 Major customer #1 (1) 10 % 5 % 4 % Major customer #2 (2) 7 % 18 % 21 % Group #1 of entities under common ownership (3) 17 % 15 % 10 % Group #2 of entities under common ownership (3) 8 % 8 % 11 % ____________________________________________ (1) This major customer is a purchaser of the Company’s production from its Permian region. (2) This major customer was the operator of the Company’s outside-operated Eagle Ford shale program, which was divested of during the first quarter of 2017. Prior to the divestiture, the Company was party to various marketing agreements, which included certain gathering, transportation, and processing throughput commitments. Because the Company shared with the operator the risk of non-performance by its counterparty purchasers, the Company included the operator as a major customer in the table above. Several of the operator’s counterparty purchasers under these contracts were also direct purchasers of the Company’s production from other areas. (3) In the aggregate these groups of entities under common ownership represent more than 10 percent of total oil, gas, and NGL production revenue for the period(s) shown, however, none of the individual entities 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 costs, including lease and well equipment and intangible development costs, are depleted as a group of assets (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 the carrying costs may not be recoverable. Expected future discounted cash flows are calculated on all estimated proved reserves and risk-adjusted probable and possible reserves using discount rates and price forecasts that management believes are representative of current market conditions. 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, adjusted for basis differentials, 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. Please refer to Note 11 – Fair Value Measurements for additional discussion. 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. When successful wells are drilled on unproved leases, unproved property costs allocated to those leases are reclassified to proved properties and depleted on a units-of-production basis. An impairment is recorded on unproved property when the Company determines that either the property will not be developed or the carrying value is not realizable. Please refer to Note 11 – Fair Value Measurements for additional discussion. 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 G&G, 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 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 where appropriate. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts. A long-lived asset is evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. The Company uses an income valuation technique if there is not a market-observable price for the asset. Please refer to Note 11 – Fair Value Measurements for additional discussion. 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. Please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions and Note 11 – Fair Value Measurements for additional discussion. 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 and 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 changes in inflation factors or the Company’s credit-adjusted risk-free rate as market conditions warrant. Please refer to Note 9 – Asset Retirement Obligations for a reconciliation of the Company’s total asset retirement obligation liability as of December 31, 2017 , and 2016 . Derivative Financial Instruments The Company seeks to manage or reduce commodity price risk on its production by entering into derivative contracts. The Company seeks to minimize its basis risk and indexes its oil derivative contracts to NYMEX prices, its NGL derivative contracts to OPIS prices, and its gas derivative contracts to various regional index prices associated with pipelines into which the Company’s gas production is sold. 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. 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 when the Company’s production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production. No revenue is recognized unless it is determined that title to the product has transferred to the purchaser. At the end of each month, the Company estimates the amount of production delivered to the purchaser and the price the Company will receive. The Company uses knowledge of its properties and historical performance, contractual agreements, NYMEX, OPIS, and local spot market prices, quality and transportation differentials, and other factors as the basis for these estimates. The Company follows the sales method of accounting for gas production imbalances. If the Company’s sales volumes for a well exceed the Company’s proportionate share of production from the well, a liability is recognized to the extent that the Company’s share of estimated remaining recoverable reserves from the well is insufficient to satisfy this imbalance. Effective January 1, 2018, the Company’s revenue recognition policy changed due to the adoption of new accounting guidance. Please refer to Recently Issued Accounting Standards below for additional discussion. Stock-Based Compensation At December 31, 2017 , the Company had stock-based employee compensation plans that included RSUs and 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 included within general and administrative expense and exploration expense in the accompanying statements of operations. 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 Basic net income (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 (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 year ended December 31, 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 (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 , 2016 , and 2015 , all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted net loss per common share. The following table details the weighted-average anti-dilutive securities for the years presented: For the Years Ended December 31, 2017 2016 2015 (in thousands) Anti-dilutive 264 280 256 The following table sets forth the calculations of basic and diluted net loss per common share: For the Years Ended December 31, 2017 2016 2015 (in thousands, except per share data) Net loss $ (160,843 ) $ (757,744 ) $ (447,710 ) Basic weighted-average common shares outstanding 111,428 76,568 67,723 Add: dilutive effect of non-vested RSUs and contingent PSUs — — — Add: dilutive effect of Senior Convertible Notes — — — Diluted weighted-average common shares outstanding 111,428 76,568 67,723 Basic net loss per common share $ (1.44 ) $ (9.90 ) $ (6.61 ) Diluted net loss per common share $ (1.44 ) $ (9.90 ) $ (6.61 ) 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, 2017 , and 2016 . 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 in onshore 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 2017 or 2016 . 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. Going forward, excess tax benefits will be presented in operating activities on the accompanying statements of cash flows. • Also 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 $0.4 million , and a net $0.7 million 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 has reclassified restricted cash out of investing activities and combined it with cash and cash equivalents when reconciling the beginning and end of period balances on the statements of cash flows. The December 31, 2016, and 2015 accompanying statements of cash flows line items that were adjusted as a result of the adoption of ASU 2016-15 and ASU 2016-18 are summarized as follows: For the Years Ended December 31, 2016 2015 As Reported As Adjusted As Reported As Adjusted (in thousands) Non-cash (gain) loss on extinguishment of debt $ (15,722 ) N/A $ 4,123 N/A (Gain) loss on extinguishment of debt N/A $ (15,722 ) N/A $ 16,578 Net cash provided by operating activities $ 552,804 $ 552,804 $ 978,352 $ 990,807 Other, net $ (3,000 ) $ — $ (985 ) $ (985 ) Net cash used in investing activities $ (1,870,639 ) $ (1,867,639 ) $ (1,144,639 ) $ (1,144,639 ) Cash paid for extinguishment of debt N/A $ — N/A $ (12,455 ) Net cash provided by financing activities $ 1,327,189 $ 1,327,189 $ 166,185 $ 153,730 Net change in cash and cash equivalents $ 9,354 N/A $ (102 ) N/A Net change in cash, cash equivalents, and restricted cash N/A $ 12,354 N/A $ (102 ) Cash and cash equivalents at beginning of period $ 18 N/A $ 120 N/A Cash, cash equivalents, and restricted cash at beginning of period N/A $ 18 N/A $ 120 Cash and cash equivalents at end of period $ 9,372 N/A $ 18 N/A Cash, cash equivalents, and restricted cash at end of period N/A $ 12,372 N/A $ 18 The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the accompanying balance sheets to the amounts shown in the accompanying statements of cash flows: December 31, 2017 2016 2015 (in thousands) Cash and cash equivalents $ 313,943 $ 9,372 $ 18 Restricted cash (1) — 3,000 — Total cash, cash equivalents, and restricted cash shown in the accompanying statements of cash flows $ 313,943 $ 12,372 $ 18 ____________________________________________ (1) Restricted cash is included in other noncurrent assets on the accompanying balance sheets. 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. The Company adopted ASU 2014-09 and all related ASUs using a modified retrospective transition method on the effective date of January 1, 2018 and will apply the new guidance to contracts for which all, or substantially all, of the revenue has not been recognized as of December 31, 2017 under legacy revenue guidance. This adoption will not result in a material change to current or prior period results, business processes, systems, or controls. However, upon adoption the Company will expand its current disclosures to comply with the disclosure requirements of the new guidance. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”) , which requires lessees to recognize a right-of-use asset and a lease liability for virtually all leases currently classified as operating leases. The Company is currently analyzing the impact this standard will have on the Company’s contract portfolio, including non-cancelable leases, drilling rigs, pipeline gathering, transportation, gas processing, and other existing arrangements. Further, the Company is evaluating current accounting policies, applicable systems, controls, and processes to support the potential recognition and disclosure changes resulting from ASU 2016-02. Based upon the Company’s initial assessment, ASU 2016-02 is expected to result in an increase in assets and liabilities recorded. The Company will adopt ASU 2016-02 using a modified retrospective method on the effective date of January 1, 2019. In January 2018, the FASB issued ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842 (“ASU 2018-01”). ASU 2018-01 provides an optional transitional practical expedient which allows entities to exclude from evaluation land easements that exist or expired before adoption of ASU 2016-02. The Company is currently evaluating this practical expedient and will adopt ASU 2018-01 at the same time as ASU 2016-02. 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 has determined that the adoption of ASU 2017-01 on the effective date of January 1, 2018, using a prospective method, does not impact the Company’s current consolidated financial statements or disclosures. However, the clarified definition of a business will be applied by the Company to future transactions. In February 2017, the FASB issued ASU No. 2017-05, Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets (“ASU 2017-05”). ASU 2017-05 is meant to clarify the scope of Accounting Standards Codification (“ASC”) Subtopic 610-20, Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets and to add guidance for partial sales of nonfinancial assets. The Company has determined that the adoption of ASU 2017-05 on the effective date of January 1, 2018, using a modified retrospective method, does not impact the Company’s current consolidated

Accounts Receivable and Account

Accounts Receivable and Accounts Payable and Accrued Expenses	12 Months Ended
	Dec. 31, 2017
Accounts Receivable and Accounts Payable and Accrued Expenses [Abstract]
Accounts Receivable and Accounts Payable and Accrued Expenses [Text Block]	Note 2 – Accounts Receivable and Accounts Payable and Accrued Expenses Accounts receivable are comprised of the following accruals: As of December 31, 2017 2016 (in thousands) Oil, gas, and NGL production revenue $ 96,610 $ 96,101 Amounts due from joint interest owners 56,929 29,669 State severance tax refunds 2,276 15,320 Derivative settlements 99 6,512 Other 4,240 4,348 Total accounts receivable $ 160,154 $ 151,950 Accounts payable and accrued expenses are comprised of the following accruals: As of December 31, 2017 2016 (in thousands) Capital expenditures $ 164,620 $ 107,009 Revenue and severance tax payable 60,328 39,617 Lease operating expense 22,078 15,956 Property taxes 13,222 6,606 Compensation 39,471 34,761 Derivative settlements 12,644 6,473 Interest 45,057 45,059 Other 29,210 44,227 Total accounts payable and accrued expenses $ 386,630 $ 299,708

Divestitures, Assets Held for S

Divestitures, Assets Held for Sale, and Acquisitions	12 Months Ended
	Dec. 31, 2017
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 2017 Divestiture Activity Eagle Ford Divestiture. During the first quarter of 2017, the Company divested its outside-operated Eagle Ford shale assets, including its ownership interest in related midstream assets, for total cash received, net of costs (referred to throughout this report as “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 . These assets were classified as held for sale as of December 31, 2016 . The following table presents income (loss) before income taxes from the outside-operated Eagle Ford shale assets sold for the years ended December 31, 2017 , 2016 , and 2015 . This divestiture was considered a disposal of a significant asset group. For the Years Ended December 31, 2017 2016 2015 (in thousands) Income (loss) before income taxes (1) $ 24,324 $ (218,506 ) $ 71,556 ____________________________________________ (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 approximately $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 a small net gain. Please refer to the Assets Held for Sale section below for an explanation of divestiture losses the Company recorded during 2017 for its Divide County, North Dakota assets, which were held for sale in the first quarter and a portion of the second quarter of 2017. 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 packages for 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 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. 2015 Divestiture Activity Mid-Continent Divestiture. During the second quarter of 2015, the Company divested its Mid-Continent assets in multiple transactions for total net divestiture proceeds of $310.3 million and a final net gain of $108.4 million . In conjunction with the divestiture of its Mid-Continent assets, the Company closed its Tulsa, Oklahoma office. Permian Divestiture. During the fourth quarter of 2015, the Company divested certain non-core assets in its Permian region. Net divestiture proceeds were $25.1 million and the final net gain on this divestiture was $2.3 million . Write-downs on certain other assets held for sale and subsequently sold during the year ended December 31, 2015, totaled $68.6 million , which partially offset the net gain on the Mid-Continent and Permian divestitures discussed above. Assets 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 in the accompanying statements of operations. During the year ended December 31, 2017 , the Company recorded a $526.5 million write-down on its retained Divide County, North Dakota assets held for sale in early 2017, of which $359.6 million was recorded in the first quarter of 2017 based on estimated fair value less selling costs. An additional $166.9 million write-down was recorded in the second quarter of 2017 based on market conditions that existed on the date the Company decided to retain the assets. As of December 31, 2017 , the accompanying balance sheets present $111.7 million of assets held for sale, net of accumulated depletion, depreciation, and amortization expense, which consists primarily of approximately 112,000 net acres in the Powder River Basin. A corresponding aggregate asset retirement obligation liability of $11.4 million is separately presented. Subsequent to December 31, 2017 , the Company entered into a definitive agreement for the sale of these assets for a gross purchase price of $500.0 million , subject to customary closing price adjustments. The Company expects to close this divestiture in the first quarter of 2018. The closing of this divestiture is subject to the satisfaction of customary closing conditions and there can be no assurance that the transaction will close on time or at all. The Company determined that neither planned nor executed asset sales qualify for discontinued operations accounting under financial statement presentation authoritative guidance. 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 and the Senior Convertible Notes and equity offerings in August 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. Refer to Note 11 – Fair Value Measurements for additional discussion on the valuation techniques used in determining the fair value of the acquired properties. 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. 2015 Acquisition Activity There was no significant acquisition activity during the year ended December 31, 2015 .

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 2015 (in thousands) Current portion of income tax expense Federal $ 5,698 $ 2,932 $ — State 3,398 1,539 1,571 Deferred portion of income tax benefit (192,066 ) (448,643 ) (276,722 ) Total income tax benefit $ (182,970 ) $ (444,172 ) $ (275,151 ) Effective tax rate 53.2 % 37.0 % 38.1 % The components of the net deferred tax liabilities are as follows: As of December 31, 2017 2016 (in thousands) Deferred tax liabilities Oil and gas properties $ 142,467 $ 518,394 Other 3,412 7,733 Total deferred tax liabilities 145,879 526,127 Deferred tax assets Derivative liabilities 29,463 31,349 Credit carryover 22,537 12,448 Pension 7,986 10,366 Federal and state tax net operating loss carryovers 3,867 151,343 Stock compensation 3,545 10,083 Other liabilities 1,470 201 Total deferred tax assets 68,868 215,790 Valuation allowance (2,978 ) (5,335 ) Net deferred tax assets 65,890 210,455 Total net deferred tax liabilities $ 79,989 $ 315,672 Current federal income tax refundable $ 37 $ 644 Current state income tax payable $ 3,009 $ 1,181 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 . This rate change was required to be applied to the Company’s total temporary differences as of December 31, 2017, resulting in a decrease in net deferred tax liabilities and a realized tax benefit of $63.7 million in the fourth quarter of 2017. This realized tax benefit amount represents 18.5 percentage points of the effective tax rate for 2017 reported above. Please refer to the table below for additional detail. Although the Company believes it has properly analyzed the tax accounting impacts of the 2017 Tax Act and appropriately re-measured its net deferred tax liability as of December 31, 2017, it will continue to monitor provisions with discrete rate impacts, such as the limitation on executive compensation, for subsequent events and guidance within one year of the enacted date. As of December 31, 2017 , the Company estimated its federal net operating loss (“NOL”) carryforward at $1.3 million , which reflects the planning strategies to utilize NOLs for the 2017 and 2016 tax years. 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 R&D credit carryforwards of $7.2 million . The federal R&D credit carryforwards expire between 2028 and 2033. The Company’s AMT credit carryforward of $15.7 million does not expire and is expected to be fully refunded by 2022 subject to possible limitations placed on these types of refunds under the sequestration rules enacted by Congress. State NOL carryforwards were $71.8 million and state tax credits were $283,000 as of December 31, 2017 . Federal and state NOLs and state credits expire between 2018 and 2038. The Company’s current valuation allowance relates to state NOL carryforwards and state tax credits, which could not be utilized in the respective states for the tax years 2017 and 2016, and are expected to expire before they can be utilized. The change in the valuation allowance from 2016 to 2017 primarily relates to an allocable change to the Company’s mix of state apportioned losses, anticipated utilization of state cumulative NOLs and to a lesser extent the cumulative state effect of adopting ASU 2016-09. Federal income tax benefit differs from the amount that would be provided by applying the U.S. federal statutory rate to income before income taxes primarily due to the effect of state income taxes, changes in valuation allowances, R&D credits, and accumulated impacts of other smaller permanent differences, reported as follows: For the Years Ended December 31, 2017 2016 2015 (in thousands) Federal statutory tax benefit $ (120,335 ) $ (420,671 ) $ (253,001 ) Increase (decrease) in tax resulting from: Federal tax reform changes - 2017 Tax Act (63,675 ) — — State tax benefit (net of federal benefit) (3,286 ) (17,549 ) (21,583 ) Change in valuation allowance (2,727 ) (5,059 ) 3,148 Employee share-based compensation 8,190 — — Other (1,137 ) (893 ) (3,715 ) Income tax benefit $ (182,970 ) $ (444,172 ) $ (275,151 ) 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. The Company and its subsidiaries file federal income tax returns and various state income tax returns. With an exception for activity related to its 2003 - 2005 tax years, the Company is generally no longer subject to United States federal or state income tax examinations by tax authorities for years before 2013. The exception tax years have been reopened for net operating loss carryback claims and are currently under examination by the Internal Revenue Service (the “IRS”). During the third quarter of 2017, the Company received a $5.5 million refund in advance of the IRS completing its examination of the Company’s claims. During 2016, the Company’s 2007 - 2011 IRS examination was finalized, as was the 2013 IRS audit of the SM-Mitsui Tax Partnership with no material adjustments to previously recorded amounts. The Company recorded an additional $2.0 million net R&D credit in 2015 as a result of its R&D credit settlement with the IRS Appeals Office. 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 2018 . The total amount recorded for unrecognized tax benefits is presented below: For the Years Ended December 31, 2017 2016 2015 (in thousands) Beginning balance $ 446 $ 2,782 $ 1,582 Additions for tax positions of prior years — 9 1,200 Settlements — (2,345 ) — Ending balance $ 446 $ 446 $ 2,782

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Long-Term Debt	Note 5 – Long-Term Debt Credit Agreement The Company’s Credit Agreement provides for a maximum loan amount of $2.5 billion and has a maturity date of December 10, 2019 . On March 31, 2017 , the Company entered into the Ninth Amendment with its lenders. Pursuant to the Ninth Amendment, and as part of the regular, semi-annual borrowing base redetermination process, the borrowing base and aggregate lender commitments were reduced to $925 million primarily due to the sale of the Company’s outside-operated Eagle Ford shale assets and the decrease in the value of the Company’s estimated proved reserves as of December 31, 2016. The borrowing base redetermination process considers the value of both the Company’s (a) proved oil and gas properties reflected in the Company’s most recent reserve report and (b) commodity derivative contracts, each as determined by the Company’s lender group. The next semi-annual redetermination date is scheduled for April 1, 2018 . 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. Financial covenants under the Credit Agreement require, as of the last day of each of the Company’s fiscal quarters, the Company’s (a) ratio of senior secured debt to 12-month trailing adjusted EBITDAX to be not more than 2.75 to 1.0; (b) adjusted current ratio to be not less than 1.0 to 1.0; and (c) ratio of 12-month trailing adjusted EBITDAX to interest expense to be not less than 2.0 to 1.0. The Company was in compliance with all financial and non-financial covenants under the Credit Agreement as of December 31, 2017 , 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 table below, and Alternate Base Rate (“ABR”) and swingline loans accrue interest at the prime rate, plus the applicable margin from the utilization table below. Commitment fees are accrued on the unused portion of the aggregate lender commitment amount and are included in interest expense in the accompanying statements of operations. The borrowing base utilization grid under the Credit Agreement is as follows: Borrowing Base Utilization Percentage <25% ≥25% <50% ≥50% <75% ≥75% <90% ≥90% Eurodollar Loans 1.750 % 2.000 % 2.250 % 2.500 % 2.750 % ABR Loans or Swingline Loans 0.750 % 1.000 % 1.250 % 1.500 % 1.750 % Commitment Fee Rate 0.300 % 0.300 % 0.350 % 0.375 % 0.375 % 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 14, 2018 , December 31, 2017 , and December 31, 2016 : As of February 14, 2018 As of December 31, 2017 As of December 31, 2016 (in thousands) Credit facility balance (1) $ — $ — $ — Letters of credit (2) 200 200 200 Available borrowing capacity 924,800 924,800 1,164,800 Total aggregate lender commitment amount $ 925,000 $ 925,000 $ 1,165,000 ____________________________________________ (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 $3.1 million and $5.9 million as of December 31, 2017 , and 2016 , respectively. (2) Letters of credit outstanding reduce the amount available under the credit facility on a dollar-for-dollar basis. Senior Notes The Company’s Senior Notes consist of 6.50% Senior Notes due 2021, 6.125% Senior Notes due 2022, 6.50% Senior Notes due 2023, 5.0% Senior Notes due 2024, 5.625% Senior Notes due 2025, and 6.75% Senior Notes due 2026 (collectively referred to as “Senior Notes”). The Senior Notes, net of unamortized deferred financing costs line on the accompanying balance sheets as of December 31, 2017 , and 2016 , consisted of the following: As of December 31, 2017 2016 Principal Amount Unamortized Deferred Financing Costs Senior Notes, Net of Unamortized Deferred Financing Costs Principal Amount Unamortized Deferred Financing Costs Senior Notes, Net of Unamortized Deferred Financing Costs (in thousands) 6.50% Senior Notes due 2021 $ 344,611 $ 2,656 $ 341,955 $ 346,955 $ 3,372 $ 343,583 6.125% Senior Notes due 2022 561,796 5,800 555,996 561,796 6,979 554,817 6.50% Senior Notes due 2023 394,985 3,707 391,278 394,985 4,436 390,549 5.0% Senior Notes due 2024 500,000 5,610 494,390 500,000 6,533 493,467 5.625% Senior Notes due 2025 500,000 6,714 493,286 500,000 7,619 492,381 6.75% Senior Notes due 2026 500,000 7,242 492,758 500,000 8,078 491,922 Total $ 2,801,392 $ 31,729 $ 2,769,663 $ 2,803,736 $ 37,017 $ 2,766,719 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; however, the first $6.5 million of dividends paid each year are not restricted by the restricted payment covenant. The Company was in compliance with all covenants under its Senior Notes as of December 31, 2017 , 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 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. 2019 Notes . During 2015, the Company conducted a tender offer and subsequent redemption of its 2019 Notes. As a result, the Company recorded a loss on the extinguishment of debt of approximately $16.6 million for the year ended December 31, 2015. This amount includes approximately $12.5 million associated with the premium paid for the tender offer and redemption of the 2019 Notes and approximately $4.1 million related to the acceleration of unamortized deferred financing costs. 2021 Notes. On November 8, 2011 , the Company issued $350.0 million in aggregate principal amount of 6.50% Senior Notes due 2021 at par, which mature on November 15, 2021 . The Company received net proceeds of $343.1 million after deducting fees of $6.9 million , which are being amortized as deferred financing costs over the life of the 2021 Notes. During the first quarter of 2016, the Company repurchased $3.1 million in aggregate principal amount of its 2021 Notes for a settlement amount of $2.3 million , excluding interest. During the first quarter of 2017, the Company repurchased in open market transactions a total of $2.3 million in aggregate principal amount of its 2021 Notes at a slight premium. 2022 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. 2023 Notes. On June 29, 2012 , the Company issued $400.0 million in aggregate principal amount of 6.50% Senior Notes due 2023 at par, which mature on January 1, 2023 . The Company received net proceeds of $392.1 million after deducting fees of $7.9 million , which are being amortized as deferred financing costs over the life of the 2023 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 , excluding interest. 2024 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 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. The net proceeds were used to fund the consideration paid to the tendering holders of the 2019 Notes and to redeem the remaining untendered 2019 Notes, as well as repay outstanding borrowings under the Credit Agreement and for general corporate purposes. 2026 Notes. On September 12, 2016 , the Company issued $500.0 million in aggregate principal amount of 6.75% Senior Notes due 2026 , at par (the “2026 Notes”), 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. 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 (the “Senior Convertible Notes”). 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. The Senior Convertible Notes mature on July 1, 2021 , unless earlier converted. 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, 2017 , 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, 2017 , 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 $9.9 million and $3.7 million for the years ended December 31, 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, 2017 and 2016: As of December 31, 2017 2016 (in thousands) Principal amount of Senior Convertible Notes $ 172,500 $ 172,500 Unamortized debt discount (30,183 ) (37,513 ) Unamortized deferred financing costs (3,210 ) (4,131 ) Net carrying amount $ 139,107 $ 130,856 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, 2017 and 2016: As of December 31, 2017 2016 (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, 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, 2017 , 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, 2017 , 2016 , and 2015 , were $12.6 million , $17.0 million , and $25.1 million , respectively.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
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 contracts of $37.8 million , gathering, processing, transportation throughput, and delivery commitments of $463.4 million , office leases, including maintenance, of $43.3 million , and other miscellaneous contracts and leases of $30.2 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) 2018 $ 113,774 2019 112,860 2020 111,107 2021 102,606 2022 72,073 Thereafter 62,245 Total $ 574,665 Subsequent to December 31, 2017 , the Company entered into a fixed price contract to purchase electricity through 2027 for a total of $27.9 million . As of the filing of this report, the Company expects to meet this purchase commitment. Drilling Contracts The Company has several drilling rig contracts in place to facilitate drilling plans. Early termination of these rig contracts as of December 31, 2017 , would have resulted in termination penalties of $27.7 million , which would be in lieu of paying the remaining drilling commitments of $37.8 million included in the table above. For the years ended December 31, 2016 , and 2015 , the Company incurred $8.7 million and $13.7 million , respectively, 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 such expenses were recorded by the Company for the year ended December 31, 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, 2017 , the Company has commitments to deliver a minimum of 19 MMBbl of oil, 789 Bcf of gas, and 24 MMBbl of produced water through 2028 . 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, 2017 , if the Company fails to deliver any product, as applicable, the aggregate undiscounted deficiency payments total approximately $463.4 million . If a shortfall in the minimum volume commitment for gas is projected, the Company has rights under certain contracts to arrange for third-party gas to be delivered, and such volumes would count toward its minimum volume commitment. During the first quarter of 2017, the Company completed the divestiture of its outside-operated Eagle Ford shale assets. Upon closing of the sale, the Company is no longer subject to transportation throughput commitments totaling 52 MMBbl of oil, 514 Bcf of gas, and 13 MMBbl of NGLs, or $501.9 million of the potential undiscounted deficiency payments as of December 31, 2016 . As of the filing of this report, the Company does not expect to incur any material shortfalls. 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, 2017 , 2016 , and 2015 , was $4.8 million , $5.2 million , and $6.1 million , respectively. The Company closed its office in Billings, Montana in November 2016 and paid $3.2 million to the lessor to terminate the lease, which is not reflected in the rent expense amount 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 results of such pending litigation and claims is not likely 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, 2017
Compensation Related Costs [Abstract]
Compensation Plans	Note 7 – Compensation Plans Equity 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, 2017 , approximately 3.3 million shares of common stock remained 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 long-term equity compensation program. 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 measurement period. The performance criteria for PSUs are based on a combination of the Company’s annualized Total Shareholder Return (“TSR”) for the performance period and the relative performance of the Company’s TSR compared with the annualized TSR of certain peer companies for the performance period. Compensation expense for PSUs is recognized within general and administrative and exploration expense over the vesting periods of the respective awards. The fair value of PSUs is measured at the grant date with a stochastic process method using the Geometric Brownian Motion Model (“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. 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 $9.7 million , $11.0 million , and $10.6 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively. As of December 31, 2017 , there was $18.8 million of total unrecognized expense related to PSUs, which is being amortized through 2020 . A summary of the status and activity of non-vested PSUs is presented in the following table: For the Years Ended December 31, 2017 2016 2015 PSUs Weighted-Average Grant-Date Fair Value PSUs Weighted-Average Grant-Date Fair Value PSUs Weighted-Average Grant-Date Fair Value Non-vested at beginning of year (1) 828,923 $ 43.25 626,328 $ 61.81 433,660 $ 73.63 Granted (1) 977,731 $ 15.86 447,971 $ 26.56 320,753 $ 45.34 Vested (1) (94,338 ) $ 85.85 (130,353 ) $ 64.17 (76,438 ) $ 51.76 Forfeited (1) (178,825 ) $ 44.99 (115,023 ) $ 55.59 (51,647 ) $ 73.62 Non-vested at end of year (1) 1,533,491 $ 22.97 828,923 $ 43.25 626,328 $ 61.81 ____________________________________________ (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 2017 , 2016 , and 2015 was $15.5 million , $11.9 million , and $14.5 million , respectively. The PSUs granted in 2015 will remain non-vested until the third anniversary date of their issuance, at which time they will fully vest, unless the employee is retirement eligible in which case the PSUs vest immediately upon attainment of retirement age. PSUs granted in 2017 and 2016 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, 2017 , there were no shares of common stock issued to settle PSUs granted in 2014 as the multiplier earned was zero. A summary of the shares of common stock issued to settle PSUs for the years ended December 31, 2016 , and 2015 , is presented in the table below: For the Years Ended December 31, 2016 2015 Shares of common stock issued to settle PSUs (1) 44,870 288,962 Less: shares of common stock withheld for income and payroll taxes (14,809 ) (100,683 ) Net shares of common stock issued 30,061 188,279 Multiplier earned 0.2 1.0 ____________________________________________ (1) During the years ended December 31, 2016 , and 2015 , the Company issued shares of common stock for PSUs granted in 2013, and 2012. 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, 2017 , 2016 , and 2015 was $8.1 million , $8.4 million , and $4.0 million , respectively. Employee Restricted Stock Units The Company grants RSUs to eligible employees as part of its long-term equity incentive compensation program. 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 award. Total compensation expense recorded for employee RSUs for the years ended December 31, 2017 , 2016 , and 2015 , was $10.3 million , $11.9 million , and $13.4 million , respectively. As of December 31, 2017 , there was $19.3 million of total unrecognized expense related to non-vested RSU awards, which is being amortized through 2020 . 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 for eligible employees is presented in the following table: For the Years Ended December 31, 2017 2016 2015 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 604,116 $ 37.39 543,737 $ 55.01 515,724 $ 68.29 Granted 1,020,780 $ 16.64 417,065 $ 28.08 356,246 $ 43.72 Vested (246,025 ) $ 43.99 (241,363 ) $ 58.06 (278,289 ) $ 63.12 Forfeited (134,609 ) $ 26.38 (115,323 ) $ 43.52 (49,944 ) $ 66.53 Non-vested at end of year 1,244,262 $ 20.25 604,116 $ 37.39 543,737 $ 55.01 The fair value of RSUs granted to eligible employees in 2017 , 2016 , and 2015 was $17.0 million , $11.7 million , and $15.6 million , respectively. The RSUs granted in 2015 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 vest immediately upon attainment of retirement age. The RSUs granted in 2017 and 2016 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 a 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, 2017 2016 2015 Shares of common stock issued to settle RSUs (1) 246,025 241,363 278,289 Less: shares of common stock withheld for income and payroll taxes (74,747 ) (72,181 ) (91,045 ) Net shares of common stock issued 171,278 169,182 187,244 ____________________________________________ (1) During the years ended December 31, 2017 , 2016 , and 2015 , the Company issued shares of common stock for RSUs 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, 2017 , 2016 , and 2015 was $10.8 million , $14.0 million , and $17.6 million , respectively. Director Shares and Restricted Stock Units In 2017 , 2016 , and 2015 , the Company issued 71,573 , 53,473 , and 39,903 shares, respectively, of its common stock to its non-employee directors under the Company’s Equity Plan. Also in 2017 , the Company issued 8,794 RSUs to a non-employee director. For the years ended December 31, 2017 , 2016 , and 2015 , the Company recorded $1.6 million , $2.0 million , and $1.6 million , respectively, of compensation expense related to director shares and RSUs issued. Beginning with the awards granted in 2016, all shares issued to non-employee directors fully vest on December 31 st of the year granted. Prior to 2016, all shares of common stock issued to the Company’s non-employee directors were earned over the one -year service period following the date of grant, unless five years of service had been provided to the Company by the director, in which case that director’s shares vested upon the earlier of the completion of the one year service period or the director retiring from the Board of Directors. 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 IRC. The Company had approximately 1.8 million shares of its common stock available for issuance under the ESPP as of December 31, 2017 . There were 186,665 , 218,135 , and 197,214 shares issued under the ESPP in 2017 , 2016 , and 2015 , respectively. Total proceeds to the Company for the issuance of these shares were $2.6 million , $4.2 million , and $4.8 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively. The fair value of ESPP grants is measured at the date of grant using the Black-Scholes-Merton 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, 2017 2016 2015 Risk free interest rate 0.9 % 0.4 % 0.1 % Dividend yield 0.5 % 0.4 % 0.2 % Volatility factor of the expected market price of the Company’s common stock 62.5 % 95.0 % 61.2 % Expected life (in years) 0.5 0.5 0.5 The Company expensed $1.0 million , $2.0 million , and $1.8 million for the years ended December 31, 2017 , 2016 , and 2015 , 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 each employee’s contribution up to six percent of the employee’s base salary and performance bonus, and may make additional contributions at its discretion. The Company matches contributions made by employees hired after December 31, 2014, up to nine 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 $4.5 million , $5.4 million , and $5.6 million for the years ended December 31, 2017 , 2016 , and 2015 , 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 on divestiture activity line item in the accompanying statements of operations. For the Years Ended December 31, 2017 2016 2015 (in thousands) Cash payments made or accrued related to operations $ (54 ) $ 6,608 $ 3,498 Cash payments made or accrued related to divestitures 2,753 24,349 3,789 Total net settlements $ 2,699 $ 30,957 $ 7,287

Pension Benefits

Pension Benefits	12 Months Ended
	Dec. 31, 2017
Defined Benefit Plan [Abstract]
Pension Benefits	Note 8 – Pension Benefits The Company has a non-contributory defined benefit pension plan covering substantially all 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 as of December 31, 2014, 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 accumulated other comprehensive income (loss), net of tax. 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, 2017 2016 (in thousands) Change in benefit obligation: Projected benefit obligation at beginning of year $ 69,659 $ 62,547 Service cost 6,638 8,200 Interest cost 2,689 2,908 Actuarial loss 3,708 2,662 Benefits paid (10,757 ) (6,658 ) Projected benefit obligation at end of year 71,937 69,659 Change in plan assets: Fair value of plan assets at beginning of year 31,731 25,769 Actual return on plan assets 2,956 1,575 Employer contribution 7,048 11,045 Benefits paid (10,757 ) (6,658 ) Fair value of plan assets at end of year 30,978 31,731 Funded status at end of year $ (40,959 ) $ (37,928 ) The Company’s underfunded status for the Pension Plans as of December 31, 2017 , and 2016 , was $41.0 million and $37.9 million , respectively, and is recognized in the accompanying balance sheets as a portion of other noncurrent liabilities. No plan assets of the Qualified Pension Plan were returned to the Company during the year ended December 31, 2017 . 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, 2017 2016 (in thousands) Projected benefit obligation $ 71,937 $ 69,659 Accumulated benefit obligation $ 56,045 $ 54,681 Less: Fair value of plan assets (30,978 ) (31,731 ) Underfunded accumulated benefit obligation $ 25,067 $ 22,950 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 a 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, 2017 , and 2016 , were as follows: As of December 31, 2017 2016 (in thousands) Unrecognized actuarial losses $ 21,397 $ 22,708 Unrecognized prior service costs 66 83 Accumulated other comprehensive loss $ 21,463 $ 22,791 The estimated net loss that will be amortized from accumulated other comprehensive loss into net periodic benefit cost for the year ended December 31, 2018, is $1.3 million . The pension liability adjustments recognized in other comprehensive income (loss) during 2017 , 2016 , and 2015 , were as follows: For the Years Ended December 31, 2017 2016 2015 (in thousands) Net actuarial loss $ (2,995 ) $ (3,322 ) $ (4,990 ) Amortization of prior service cost 17 16 17 Amortization of net actuarial loss 1,297 1,582 1,486 Settlements 3,009 — 350 Total pension liability adjustment, pre-tax 1,328 (1,724 ) (3,137 ) Tax (expense) benefit (561 ) 570 1,047 Total pension liability adjustment, net of tax $ 767 $ (1,154 ) $ (2,090 ) Components of Net Periodic Benefit Cost for the Pension Plans For the Years Ended December 31, 2017 2016 2015 (in thousands) Components of net periodic benefit cost: Service cost $ 6,638 $ 8,200 $ 7,949 Interest cost 2,689 2,908 2,496 Expected return on plan assets that reduces periodic pension benefit cost (2,244 ) (2,235 ) (2,182 ) Amortization of prior service cost 17 16 17 Amortization of net actuarial loss 1,297 1,582 1,486 Settlements 3,009 — 350 Net periodic benefit cost $ 11,406 $ 10,471 $ 10,116 Pension Plan Assumptions The weighted-average assumptions used to measure the Company’s projected benefit obligation are as follows: As of December 31, 2017 2016 Projected benefit obligation: Discount rate 3.8% 4.2% 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, 2017 2016 2015 Net periodic benefit cost: Discount rate 4.2% 4.7% 4.3% Expected return on plan assets (1) 6.5% 7.5% 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 2018 2017 2016 Equity securities 35.0 % 38.4 % 28.8 % Fixed income securities 43.0 % 39.8 % 35.5 % Other securities 22.0 % 21.8 % 35.7 % Total 100.0 % 100.0 % 100.0 % There is no asset allocation of the Nonqualified Pension Plan since there are no plan assets in that plan. An expected return on plan assets of 6.5 percent and 7.5 percent was used to calculate the Company’s obligation under the Qualified Pension Plan as of December 31, 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, 2017 , and 2016 , 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, 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 corp 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 As of December 31, 2016 Cash — % $ — $ — $ — $ — Equity securities: Domestic (2) 18.7 % 5,945 4,471 1,474 — International (3) 10.1 % 3,192 3,192 — — Total equity securities 28.8 % 9,137 7,663 1,474 — Fixed income securities: High-yield bonds (4) 2.6 % 822 822 — — Core fixed income (5) 25.0 % 7,923 7,923 — — Floating rate corp loans (6) 7.9 % 2,495 2,495 — — Total fixed income securities 35.5 % 11,240 11,240 — — Other securities: Commodities (7) 1.8 % 578 578 — — Real estate (8) 5.1 % 1,629 — — 1,629 Collective investment trusts (9) 17.5 % 5,562 — 5,562 — Hedge fund (10) 11.3 % 3,585 — — 3,585 Total other securities 35.7 % 11,354 578 5,562 5,214 Total investments 100.0 % $ 31,731 $ 19,481 $ 7,036 $ 5,214 ____________________________________________ (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 this fund 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 an investment in an actively traded global mutual fund that focuses 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, 2016 $ 5,045 Purchases 561 Realized gain on assets 54 Unrealized gain on assets 115 Disposition (561 ) Balance at December 31, 2016 $ 5,214 Purchases 300 Realized gain on assets 130 Unrealized gain on assets 120 Disposition (555 ) Balance at December 31, 2017 $ 5,209 Contributions The Company contributed $7.0 million , $11.0 million , and $6.4 million to the Pension Plans in the years ended December 31, 2017 , 2016 , and 2015 , respectively. The Company expects to make a $4.0 million contribution to the Pension Plans in 2018 . Benefit Payments The Pension Plans made actual benefit payments of $10.8 million , $6.7 million , and $8.2 million in the years ended December 31, 2017 , 2016 , and 2015 , respectively. Expected benefit payments over the next 10 years are as follows: Years Ending December 31, (in thousands) 2018 $ 4,217 2019 $ 3,818 2020 $ 4,363 2021 $ 5,561 2022 $ 6,117 2023 through 2027 $ 36,279

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note 9 – 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, 2017 2016 (in thousands) Beginning asset retirement obligations $ 123,307 $ 140,874 Liabilities incurred (1) 7,588 21,293 Liabilities settled (2) (30,432 ) (57,100 ) Accretion expense 5,988 7,795 Revision to estimated cash flows 8,019 10,445 Ending asset retirement obligations (3)(4) $ 114,470 $ 123,307 ____________________________________________ (1) Reflects liabilities incurred through drilling activities and acquisitions of drilled wells. (2) Reflects liabilities settled through plugging and abandonment activities and divestitures of properties. (3) Balances as of December 31, 2017 , and 2016 , included $11.4 million and $26.2 million , respectively, of asset retirement obligations associated with oil and gas properties held for sale. (4) Balances as of December 31, 2017 , and 2016 , included $75,000 and $932,000 , respectively, related to the Company’s current asset retirement obligation liability, which is recorded in accounts payable and accrued expenses on the accompanying balance sheets.

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [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, 2017 , all derivative counterparties were members of the Company’s credit facility 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 swap arrangements for gas and NGLs. 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. As of December 31, 2017 , the Company had commodity derivative contracts outstanding through the second quarter of 2020 , as summarized in the tables below. Oil Swaps Contract Period NYMEX WTI Volumes Weighted-Average Contract Price (MBbl) (per Bbl) First quarter 2018 1,075 $ 50.16 Second quarter 2018 1,534 $ 49.57 Third quarter 2018 1,769 $ 49.77 Fourth quarter 2018 1,894 $ 49.87 2019 1,940 $ 50.70 Total 8,212 Oil Collars Contract Period NYMEX WTI Volumes Weighted-Average Floor Price Weighted-Average Ceiling Price (MBbl) (per Bbl) (per Bbl) First quarter 2018 1,445 $ 50.00 $ 59.07 Second quarter 2018 1,459 $ 50.00 $ 59.03 Third quarter 2018 1,948 $ 50.00 $ 58.61 Fourth quarter 2018 2,222 $ 50.00 $ 58.44 2019 5,908 $ 47.65 $ 59.19 Total 12,982 Oil Basis Swaps Contract Period Midland-Cushing Volumes Weighted-Average Contract Price (1) (MBbl) (per Bbl) First quarter 2018 2,113 $ (1.15 ) Second quarter 2018 2,392 $ (1.03 ) Third quarter 2018 3,018 $ (1.06 ) Fourth quarter 2018 3,327 $ (1.08 ) 2019 5,788 $ (1.09 ) Total 16,638 ____________________________________________ (1) Represents the price differential between WTI prices at Midland, Texas and WTI prices at Cushing, Oklahoma. Gas Swaps Contract Period Sold Volumes Weighted-Average Contract Price Purchased Volumes Weighted-Average Contract Price Net Volumes (BBtu) (per MMBtu) (BBtu) (per MMBtu) (BBtu) First quarter 2018 28,910 $ 3.55 (8,121 ) $ 4.34 20,789 Second quarter 2018 23,507 $ 3.31 (7,795 ) $ 4.24 15,712 Third quarter 2018 24,627 $ 3.29 (7,480 ) $ 4.23 17,147 Fourth quarter 2018 25,856 $ 3.29 (7,210 ) $ 4.27 18,646 2019 41,394 $ 3.76 (24,415 ) $ 4.34 16,979 Total (1) 144,294 (55,021 ) 89,273 ____________________________________________ (1) Total net volumes of gas swaps are comprised of IF HSC ( 99% ) and IF El Paso Permian ( 1% ). NGL Swaps OPIS Purity Ethane 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 2018 923 $ 10.90 629 $ 25.39 206 $ 35.83 167 $ 35.76 188 $ 49.40 Second quarter 2018 915 $ 10.87 554 $ 24.94 84 $ 35.69 66 $ 35.07 109 $ 49.57 Third quarter 2018 1,033 $ 10.99 610 $ 24.27 93 $ 35.70 70 $ 35.07 118 $ 49.56 Fourth quarter 2018 1,146 $ 11.18 671 $ 24.39 102 $ 35.70 76 $ 35.07 129 $ 49.57 2019 3,533 $ 12.31 1,503 $ 27.83 154 $ 35.64 117 $ 35.70 197 $ 50.93 2020 539 $ 11.13 — $ — — $ — — $ — — $ — Total 8,089 3,967 639 496 741 Commodity Derivative Contracts Entered Into After December 31, 2017 Subsequent to December 31, 2017 , the Company entered into NGL Swap contracts for 2018 for approximately 228 MBbl of OPIS Natural Gasoline Mont Belvieu Non-TET NGL production at a contract price of $53.34 per Bbl. Derivative Assets and Liabilities Fair Value The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities. The Company does not designate its derivative commodity contracts as hedging instruments. The fair value of the derivative commodity contracts was a net liability of $139.4 million at December 31, 2017 , and net liability of $91.7 million at December 31, 2016 . The following tables detail the fair value of derivatives recorded in the accompanying balance sheets, by category: 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 As of December 31, 2016 Derivative Assets Derivative Liabilities Balance Sheet Classification Fair Value Balance Sheet Classification Fair Value (in thousands) Commodity contracts Current assets $ 54,521 Current liabilities $ 115,464 Commodity contracts Noncurrent assets 67,575 Noncurrent liabilities 98,340 Total commodity contracts $ 122,096 $ 213,804 Offsetting of Derivative Assets and Liabilities As of December 31, 2017 , and 2016 , 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 2017 2016 2017 2016 (in thousands) Gross amounts presented in the accompanying balance sheets $ 104,628 $ 122,096 $ (243,984 ) $ (213,804 ) Amounts not offset in the accompanying balance sheets (100,035 ) (118,080 ) 100,035 118,080 Net amounts $ 4,593 $ 4,016 $ (143,949 ) $ (95,724 ) 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, 2017 , 2016 , and 2015 . 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 net derivative (gain) loss presented in the accompanying statements of operations: For the Years Ended December 31, 2017 2016 2015 (in thousands) Derivative settlement (gain) loss: Oil contracts $ 31,176 $ (243,102 ) $ (362,219 ) Gas contracts (1) (87,857 ) (94,936 ) (123,180 ) NGL contracts 35,447 8,560 (27,167 ) Total derivative settlement gain $ (21,234 ) $ (329,478 ) $ (512,566 ) Net derivative (gain) loss: Oil contracts $ 71,502 $ 85,370 $ (191,165 ) Gas contracts (76,315 ) 81,060 (189,734 ) NGL contracts 31,227 84,203 (27,932 ) Total net derivative (gain) loss $ 26,414 $ 250,633 $ (408,831 ) ____________________________________________ (1) Gas derivative settlements for the year ended December 31, 2015, include $15.3 million of early settlements of futures contracts as a result of divesting assets in the Company’s Mid-Continent region. Credit Related Contingent Features As of December 31, 2017, and through the filing of this report, all of the Company’s derivative counterparties were members of the Company’s credit facility lender group. The Company’s obligations under its Credit Agreement and derivative contracts are secured by mortgages on assets having a value equal to at least 90 percent of the total PV-9 of the Company’s proved oil and gas properties evaluated in the most recent reserve report.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Disclosures [Text Block]	Note 11 – Fair Value Measurements The Company follows fair value measurement accounting guidance for all assets and liabilities measured at fair value. This guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The fair value hierarchy for grouping these assets and liabilities is based on the significance level of the following inputs: • Level 1 – quoted prices in active markets for identical assets or liabilities • Level 2 – quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable • Level 3 – significant inputs to the valuation model are unobservable The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they are classified within the fair value hierarchy as of December 31, 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. 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, 2016 : Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 122,096 $ — Total property and equipment, net (2) $ — $ — $ 88,205 Liabilities: Derivatives (1) $ — $ 213,804 $ — ____________________________________________ (1) This represents a financial asset or liability that is measured at fair value on a recurring basis. (2) This represents a non-financial asset that is measured at fair value on a nonrecurring 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. All of the Company’s commodity derivative counterparties are members of the Company’s credit facility lender group. 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 with 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 commodity derivative instruments. Proved and Unproved Oil and Gas Properties and Other Property and Equipment 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 the carrying costs may not be recoverable. The Company uses Level 3 inputs and the income valuation technique, which converts future cash flow amounts to a single present value amount, 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. The calculation of the discount rates is based on the best information available and the rates used ranged from 10 percent to 15 percent based on the reservoir specific weightings of future estimated proved and unproved cash flows as of December 31, 2017 , and 2016 . The Company believes the discount rates are representative of current market conditions and consider 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 prices for oil and gas are forecast 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 forecast 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 Company did not recognize any material impairment of proved properties expense for the year ended 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 for 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. The Company recorded impairment of proved properties expense of $468.7 million for the year ended December 31, 2015 , related primarily to the decline in expected reserve cash flows driven by commodity price declines recorded mainly in the Company’s East Texas and Powder River Basin programs with smaller impacts on other legacy and non-core assets in the Rocky Mountain region. 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. 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. The following table presents abandonment and impairment of unproved properties expense recorded for the periods presented: For the Years Ended December 31, 2017 2016 2015 (in millions) Abandonment and impairment of unproved properties $ 12.3 $ 80.4 $ 78.6 Abandonment and impairment of unproved properties expense recorded during the year ended December 31, 2017 , related primarily to lease expirations. 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. During the year ended December 31, 2015 , abandonment and impairment expense resulted from lease expirations and acreage the Company no longer intended to develop in light of changes in drilling plans in response to the decline in commodity prices. Other property and equipment . 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. During the year ended December 31, 2015 , the Company recorded impairment of other property and equipment expense of $49.4 million on the Company’s gathering system assets in its east Texas program. These assets were impaired in conjunction with the impairment of the associated proved and unproved properties, which the Company did not intend to develop and subsequently sold. There were no other property and equipment impairments in 2017 or 2016. Oil and gas properties held for sale . Proved and unproved oil and gas properties classified as held for sale, including the 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 income valuation techniques discussed above. Any initial write-down and subsequent changes to the fair value less estimated cost to sell is included within the net gain (loss) on divestiture activity line item in the accompanying statements of operations. There were no assets held for sale recorded at fair value as of December 31, 2017 , or 2016 , as the carrying values were below the estimated fair values less costs to sell. However, for the year ended December 31, 2017, the Company recorded a $526.5 million write-down on its Divide County, North Dakota assets which were held for sale in early 2017. Please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions for additional discussion. Acquisitions of proved and unproved properties . Assets acquired and liabilities assumed under transactions that meet the criteria of a business combination under ASC Topic 805, Business Combinations are recorded at fair value on the acquisition date using an income valuation technique based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the valuation of acquired oil and gas properties include estimates of: (i) reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; (v) future cash flows; and (vi) a market participant-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation. Assets acquired and liabilities assumed under transactions that do not meet the criteria of a business combination under ASC Topic 805, Business Combinations are accounted for as an asset acquisition and are recorded based on the fair value of the total consideration transferred on the acquisition date using the lowest observable inputs available. In connection with the QStar Acquisition, the Company issued approximately 13.4 million shares of common stock as a component of the total consideration transferred to the sellers on December 21, 2016. Fair value of the equity consideration transferred was based on the closing price of the Company’s common stock on the date of acquisition, as adjusted using an option pricing model to account for the lack of marketability of the shares issued. Please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions for additional discussion. Long-Term Debt The following table reflects the fair value of the Senior Notes and Senior Convertible Notes 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, 2017 , or 2016 , as they are 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, 2017 2016 Principal Amount Fair Value Principal Amount Fair Value (in thousands) 6.50% Senior Notes due 2021 $ 344,611 $ 351,682 $ 346,955 $ 354,546 6.125% Senior Notes due 2022 $ 561,796 $ 571,627 $ 561,796 $ 570,925 6.50% Senior Notes due 2023 $ 394,985 $ 403,434 $ 394,985 $ 403,134 5.0% Senior Notes due 2024 $ 500,000 $ 483,440 $ 500,000 $ 475,975 5.625% Senior Notes due 2025 $ 500,000 $ 494,355 $ 500,000 $ 485,000 6.75% Senior Notes due 2026 $ 500,000 $ 516,350 $ 500,000 $ 516,565 1.50% Senior Convertible Notes due 2021 $ 172,500 $ 168,291 $ 172,500 $ 202,189 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, 2017
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 2017 , 2016 , and 2015 . 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, 2017 2016 2015 (in thousands) Beginning balance $ 19,846 $ 11,952 $ 43,589 Additions to capitalized exploratory well costs pending the determination of proved reserves 49,446 19,846 11,952 Divestitures — — (809 ) Reclassifications to wells, facilities, and equipment based on the determination of proved reserves (19,846 ) (11,952 ) (18,485 ) Capitalized exploratory well costs charged to expense — — (24,295 ) Ending balance $ 49,446 $ 19,846 $ 11,952 As of December 31, 2017 , there were no exploratory well costs that were capitalized for more than one year.

Equity

Equity	12 Months Ended
	Dec. 31, 2017
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 2017.

Summary of Significant Accoun21

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation [Policy Text Block]	Basis of Presentation The accompanying consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries 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 subsequent events after the balance sheet date of December 31, 2017 , 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 consist mainly of receivables from oil, gas, and NGL purchasers and from joint interest owners on properties the Company operates. For receivables from joint interest owners, the Company typically 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 two months and the Company has had minimal bad debts. Although diversified among many companies, collectability 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, 2017 2016 2015 Major customer #1 (1) 10 % 5 % 4 % Major customer #2 (2) 7 % 18 % 21 % Group #1 of entities under common ownership (3) 17 % 15 % 10 % Group #2 of entities under common ownership (3) 8 % 8 % 11 % ____________________________________________ (1) This major customer is a purchaser of the Company’s production from its Permian region. (2) This major customer was the operator of the Company’s outside-operated Eagle Ford shale program, which was divested of during the first quarter of 2017. Prior to the divestiture, the Company was party to various marketing agreements, which included certain gathering, transportation, and processing throughput commitments. Because the Company shared with the operator the risk of non-performance by its counterparty purchasers, the Company included the operator as a major customer in the table above. Several of the operator’s counterparty purchasers under these contracts were also direct purchasers of the Company’s production from other areas. (3) In the aggregate these groups of entities under common ownership represent more than 10 percent of total oil, gas, and NGL production revenue for the period(s) shown, however, none of the individual entities 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.
Successful Efforts [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 costs, including lease and well equipment and intangible development costs, are depleted as a group of assets (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 the carrying costs may not be recoverable. Expected future discounted cash flows are calculated on all estimated proved reserves and risk-adjusted probable and possible reserves using discount rates and price forecasts that management believes are representative of current market conditions. 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, adjusted for basis differentials, 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. Please refer to Note 11 – Fair Value Measurements for additional discussion. 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. When successful wells are drilled on unproved leases, unproved property costs allocated to those leases are reclassified to proved properties and depleted on a units-of-production basis. An impairment is recorded on unproved property when the Company determines that either the property will not be developed or the carrying value is not realizable. Please refer to Note 11 – Fair Value Measurements for additional discussion. 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 G&G, 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 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 where appropriate. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts. A long-lived asset is evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. The Company uses an income valuation technique if there is not a market-observable price for the asset.
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.
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 and 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 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 seeks to manage or reduce commodity price risk on its production by entering into derivative contracts. The Company seeks to minimize its basis risk and indexes its oil derivative contracts to NYMEX prices, its NGL derivative contracts to OPIS prices, and its gas derivative contracts to various regional index prices associated with pipelines into which the Company’s gas production is sold. 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.
Revenue Recognition [Policy Text Block]	Revenue Recognition The Company derives revenue primarily from the sale of produced oil, gas, and NGLs. Revenue is recognized when the Company’s production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production. No revenue is recognized unless it is determined that title to the product has transferred to the purchaser. At the end of each month, the Company estimates the amount of production delivered to the purchaser and the price the Company will receive. The Company uses knowledge of its properties and historical performance, contractual agreements, NYMEX, OPIS, and local spot market prices, quality and transportation differentials, and other factors as the basis for these estimates. The Company follows the sales method of accounting for gas production imbalances. If the Company’s sales volumes for a well exceed the Company’s proportionate share of production from the well, a liability is recognized to the extent that the Company’s share of estimated remaining recoverable reserves from the well is insufficient to satisfy this imbalance. Effective January 1, 2018, the Company’s revenue recognition policy changed due to the adoption of new accounting guidance. Please refer to Recently Issued Accounting Standards below for additional discussion.
Share-based Compensation [Policy Text Block]	Stock-Based Compensation At December 31, 2017 , the Company had stock-based employee compensation plans that included RSUs and 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 included within general and administrative expense and exploration expense in the accompanying statements of operations. 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 Basic net income (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 (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 year ended December 31, 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 (loss) per share.
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, 2017 , and 2016 . 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 in onshore 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. Going forward, excess tax benefits will be presented in operating activities on the accompanying statements of cash flows. • Also 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 $0.4 million , and a net $0.7 million 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 has reclassified restricted cash out of investing activities and combined it with cash and cash equivalents when reconciling the beginning and end of period balances on the statements of cash flows. The December 31, 2016, and 2015 accompanying statements of cash flows line items that were adjusted as a result of the adoption of ASU 2016-15 and ASU 2016-18 are summarized as follows: For the Years Ended December 31, 2016 2015 As Reported As Adjusted As Reported As Adjusted (in thousands) Non-cash (gain) loss on extinguishment of debt $ (15,722 ) N/A $ 4,123 N/A (Gain) loss on extinguishment of debt N/A $ (15,722 ) N/A $ 16,578 Net cash provided by operating activities $ 552,804 $ 552,804 $ 978,352 $ 990,807 Other, net $ (3,000 ) $ — $ (985 ) $ (985 ) Net cash used in investing activities $ (1,870,639 ) $ (1,867,639 ) $ (1,144,639 ) $ (1,144,639 ) Cash paid for extinguishment of debt N/A $ — N/A $ (12,455 ) Net cash provided by financing activities $ 1,327,189 $ 1,327,189 $ 166,185 $ 153,730 Net change in cash and cash equivalents $ 9,354 N/A $ (102 ) N/A Net change in cash, cash equivalents, and restricted cash N/A $ 12,354 N/A $ (102 ) Cash and cash equivalents at beginning of period $ 18 N/A $ 120 N/A Cash, cash equivalents, and restricted cash at beginning of period N/A $ 18 N/A $ 120 Cash and cash equivalents at end of period $ 9,372 N/A $ 18 N/A Cash, cash equivalents, and restricted cash at end of period N/A $ 12,372 N/A $ 18 The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the accompanying balance sheets to the amounts shown in the accompanying statements of cash flows: December 31, 2017 2016 2015 (in thousands) Cash and cash equivalents $ 313,943 $ 9,372 $ 18 Restricted cash (1) — 3,000 — Total cash, cash equivalents, and restricted cash shown in the accompanying statements of cash flows $ 313,943 $ 12,372 $ 18 ____________________________________________ (1) Restricted cash is included in other noncurrent assets on the accompanying balance sheets. 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. The Company adopted ASU 2014-09 and all related ASUs using a modified retrospective transition method on the effective date of January 1, 2018 and will apply the new guidance to contracts for which all, or substantially all, of the revenue has not been recognized as of December 31, 2017 under legacy revenue guidance. This adoption will not result in a material change to current or prior period results, business processes, systems, or controls. However, upon adoption the Company will expand its current disclosures to comply with the disclosure requirements of the new guidance. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”) , which requires lessees to recognize a right-of-use asset and a lease liability for virtually all leases currently classified as operating leases. The Company is currently analyzing the impact this standard will have on the Company’s contract portfolio, including non-cancelable leases, drilling rigs, pipeline gathering, transportation, gas processing, and other existing arrangements. Further, the Company is evaluating current accounting policies, applicable systems, controls, and processes to support the potential recognition and disclosure changes resulting from ASU 2016-02. Based upon the Company’s initial assessment, ASU 2016-02 is expected to result in an increase in assets and liabilities recorded. The Company will adopt ASU 2016-02 using a modified retrospective method on the effective date of January 1, 2019. In January 2018, the FASB issued ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842 (“ASU 2018-01”). ASU 2018-01 provides an optional transitional practical expedient which allows entities to exclude from evaluation land easements that exist or expired before adoption of ASU 2016-02. The Company is currently evaluating this practical expedient and will adopt ASU 2018-01 at the same time as ASU 2016-02. 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 has determined that the adoption of ASU 2017-01 on the effective date of January 1, 2018, using a prospective method, does not impact the Company’s current consolidated financial statements or disclosures. However, the clarified definition of a business will be applied by the Company to future transactions. In February 2017, the FASB issued ASU No. 2017-05, Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets (“ASU 2017-05”). ASU 2017-05 is meant to clarify the scope of Accounting Standards Codification (“ASC”) Subtopic 610-20, Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets and to add guidance for partial sales of nonfinancial assets. The Company has determined that the adoption of ASU 2017-05 on the effective date of January 1, 2018, using a modified retrospective method, does not impact the Company’s current consolidated financial statements or disclosures. In March 2017, the FASB issued ASU No. 2017-07, Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (“ASU 2017-07”). ASU 2017-07 requires presentation of service cost in the same line item(s) as other compensation costs arising from services rendered by employees during the period and presentation of the remaining components of net benefit cost in a separate line item, outside operating items. In addition, only the service cost component of net benefit cost is eligible for capitalization. The Company adopted ASU 2017-07 on the effective date of January 1, 2018, with retrospective application of the service cost component and the other components of net benefit cost in the consolidated statements of operations and prospective application for the capitalization of the service cost component of net benefit costs in assets. While the adoption of ASU 2017-07 resulted in the Company reclassifying certain amounts from operating expenses to non-operating expenses, ASU 2017-07 did not result in a material impact to the Company’s consolidated financial statements or disclosures. In February 2018, the FASB issued ASU No. 2018-02, Income Statement – Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (“ASU 2018-02”). ASU 2018-02 permits entities to reclassify tax effects stranded in accumulated other comprehensive income (loss) to retained earnings as a result of the 2017 Tax Act. ASU 2018-02, is to be applied either in the period of adoption or retrospectively to each period (or periods) in which the effect of the change in the United States federal corporate income tax rate in the 2017 Tax Act is recognized. The guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2018. Early adoption is permitted as outlined in ASU 2018-02. The Company is currently evaluating the provisions of this guidance and assessing the potential impact on the Company’s consolidated financial statements and disclosures. There are no other ASUs applicable to the Company that would have a material effect on the Company’s consolidated financial statements and related disclosures that have been issued but not yet adopted by the Company as of December 31, 2017 , and through the filing of this report.
Pension and Other Postretirement Plans, Pensions [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 accumulated other comprehensive income (loss), net of tax. 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 [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 Accoun22

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 2015 Major customer #1 (1) 10 % 5 % 4 % Major customer #2 (2) 7 % 18 % 21 % Group #1 of entities under common ownership (3) 17 % 15 % 10 % Group #2 of entities under common ownership (3) 8 % 8 % 11 % ____________________________________________ (1) This major customer is a purchaser of the Company’s production from its Permian region. (2) This major customer was the operator of the Company’s outside-operated Eagle Ford shale program, which was divested of during the first quarter of 2017. Prior to the divestiture, the Company was party to various marketing agreements, which included certain gathering, transportation, and processing throughput commitments. Because the Company shared with the operator the risk of non-performance by its counterparty purchasers, the Company included the operator as a major customer in the table above. Several of the operator’s counterparty purchasers under these contracts were also direct purchasers of the Company’s production from other areas. (3) In the aggregate these groups of entities under common ownership represent more than 10 percent of total oil, gas, and NGL production revenue for the period(s) shown, however, none of the individual entities comprising either group represented more than 10 percent of the Company’s total oil, gas, and NGL production revenue.
Schedule of Weighted-Average Anti-Dilutive Securities Excluded from Computation of Earnings Per Share [Table Text Block]	The following table details the weighted-average anti-dilutive securities for the years presented: For the Years Ended December 31, 2017 2016 2015 (in thousands) Anti-dilutive 264 280 256
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]	The following table sets forth the calculations of basic and diluted net loss per common share: For the Years Ended December 31, 2017 2016 2015 (in thousands, except per share data) Net loss $ (160,843 ) $ (757,744 ) $ (447,710 ) Basic weighted-average common shares outstanding 111,428 76,568 67,723 Add: dilutive effect of non-vested RSUs and contingent PSUs — — — Add: dilutive effect of Senior Convertible Notes — — — Diluted weighted-average common shares outstanding 111,428 76,568 67,723 Basic net loss per common share $ (1.44 ) $ (9.90 ) $ (6.61 ) Diluted net loss per common share $ (1.44 ) $ (9.90 ) $ (6.61 )
Schedule of New Accounting Pronouncements and Changes in Accounting Principles [Table Text Block]	The December 31, 2016, and 2015 accompanying statements of cash flows line items that were adjusted as a result of the adoption of ASU 2016-15 and ASU 2016-18 are summarized as follows: For the Years Ended December 31, 2016 2015 As Reported As Adjusted As Reported As Adjusted (in thousands) Non-cash (gain) loss on extinguishment of debt $ (15,722 ) N/A $ 4,123 N/A (Gain) loss on extinguishment of debt N/A $ (15,722 ) N/A $ 16,578 Net cash provided by operating activities $ 552,804 $ 552,804 $ 978,352 $ 990,807 Other, net $ (3,000 ) $ — $ (985 ) $ (985 ) Net cash used in investing activities $ (1,870,639 ) $ (1,867,639 ) $ (1,144,639 ) $ (1,144,639 ) Cash paid for extinguishment of debt N/A $ — N/A $ (12,455 ) Net cash provided by financing activities $ 1,327,189 $ 1,327,189 $ 166,185 $ 153,730 Net change in cash and cash equivalents $ 9,354 N/A $ (102 ) N/A Net change in cash, cash equivalents, and restricted cash N/A $ 12,354 N/A $ (102 ) Cash and cash equivalents at beginning of period $ 18 N/A $ 120 N/A Cash, cash equivalents, and restricted cash at beginning of period N/A $ 18 N/A $ 120 Cash and cash equivalents at end of period $ 9,372 N/A $ 18 N/A Cash, cash equivalents, and restricted cash at end of period N/A $ 12,372 N/A $ 18 The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the accompanying balance sheets to the amounts shown in the accompanying statements of cash flows: December 31, 2017 2016 2015 (in thousands) Cash and cash equivalents $ 313,943 $ 9,372 $ 18 Restricted cash (1) — 3,000 — Total cash, cash equivalents, and restricted cash shown in the accompanying statements of cash flows $ 313,943 $ 12,372 $ 18 ____________________________________________ (1) Restricted cash is included in other noncurrent assets on the accompanying balance sheets.

Accounts Receivable and Accou23

Accounts Receivable and Accounts Payable and Accrued Expenses (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 (in thousands) Oil, gas, and NGL production revenue $ 96,610 $ 96,101 Amounts due from joint interest owners 56,929 29,669 State severance tax refunds 2,276 15,320 Derivative settlements 99 6,512 Other 4,240 4,348 Total accounts receivable $ 160,154 $ 151,950
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, 2017 2016 (in thousands) Capital expenditures $ 164,620 $ 107,009 Revenue and severance tax payable 60,328 39,617 Lease operating expense 22,078 15,956 Property taxes 13,222 6,606 Compensation 39,471 34,761 Derivative settlements 12,644 6,473 Interest 45,057 45,059 Other 29,210 44,227 Total accounts payable and accrued expenses $ 386,630 $ 299,708

Fair Value of Acquired Properti

Fair Value of Acquired Properties (Tables)	12 Months Ended
	Dec. 31, 2017
Acquisitions, Divestitures, and Assets Held for Sale Disclosure [Abstract]
Income (loss) before income taxes from sold assets [Table Text Block]	The following table presents income (loss) before income taxes from the outside-operated Eagle Ford shale assets sold for the years ended December 31, 2017 , 2016 , and 2015 . This divestiture was considered a disposal of a significant asset group. For the Years Ended December 31, 2017 2016 2015 (in thousands) Income (loss) before income taxes (1) $ 24,324 $ (218,506 ) $ 71,556 ____________________________________________ (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 approximately $269.6 million of impairment of proved properties expense for the year ended December 31, 2016 .
Rock Oil schedule of fair value of assets and liabilities acquired [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. 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. Refer to Note 11 – Fair Value Measurements for additional discussion on the valuation techniques used in determining the fair value of the acquired properties. 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

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Schedule of componenets of provision for income taxes [Table Text Block]	The provision for income taxes consists of the following: For the Years Ended December 31, 2017 2016 2015 (in thousands) Current portion of income tax expense Federal $ 5,698 $ 2,932 $ — State 3,398 1,539 1,571 Deferred portion of income tax benefit (192,066 ) (448,643 ) (276,722 ) Total income tax benefit $ (182,970 ) $ (444,172 ) $ (275,151 ) Effective tax rate 53.2 % 37.0 % 38.1 %
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, 2017 2016 (in thousands) Deferred tax liabilities Oil and gas properties $ 142,467 $ 518,394 Other 3,412 7,733 Total deferred tax liabilities 145,879 526,127 Deferred tax assets Derivative liabilities 29,463 31,349 Credit carryover 22,537 12,448 Pension 7,986 10,366 Federal and state tax net operating loss carryovers 3,867 151,343 Stock compensation 3,545 10,083 Other liabilities 1,470 201 Total deferred tax assets 68,868 215,790 Valuation allowance (2,978 ) (5,335 ) Net deferred tax assets 65,890 210,455 Total net deferred tax liabilities $ 79,989 $ 315,672 Current federal income tax refundable $ 37 $ 644 Current state income tax payable $ 3,009 $ 1,181
Schedule of effective income tax rate reconciliation [Table Text Block]	Federal income tax benefit differs from the amount that would be provided by applying the U.S. federal statutory rate to income before income taxes primarily due to the effect of state income taxes, changes in valuation allowances, R&D credits, and accumulated impacts of other smaller permanent differences, reported as follows: For the Years Ended December 31, 2017 2016 2015 (in thousands) Federal statutory tax benefit $ (120,335 ) $ (420,671 ) $ (253,001 ) Increase (decrease) in tax resulting from: Federal tax reform changes - 2017 Tax Act (63,675 ) — — State tax benefit (net of federal benefit) (3,286 ) (17,549 ) (21,583 ) Change in valuation allowance (2,727 ) (5,059 ) 3,148 Employee share-based compensation 8,190 — — Other (1,137 ) (893 ) (3,715 ) Income tax benefit $ (182,970 ) $ (444,172 ) $ (275,151 )
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, 2017 2016 2015 (in thousands) Beginning balance $ 446 $ 2,782 $ 1,582 Additions for tax positions of prior years — 9 1,200 Settlements — (2,345 ) — Ending balance $ 446 $ 446 $ 2,782

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Borrowing Base Utilization Grid, Credit Facility [Table Text Block]	The borrowing base utilization grid under the Credit Agreement is as follows: Borrowing Base Utilization Percentage <25% ≥25% <50% ≥50% <75% ≥75% <90% ≥90% Eurodollar Loans 1.750 % 2.000 % 2.250 % 2.500 % 2.750 % ABR Loans or Swingline Loans 0.750 % 1.000 % 1.250 % 1.500 % 1.750 % Commitment Fee Rate 0.300 % 0.300 % 0.350 % 0.375 % 0.375 %
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 14, 2018 , December 31, 2017 , and December 31, 2016 : As of February 14, 2018 As of December 31, 2017 As of December 31, 2016 (in thousands) Credit facility balance (1) $ — $ — $ — Letters of credit (2) 200 200 200 Available borrowing capacity 924,800 924,800 1,164,800 Total aggregate lender commitment amount $ 925,000 $ 925,000 $ 1,165,000 ____________________________________________ (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 $3.1 million and $5.9 million as of December 31, 2017 , and 2016 , respectively. (2) Letters of credit outstanding reduce the amount available under the credit facility on a dollar-for-dollar basis.
Schedule of Senior Notes [Table Text Block]	Senior Notes, net of unamortized deferred financing costs line on the accompanying balance sheets as of December 31, 2017 , and 2016 , consisted of the following: As of December 31, 2017 2016 Principal Amount Unamortized Deferred Financing Costs Senior Notes, Net of Unamortized Deferred Financing Costs Principal Amount Unamortized Deferred Financing Costs Senior Notes, Net of Unamortized Deferred Financing Costs (in thousands) 6.50% Senior Notes due 2021 $ 344,611 $ 2,656 $ 341,955 $ 346,955 $ 3,372 $ 343,583 6.125% Senior Notes due 2022 561,796 5,800 555,996 561,796 6,979 554,817 6.50% Senior Notes due 2023 394,985 3,707 391,278 394,985 4,436 390,549 5.0% Senior Notes due 2024 500,000 5,610 494,390 500,000 6,533 493,467 5.625% Senior Notes due 2025 500,000 6,714 493,286 500,000 7,619 492,381 6.75% Senior Notes due 2026 500,000 7,242 492,758 500,000 8,078 491,922 Total $ 2,801,392 $ 31,729 $ 2,769,663 $ 2,803,736 $ 37,017 $ 2,766,719
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, 2017 and 2016: As of December 31, 2017 2016 (in thousands) Principal amount of Senior Convertible Notes $ 172,500 $ 172,500 Unamortized debt discount (30,183 ) (37,513 ) Unamortized deferred financing costs (3,210 ) (4,131 ) Net carrying amount $ 139,107 $ 130,856 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, 2017 and 2016: As of December 31, 2017 2016 (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, 2017
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) 2018 $ 113,774 2019 112,860 2020 111,107 2021 102,606 2022 72,073 Thereafter 62,245 Total $ 574,665

Compensation Plans (Tables)

Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2017
Compensation Related Costs [Abstract]
Schedule of performance share awards under equity incentive compensation plan	A summary of the status and activity of non-vested PSUs is presented in the following table: For the Years Ended December 31, 2017 2016 2015 PSUs Weighted-Average Grant-Date Fair Value PSUs Weighted-Average Grant-Date Fair Value PSUs Weighted-Average Grant-Date Fair Value Non-vested at beginning of year (1) 828,923 $ 43.25 626,328 $ 61.81 433,660 $ 73.63 Granted (1) 977,731 $ 15.86 447,971 $ 26.56 320,753 $ 45.34 Vested (1) (94,338 ) $ 85.85 (130,353 ) $ 64.17 (76,438 ) $ 51.76 Forfeited (1) (178,825 ) $ 44.99 (115,023 ) $ 55.59 (51,647 ) $ 73.62 Non-vested at end of year (1) 1,533,491 $ 22.97 828,923 $ 43.25 626,328 $ 61.81 ____________________________________________ (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 years ended December 31, 2016 , and 2015 , is presented in the table below: For the Years Ended December 31, 2016 2015 Shares of common stock issued to settle PSUs (1) 44,870 288,962 Less: shares of common stock withheld for income and payroll taxes (14,809 ) (100,683 ) Net shares of common stock issued 30,061 188,279 Multiplier earned 0.2 1.0 ____________________________________________ (1) During the years ended December 31, 2016 , and 2015 , the Company issued shares of common stock for PSUs granted in 2013, and 2012. 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 for eligible employees is presented in the following table: For the Years Ended December 31, 2017 2016 2015 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 604,116 $ 37.39 543,737 $ 55.01 515,724 $ 68.29 Granted 1,020,780 $ 16.64 417,065 $ 28.08 356,246 $ 43.72 Vested (246,025 ) $ 43.99 (241,363 ) $ 58.06 (278,289 ) $ 63.12 Forfeited (134,609 ) $ 26.38 (115,323 ) $ 43.52 (49,944 ) $ 66.53 Non-vested at end of year 1,244,262 $ 20.25 604,116 $ 37.39 543,737 $ 55.01
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, 2017 2016 2015 Shares of common stock issued to settle RSUs (1) 246,025 241,363 278,289 Less: shares of common stock withheld for income and payroll taxes (74,747 ) (72,181 ) (91,045 ) Net shares of common stock issued 171,278 169,182 187,244 ____________________________________________ (1) During the years ended December 31, 2017 , 2016 , and 2015 , the Company issued shares of common stock for RSUs granted in previous years. The Company and a majority of grant recipients mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings in accordance with the Company’s Equity Plan and individual award agreements.
Schedule of employee stock purchase plan	The fair value of ESPP shares issued during the periods reported were estimated using the following weighted-average assumptions: For the Years Ended December 31, 2017 2016 2015 Risk free interest rate 0.9 % 0.4 % 0.1 % Dividend yield 0.5 % 0.4 % 0.2 % Volatility factor of the expected market price of the Company’s common stock 62.5 % 95.0 % 61.2 % Expected life (in years) 0.5 0.5 0.5
Schedule of net profits plan cash payment allocation	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 on divestiture activity line item in the accompanying statements of operations. For the Years Ended December 31, 2017 2016 2015 (in thousands) Cash payments made or accrued related to operations $ (54 ) $ 6,608 $ 3,498 Cash payments made or accrued related to divestitures 2,753 24,349 3,789 Total net settlements $ 2,699 $ 30,957 $ 7,287
[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, 2017
Defined Benefit Plan [Abstract]
Schedule of Net Funded Status [Table Text Block]	For the Years Ended December 31, 2017 2016 (in thousands) Change in benefit obligation: Projected benefit obligation at beginning of year $ 69,659 $ 62,547 Service cost 6,638 8,200 Interest cost 2,689 2,908 Actuarial loss 3,708 2,662 Benefits paid (10,757 ) (6,658 ) Projected benefit obligation at end of year 71,937 69,659 Change in plan assets: Fair value of plan assets at beginning of year 31,731 25,769 Actual return on plan assets 2,956 1,575 Employer contribution 7,048 11,045 Benefits paid (10,757 ) (6,658 ) Fair value of plan assets at end of year 30,978 31,731 Funded status at end of year $ (40,959 ) $ (37,928 )
Schedule of Accumulated Benefit Obligation in Excess of Fair Value of Plan Assets [Table Text Block]	As of December 31, 2017 2016 (in thousands) Projected benefit obligation $ 71,937 $ 69,659 Accumulated benefit obligation $ 56,045 $ 54,681 Less: Fair value of plan assets (30,978 ) (31,731 ) Underfunded accumulated benefit obligation $ 25,067 $ 22,950
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, 2017 , and 2016 , were as follows: As of December 31, 2017 2016 (in thousands) Unrecognized actuarial losses $ 21,397 $ 22,708 Unrecognized prior service costs 66 83 Accumulated other comprehensive loss $ 21,463 $ 22,791
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 2017 , 2016 , and 2015 , were as follows: For the Years Ended December 31, 2017 2016 2015 (in thousands) Net actuarial loss $ (2,995 ) $ (3,322 ) $ (4,990 ) Amortization of prior service cost 17 16 17 Amortization of net actuarial loss 1,297 1,582 1,486 Settlements 3,009 — 350 Total pension liability adjustment, pre-tax 1,328 (1,724 ) (3,137 ) Tax (expense) benefit (561 ) 570 1,047 Total pension liability adjustment, net of tax $ 767 $ (1,154 ) $ (2,090 )
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, 2017 2016 2015 (in thousands) Components of net periodic benefit cost: Service cost $ 6,638 $ 8,200 $ 7,949 Interest cost 2,689 2,908 2,496 Expected return on plan assets that reduces periodic pension benefit cost (2,244 ) (2,235 ) (2,182 ) Amortization of prior service cost 17 16 17 Amortization of net actuarial loss 1,297 1,582 1,486 Settlements 3,009 — 350 Net periodic benefit cost $ 11,406 $ 10,471 $ 10,116
Schedule of 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, 2017 2016 Projected benefit obligation: Discount rate 3.8% 4.2% 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, 2017 2016 2015 Net periodic benefit cost: Discount rate 4.2% 4.7% 4.3% Expected return on plan assets (1) 6.5% 7.5% 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 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 2018 2017 2016 Equity securities 35.0 % 38.4 % 28.8 % Fixed income securities 43.0 % 39.8 % 35.5 % Other securities 22.0 % 21.8 % 35.7 % Total 100.0 % 100.0 % 100.0 %
Schedule of Fair Values of the Qualified Plan Assets [Table Text Block]	The fair values of the Company’s Qualified Pension Plan assets as of December 31, 2017 , and 2016 , 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, 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 corp 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 As of December 31, 2016 Cash — % $ — $ — $ — $ — Equity securities: Domestic (2) 18.7 % 5,945 4,471 1,474 — International (3) 10.1 % 3,192 3,192 — — Total equity securities 28.8 % 9,137 7,663 1,474 — Fixed income securities: High-yield bonds (4) 2.6 % 822 822 — — Core fixed income (5) 25.0 % 7,923 7,923 — — Floating rate corp loans (6) 7.9 % 2,495 2,495 — — Total fixed income securities 35.5 % 11,240 11,240 — — Other securities: Commodities (7) 1.8 % 578 578 — — Real estate (8) 5.1 % 1,629 — — 1,629 Collective investment trusts (9) 17.5 % 5,562 — 5,562 — Hedge fund (10) 11.3 % 3,585 — — 3,585 Total other securities 35.7 % 11,354 578 5,562 5,214 Total investments 100.0 % $ 31,731 $ 19,481 $ 7,036 $ 5,214 ____________________________________________ (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 this fund 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 an investment in an actively traded global mutual fund that focuses 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, 2016 $ 5,045 Purchases 561 Realized gain on assets 54 Unrealized gain on assets 115 Disposition (561 ) Balance at December 31, 2016 $ 5,214 Purchases 300 Realized gain on assets 130 Unrealized gain on assets 120 Disposition (555 ) Balance at December 31, 2017 $ 5,209
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) 2018 $ 4,217 2019 $ 3,818 2020 $ 4,363 2021 $ 5,561 2022 $ 6,117 2023 through 2027 $ 36,279

Reconciliation of Asset Retirem

Reconciliation of Asset Retirement Obligation Liability (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 (in thousands) Beginning asset retirement obligations $ 123,307 $ 140,874 Liabilities incurred (1) 7,588 21,293 Liabilities settled (2) (30,432 ) (57,100 ) Accretion expense 5,988 7,795 Revision to estimated cash flows 8,019 10,445 Ending asset retirement obligations (3)(4) $ 114,470 $ 123,307 ____________________________________________ (1) Reflects liabilities incurred through drilling activities and acquisitions of drilled wells. (2) Reflects liabilities settled through plugging and abandonment activities and divestitures of properties. (3) Balances as of December 31, 2017 , and 2016 , included $11.4 million and $26.2 million , respectively, of asset retirement obligations associated with oil and gas properties held for sale. (4) Balances as of December 31, 2017 , and 2016 , included $75,000 and $932,000 , respectively, related to the Company’s current asset retirement obligation liability, which is recorded in accounts payable and accrued expenses on the accompanying balance sheets.

Derivative Financial Instrume31

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [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 2018 1,075 $ 50.16 Second quarter 2018 1,534 $ 49.57 Third quarter 2018 1,769 $ 49.77 Fourth quarter 2018 1,894 $ 49.87 2019 1,940 $ 50.70 Total 8,212 Oil Collars Contract Period NYMEX WTI Volumes Weighted-Average Floor Price Weighted-Average Ceiling Price (MBbl) (per Bbl) (per Bbl) First quarter 2018 1,445 $ 50.00 $ 59.07 Second quarter 2018 1,459 $ 50.00 $ 59.03 Third quarter 2018 1,948 $ 50.00 $ 58.61 Fourth quarter 2018 2,222 $ 50.00 $ 58.44 2019 5,908 $ 47.65 $ 59.19 Total 12,982 Oil Basis Swaps Contract Period Midland-Cushing Volumes Weighted-Average Contract Price (1) (MBbl) (per Bbl) First quarter 2018 2,113 $ (1.15 ) Second quarter 2018 2,392 $ (1.03 ) Third quarter 2018 3,018 $ (1.06 ) Fourth quarter 2018 3,327 $ (1.08 ) 2019 5,788 $ (1.09 ) Total 16,638 ____________________________________________ (1) Represents the price differential between WTI prices at Midland, Texas and WTI prices at Cushing, Oklahoma. Gas Swaps Contract Period Sold Volumes Weighted-Average Contract Price Purchased Volumes Weighted-Average Contract Price Net Volumes (BBtu) (per MMBtu) (BBtu) (per MMBtu) (BBtu) First quarter 2018 28,910 $ 3.55 (8,121 ) $ 4.34 20,789 Second quarter 2018 23,507 $ 3.31 (7,795 ) $ 4.24 15,712 Third quarter 2018 24,627 $ 3.29 (7,480 ) $ 4.23 17,147 Fourth quarter 2018 25,856 $ 3.29 (7,210 ) $ 4.27 18,646 2019 41,394 $ 3.76 (24,415 ) $ 4.34 16,979 Total (1) 144,294 (55,021 ) 89,273 ____________________________________________ (1) Total net volumes of gas swaps are comprised of IF HSC ( 99% ) and IF El Paso Permian ( 1% ). NGL Swaps OPIS Purity Ethane 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 2018 923 $ 10.90 629 $ 25.39 206 $ 35.83 167 $ 35.76 188 $ 49.40 Second quarter 2018 915 $ 10.87 554 $ 24.94 84 $ 35.69 66 $ 35.07 109 $ 49.57 Third quarter 2018 1,033 $ 10.99 610 $ 24.27 93 $ 35.70 70 $ 35.07 118 $ 49.56 Fourth quarter 2018 1,146 $ 11.18 671 $ 24.39 102 $ 35.70 76 $ 35.07 129 $ 49.57 2019 3,533 $ 12.31 1,503 $ 27.83 154 $ 35.64 117 $ 35.70 197 $ 50.93 2020 539 $ 11.13 — $ — — $ — — $ — — $ — Total 8,089 3,967 639 496 741
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, 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 As of December 31, 2016 Derivative Assets Derivative Liabilities Balance Sheet Classification Fair Value Balance Sheet Classification Fair Value (in thousands) Commodity contracts Current assets $ 54,521 Current liabilities $ 115,464 Commodity contracts Noncurrent assets 67,575 Noncurrent liabilities 98,340 Total commodity contracts $ 122,096 $ 213,804
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 2017 2016 2017 2016 (in thousands) Gross amounts presented in the accompanying balance sheets $ 104,628 $ 122,096 $ (243,984 ) $ (213,804 ) Amounts not offset in the accompanying balance sheets (100,035 ) (118,080 ) 100,035 118,080 Net amounts $ 4,593 $ 4,016 $ (143,949 ) $ (95,724 )
Schedule of gains and losses on derivative instruments in the statement of operations	The following table summarizes the components of net derivative (gain) loss presented in the accompanying statements of operations: For the Years Ended December 31, 2017 2016 2015 (in thousands) Derivative settlement (gain) loss: Oil contracts $ 31,176 $ (243,102 ) $ (362,219 ) Gas contracts (1) (87,857 ) (94,936 ) (123,180 ) NGL contracts 35,447 8,560 (27,167 ) Total derivative settlement gain $ (21,234 ) $ (329,478 ) $ (512,566 ) Net derivative (gain) loss: Oil contracts $ 71,502 $ 85,370 $ (191,165 ) Gas contracts (76,315 ) 81,060 (189,734 ) NGL contracts 31,227 84,203 (27,932 ) Total net derivative (gain) loss $ 26,414 $ 250,633 $ (408,831 ) ____________________________________________ (1) Gas derivative settlements for the year ended December 31, 2015, include $15.3 million of early settlements of futures contracts as a result of divesting assets in the Company’s Mid-Continent region.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2017
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, 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. 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, 2016 : Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 122,096 $ — Total property and equipment, net (2) $ — $ — $ 88,205 Liabilities: Derivatives (1) $ — $ 213,804 $ — ____________________________________________ (1) This represents a financial asset or liability that is measured at fair value on a recurring basis. (2) This represents a non-financial asset that is measured at fair value on a nonrecurring basis.	[1],[2],[3]
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, 2017 2016 2015 (in millions) Abandonment and impairment of unproved properties $ 12.3 $ 80.4 $ 78.6
Long Term Debt Fair Value [Table Text Block]	The following table reflects the fair value of the Senior Notes and Senior Convertible Notes 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, 2017 , or 2016 , as they are 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, 2017 2016 Principal Amount Fair Value Principal Amount Fair Value (in thousands) 6.50% Senior Notes due 2021 $ 344,611 $ 351,682 $ 346,955 $ 354,546 6.125% Senior Notes due 2022 $ 561,796 $ 571,627 $ 561,796 $ 570,925 6.50% Senior Notes due 2023 $ 394,985 $ 403,434 $ 394,985 $ 403,134 5.0% Senior Notes due 2024 $ 500,000 $ 483,440 $ 500,000 $ 475,975 5.625% Senior Notes due 2025 $ 500,000 $ 494,355 $ 500,000 $ 485,000 6.75% Senior Notes due 2026 $ 500,000 $ 516,350 $ 500,000 $ 516,565 1.50% Senior Convertible Notes due 2021 $ 172,500 $ 168,291 $ 172,500 $ 202,189
[1]	This represents a financial asset or liability that is measured at fair value on a recurring basis.
[2]	This represents a financial asset or liability that is measured at fair value on a recurring basis.
[3]	This represents a non-financial asset that is measured at fair value on a nonrecurring basis.

Suspended Well Costs (Tables)

Suspended Well Costs (Tables)	12 Months Ended
	Dec. 31, 2017
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 2017 , 2016 , and 2015 . 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, 2017 2016 2015 (in thousands) Beginning balance $ 19,846 $ 11,952 $ 43,589 Additions to capitalized exploratory well costs pending the determination of proved reserves 49,446 19,846 11,952 Divestitures — — (809 ) Reclassifications to wells, facilities, and equipment based on the determination of proved reserves (19,846 ) (11,952 ) (18,485 ) Capitalized exploratory well costs charged to expense — — (24,295 ) Ending balance $ 49,446 $ 19,846 $ 11,952

Summary of Significant Accoun34

Summary of Significant Accounting Policies Other (Details)		12 Months Ended
		Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Jan. 01, 2017USD ($)
Basis of Presentation and Significant Accounting Policies [Line Items]
Retained earnings		$ (665,657,000)	$ (794,020,000)
Deferred Tax Assets, Net of Valuation Allowance, Noncurrent		65,890,000	210,455,000
Cash and cash equivalents		313,943,000	9,372,000	$ 18,000
Restricted Cash	[1]	0	3,000,000	0
Cash, cash equivalents, and restricted cash at end of period	[2]	$ 313,943,000	12,372,000	$ 18,000
Accounts Receivable Additional Disclosures [Abstract]
Receivables Collection Period		2 months
Concentration of Credit Risk and Major Customers [Abstract]
Number of individual entities within groups of entities under common ownership that represent more than 10 percent of total production revenue		0
Number of Derivative Counterparties		10
ASU 2016-09 Cumulative Effect Adjustment for Timing of Recognition of Excess Tax Benefits [Member]
Basis of Presentation and Significant Accounting Policies [Line Items]
Retained earnings					$ (44,300,000)
ASU 2016-09 Cumulative Effect of Actual Forfeiture Rate [Member]
Basis of Presentation and Significant Accounting Policies [Line Items]
Retained earnings					700,000
Additional Paid in Capital					1,100,000
Deferred Tax Assets, Net of Valuation Allowance, Noncurrent					$ (400,000)
Revolving Credit Facility [Member] | Line of Credit [Member]
Basis of Presentation and Significant Accounting Policies [Line Items]
Long-term Line of Credit		$ 0
1.50% Senior Convertible Notes Due 2021 [Member]
Basis of Presentation and Significant Accounting Policies [Line Items]
Senior Notes, face amount		$ 172,500,000	$ 172,500,000
Minimum [Member]
Revenues [Abstract]
Revenue Receipt, Days After Sale		30 days
Maximum [Member]
Revenues [Abstract]
Revenue Receipt, Days After Sale		90 days
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
Asset Retirement Obligation Costs [Member] | Minimum [Member]
Asset Retirement Obligations [Abstract]
Fair Value Assumptions, Risk Free Interest Rate		5.50%
Asset Retirement Obligation Costs [Member] | Maximum [Member]
Asset Retirement Obligations [Abstract]
Fair Value Assumptions, Risk Free Interest Rate		12.00%
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	[3]	10.00%	5.00%	4.00%
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]	7.00%	18.00%	21.00%
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]	17.00%	15.00%	10.00%
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]	8.00%	8.00%	11.00%
[1]	Restricted cash is included in other noncurrent assets on the accompanying balance sheets.
[2]	(1) Refer to Note 1 – Summary of Significant Accounting Policies for a reconciliation of cash, cash equivalents, and restricted cash reported to the amounts reported within the accompanying balance sheets.
[3]	This major customer is a purchaser of the Company’s production from its Permian region.
[4]	This major customer was the operator of the Company’s outside-operated Eagle Ford shale program, which was divested of during the first quarter of 2017. Prior to the divestiture, the Company was party to various marketing agreements, which included certain gathering, transportation, and processing throughput commitments. Because the Company shared with the operator the risk of non-performance by its counterparty purchasers, the Company included the operator as a major customer in the table above. Several of the operator’s counterparty purchasers under these contracts were also direct purchasers of the Company’s production from other areas.
[5]	In the aggregate these groups of entities under common ownership represent more than 10 percent of total oil, gas, and NGL production revenue for the period(s) shown, however, none of the individual entities comprising either group represented more than 10 percent of the Company’s total oil, gas, and NGL production revenue.

Summary of Significant Accoun35

Summary of Significant Accounting Policies Earnings Per Share (Details) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)$ / sharesshares	Dec. 31, 2016USD ($)$ / sharesshares	Dec. 31, 2015USD ($)$ / sharesshares
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Capped call, cap price | $ / shares	$ 60
Anti-dilutive Securities Excluded from Computation of Earnings Per Share, Amount	264	280	256
Earnings Per Share Reconciliation [Abstract]
Net loss | $	$ (160,843)	$ (757,744)	$ (447,710)
Basic weighted-average common shares outstanding	111,428	76,568	67,723
Dilutive effect of non-vested RSUs and contingent PSUs	0	0	0
Dilutive effect of Senior Convertible Notes	0	0	0
Diluted weighted-average common shares outstanding	111,428	76,568	67,723
Basic net loss per common share | $ / shares	$ (1.44)	$ (9.90)	$ (6.61)
Diluted net loss per common share | $ / shares	$ (1.44)	$ (9.90)	$ (6.61)
Performance Shares [Member]
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Award Vesting Period	3 years
Multiplier Applied to PSU Awards at Settlement		0.2	1
Minimum [Member] | Performance Shares [Member]
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Multiplier Applied to PSU Awards at Settlement	0
Maximum [Member] | Performance Shares [Member]
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Multiplier Applied to PSU Awards at Settlement	2
1.50% Senior Convertible Notes Due 2021 [Member]
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Senior Notes, face amount | $	$ 172,500	$ 172,500
Senior Convertible Notes, conversion price | $ / shares	$ 40.50

Summary of Significant Accoun36

Summary of Significant Accounting Policies ASU Adjustment (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Non-cash (gain) loss on extinguishment of debt, non cash portion		$ (22)	$ 15,722	$ (4,123)
(Gain) loss on extinguishment of debt		35	(15,722)	16,578
Net cash provided by operating activities		515,390	552,804	990,807
Other, net		0	0	(985)
Net cash used in investing activities		(201,530)	(1,867,639)	(1,144,639)
Cash paid for extinguishment of debt		(13)	0	(12,455)
Net cash provided by financing activities		(12,289)	1,327,189	153,730
Net change in cash, cash equivalents, and restricted cash	[1]	301,571	12,354	(102)
Cash and cash equivalents at beginning of period		9,372	18
Cash, cash equivalents, and restricted cash at beginning of period	[1]	12,372	18	120
Cash and cash equivalents at end of period		313,943	9,372	18
Cash, cash equivalents, and restricted cash at end of period	[1]	313,943	12,372	18
As Reported | Accounting Standards Update 2016-15, 2016-18
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Non-cash (gain) loss on extinguishment of debt, non cash portion			15,722	(4,123)
Net cash provided by operating activities			552,804	978,352
Other, net			(3,000)	(985)
Net cash used in investing activities			(1,870,639)	(1,144,639)
Net cash provided by financing activities			1,327,189	166,185
Net change in cash and cash equivalents			9,354	(102)
Cash and cash equivalents at beginning of period		$ 9,372	18	120
Cash and cash equivalents at end of period			$ 9,372	$ 18
[1]	(1) Refer to Note 1 – Summary of Significant Accounting Policies for a reconciliation of cash, cash equivalents, and restricted cash reported to the amounts reported within the accompanying balance sheets.

Accounts Receivable (Details)

Accounts Receivable (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Accounts Receivable
Accounts receivable	$ 160,154	$ 151,950
Oil, gas, and NGL production revenue [Member]
Accounts Receivable
Accounts receivable	96,610	96,101
Amounts due from joint interest owners [Member]
Accounts Receivable
Accounts receivable	56,929	29,669
State severance tax refunds [Member]
Accounts Receivable
Accounts receivable	2,276	15,320
Derivative settlements [Member]
Accounts Receivable
Accounts receivable	99	6,512
Other [Member]
Accounts Receivable
Accounts receivable	$ 4,240	$ 4,348

Accounts Payable and Accrued Ex

Accounts Payable and Accrued Expenses (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Accounts Payable and Accrued Liabilities, Current [Abstract]
Capital expenditures	$ 164,620	$ 107,009
Revenue and severance tax payable	60,328	39,617
Lease operating expense	22,078	15,956
Property taxes	13,222	6,606
Compensation	39,471	34,761
Derivative settlements	12,644	6,473
Interest	45,057	45,059
Other	29,210	44,227
Total accounts payable and accrued expenses	$ 386,630	$ 299,708

Divestitures and Assets Held fo

Divestitures and Assets Held for Sale (Details) - USD ($) $ in Thousands		2 Months Ended	3 Months Ended			12 Months Ended
		Feb. 14, 2018	Dec. 31, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
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						$ 776,719	$ 946,062	$ 357,938
Net gain (loss) on divestiture activity						(131,028)	37,074	43,031
Income (loss) before income taxes						(343,813)	(1,201,916)	(722,861)
Impairment of proved properties						$ 3,806	354,614	468,679
Assets Held-for-sale
Probable period within which sale will take place (in years)						1 year
Oil and gas properties held for sale, net			$ 111,700			$ 111,700	372,621
Asset retirement obligations associated with oil and gas properties held for sale			11,369			11,369	26,241
Disposal group, disposed of by sale, not discontinued operations [Member] | Outside-operated Eagle Ford divestiture 2017 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net proceeds from the sale of oil and gas properties						744,100
Net gain (loss) on divestiture activity						396,800
Income (loss) before income taxes	[1]					24,324	(218,506)	71,556
Impairment of proved properties							269,600
Disposal group, disposed of by sale, not discontinued operations [Member] | Other divestitures 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			$ 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, disposed of by sale, not discontinued operations [Member] | Mid Continent divestiture 2015 [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							310,300
Net gain (loss) on divestiture activity							$ 108,400
Disposal group, disposed of by sale, not discontinued operations [Member] | Permian divestiture 2015 [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								25,100
Net gain (loss) on divestiture activity								2,300
Disposal group, disposed of by sale, not discontinued operations [Member] | Other divestitures 2015 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Write-down on disposal group, not discontinued operations								$ 68,600
Disposal group, held-for-sale, not discontinued operations [Member] | Divide County disposal group [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment of proved properties						$ 526,500
Write-down on disposal group, not discontinued operations				$ 166,900	$ 359,600
Subsequent Event [Member] | Disposal group, held-for-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 proceeds from the sale of oil and gas properties		$ 500,000
[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 approximately $269.6 million of impairment of proved properties expense for the year ended December 31, 2016.

Acquisitions (Details)

Acquisitions (Details) $ / shares in Units, $ in Thousands, shares in Millions		Dec. 21, 2016USD ($)shares	Oct. 04, 2016USD ($)	Sep. 30, 2017USD ($)	Sep. 30, 2017USD ($)	Dec. 31, 2017USD ($)a$ / shares	Dec. 31, 2016USD ($)$ / shares	Dec. 31, 2015USD ($)	Dec. 31, 2017USD ($)$ / shares
Business Acquisition [Line Items]
Payments to acquire oil and gas property and equipment						$ 89,896	$ 2,183,790	$ 7,984
Carrying value of properties exchanged						293,963	733	$ 0
Wells in progress						321,347	235,147		$ 321,347
Proved oil and gas properties						6,139,379	5,700,418		6,139,379
Unproved oil and gas properties						$ 2,047,203	$ 2,471,947		$ 2,047,203
Common Stock, par value per share | $ / shares						$ 0.01	$ 0.01		$ 0.01
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
QStar Acquisition 2016 [Member]
Business Acquisition [Line Items]
Payments to acquire oil and gas property and equipment		$ 1,200,000		$ 7,300	$ 1,174,628
Wells in progress		21,812
Proved oil and gas properties		61,239
Unproved oil and gas properties		1,538,264
Working capital acquired		(1,852)
Asset retirement obligations		$ (7,641)
Acquisition of oil and gas properties, consideration paid					$ 1,600,000
Private issuance of Common Stock for an acquisition | shares		13.4
Fair value of equity consideration	[1]	$ 437,194
Total consideration		1,611,822
Total oil and gas properties acquired		$ 1,621,315
Rock Oil Acquisition 2016 [Member]
Business Acquisition [Line Items]
Payments to acquire a business, gross			$ 991,000			$ 7,700			$ 998,691
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 acquired			(1,127)
Asset retirement obligations			(7,595)
Total fair value of net assets acquired			$ 998,691
Other Howard and Martin Counties trades [Member]
Business Acquisition [Line Items]
Non-monetary trade, acreage acquired | a						8,125
Non-monetary trade, acreage exchanged | a						7,580
Carrying value of properties exchanged						$ 294,000
[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, 2017	Dec. 31, 2016	Dec. 31, 2015
Components of the provision for income taxes
Federal	$ 5,698,000	$ 2,932,000	$ 0
State	3,398,000	1,539,000	1,571,000
Deferred portion of income tax benefit	(192,066,000)	(448,643,000)	(276,722,000)
Total income tax benefit	$ (182,970,000)	$ (444,172,000)	$ (275,151,000)
Effective tax rate (as a percent)	53.20%	37.00%	38.10%
Deferred income taxes [Abstract]
Deferred tax liabilities, oil and gas properties	$ 142,467,000	$ 518,394,000
Deferred tax liabilities, other	3,412,000	7,733,000
Total deferred tax liabilities	145,879,000	526,127,000
Deferred tax assets, derivative liabilities	29,463,000	31,349,000
Deferred tax assets, credit carryover	22,537,000	12,448,000
Deferred tax assets, pension	7,986,000	10,366,000
Deferred tax assets, federal and state tax net operating loss carryovers	3,867,000	151,343,000
Deferred tax assets, stock-compensation	3,545,000	10,083,000
Deferred tax assets, other liabilities	1,470,000	201,000
Total deferred tax assets	68,868,000	215,790,000
Deferred tax assets, valuation allowance	(2,978,000)	(5,335,000)
Net deferred tax assets	65,890,000	210,455,000
Total net deferred tax liabilities	79,989,000	315,672,000
Proceeds from income tax refunds	5,500,000
Net R&D tax credit recorded for IRS settlement		2,000,000
Reconciliation of unrecognized tax benefits [Roll Forward]
Unrecognized tax benefits, Beginning balance	446,000	2,782,000	$ 1,582,000
Unrecognized tax benefits, additions for tax positions of prior years	0	9,000	1,200,000
Unrecognized tax benefits, settlements	0	(2,345,000)	0
Unrecognized tax benefits, Ending balance	$ 446,000	446,000	$ 2,782,000
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	$ 3,009,000	1,181,000
Net operating loss carryforwards	71,800,000
State tax credits [Member] | State and local jurisdiction [Member]
Deferred income taxes [Abstract]
Tax credit carryforwards	283,000
Internal Revenue Service (IRS) [Member] | Domestic tax authority [Member]
Deferred income taxes [Abstract]
Current federal income tax refundable	37,000	$ 644,000
Net operating loss carryforwards	1,300,000
Internal Revenue Service (IRS) [Member] | R&D tax credit carryforwards [Member] | Domestic tax authority [Member]
Deferred income taxes [Abstract]
Tax credit carryforwards	7,200,000
Internal Revenue Service (IRS) [Member] | Alternative minimum tax credit carryforward [Member] | Domestic tax authority [Member]
Deferred income taxes [Abstract]
Tax credit carryforwards	$ 15,700,000

Income Taxes (Reconciliation of

Income Taxes (Reconciliation of Tax Expense (Benefit)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Federal statutory tax benefit	$ (120,335)	$ (420,671)	$ (253,001)
Federal tax reform changes - 2017 Tax Act	(63,675)	0	0
State tax benefit (net of federal benefit)	(3,286)	(17,549)	(21,583)
Change in valuation allowance	(2,727)	(5,059)	3,148
Employee share based compensation	8,190	0	0
Other	(1,137)	(893)	(3,715)
Total income tax benefit	$ (182,970)	$ (444,172)	$ (275,151)

Long-term Debt Revolving Credit

Long-term Debt Revolving Credit Facility (Details)		12 Months Ended
		Dec. 31, 2017USD ($)	Feb. 14, 2018USD ($)	Dec. 31, 2016USD ($)
Line of Credit Facility [Line Items]
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		0.30%
Line of Credit [Member] | Borrowing Base Utilization Of More Than 25 Percent But Less Than 50 Percent [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, unused capacity, commitment fee rate		0.30%
Line of Credit [Member] | Borrowing Base Utilization Of More Than 50 Percent But Less Than 75 Percent [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, unused capacity, commitment fee rate		0.35%
Line of Credit [Member] | Borrowing Base Utilization Of More Than 75 Percent But Less Than 90 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 More Than 90 Percent [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, unused capacity, commitment fee rate		0.375%
Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, maximum loan amount		$ 2,500,000,000
Line of credit agreement, aggregate lender commitment amount		925,000,000		1,165,000,000
Credit facility balance	[1]	0		0
Letters of credit outstanding, amount	[2]	200,000		200,000
Available borrowing capacity		924,800,000		1,164,800,000
Unamortized deferred financing costs		$ 3,100,000		$ 5,900,000
Subsequent Event [Member] | Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, aggregate lender commitment amount			$ 925,000,000
Credit facility balance	[1]		0
Letters of credit outstanding, amount	[2]		200,000
Available borrowing capacity			$ 924,800,000
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		1.75%
Eurodollar [Member] | Line of Credit [Member] | Borrowing Base Utilization Of More Than 25 Percent But Less Than 50 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 More Than 50 Percent But Less Than 75 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 More Than 75 Percent But Less Than 90 Percent [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, basis spread on variable rate		2.50%
Eurodollar [Member] | Line of Credit [Member] | Borrowing Base Utilization Of More Than 90 Percent [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, basis spread on variable rate		2.75%
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		0.75%
Debt Instrument Variable Rate, Alternative Base Rate, And Swingline Loans [Member] | Line of Credit [Member] | Borrowing Base Utilization Of More Than 25 Percent But Less Than 50 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 More Than 50 Percent But Less Than 75 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 More Than 75 Percent But Less Than 90 Percent [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, basis spread on variable rate		1.50%
Debt Instrument Variable Rate, Alternative Base Rate, And Swingline Loans [Member] | Line of Credit [Member] | Borrowing Base Utilization Of More Than 90 Percent [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, basis spread on variable rate		1.75%
Maximum [Member] | Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, covenant compliance, senior secured debt to adjusted EBITDAX ratio		2.75
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
Line of credit agreement, covenant compliance, adjusted EBITDAX to interest expense ratio		2
[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 $3.1 million and $5.9 million as of December 31, 2017, and 2016, respectively.
[2]	Letters of credit outstanding reduce the amount available under the credit facility on a dollar-for-dollar basis.

Senior Notes(Details)

Senior Notes(Details) - USD ($)	May 21, 2015	Nov. 17, 2014	May 20, 2013	Jun. 29, 2012	Nov. 08, 2011	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Mar. 31, 2017	Sep. 12, 2016
Senior Notes [Line Items]
Senior Notes, net of unamortized deferred financing costs							$ 2,769,663,000	$ 2,766,719,000
Gain (loss) on extinguishment of debt							(35,000)	15,722,000	$ (16,578,000)
Loss on extinguishment of debt, acceleration of unamortized deferred financing costs							$ 22,000	(15,722,000)	4,123,000
6.50% Senior Notes Due 2021 [Member]
Senior Notes [Line Items]
Senior Notes, interest rate, stated percentage							6.50%
Senior Notes, face amount					$ 350,000,000			346,955,000
Unamortized deferred financing costs							$ 2,656,000	3,372,000
Senior Notes, net of unamortized deferred financing costs							$ 341,955,000	343,583,000
Senior Notes, repurchased face amount						$ 3,100,000				$ 2,300,000
Senior Notes, repurchased settlement amount						2,300,000
Net proceeds from Senior Notes issuance					343,100,000
Senior Notes debt issuance costs, gross					$ (6,900,000)
6.125% Senior Notes Due 2022 [Member]
Senior Notes [Line Items]
Senior Notes, interest rate, stated percentage							6.125%
Senior Notes, face amount		$ 600,000,000						561,796,000
Unamortized deferred financing costs							$ 5,800,000	6,979,000
Senior Notes, net of unamortized deferred financing costs							$ 555,996,000	554,817,000
Senior Notes, repurchased face amount						38,200,000
Senior Notes, repurchased settlement amount						24,300,000
Net proceeds from Senior Notes issuance		590,000,000
Senior Notes debt issuance costs, gross		$ (10,000,000)
6.50% Senior Notes Due 2023 [Member]
Senior Notes [Line Items]
Senior Notes, interest rate, stated percentage							6.50%
Senior Notes, face amount				$ 400,000,000				394,985,000
Unamortized deferred financing costs							$ 3,707,000	4,436,000
Senior Notes, net of unamortized deferred financing costs							$ 391,278,000	390,549,000
Senior Notes, repurchased face amount						5,000,000
Senior Notes, repurchased settlement amount						3,300,000
Net proceeds from Senior Notes issuance				392,100,000
Senior Notes debt issuance costs, gross				$ (7,900,000)
5% Senior Notes Due 2024 [Member]
Senior Notes [Line Items]
Senior Notes, interest rate, stated percentage							5.00%
Senior Notes, face amount			$ 500,000,000					500,000,000
Unamortized deferred financing costs							$ 5,610,000	6,533,000
Senior Notes, net of unamortized deferred financing costs							$ 494,390,000	493,467,000
Net proceeds from Senior Notes issuance			490,200,000
Senior Notes debt issuance costs, gross			$ (9,800,000)
5.625% Senior Notes Due 2025 [Member]
Senior Notes [Line Items]
Senior Notes, interest rate, stated percentage							5.625%
Senior Notes, face amount	$ 500,000,000							500,000,000
Unamortized deferred financing costs							$ 6,714,000	7,619,000
Senior Notes, net of unamortized deferred financing costs							$ 493,286,000	492,381,000
Net proceeds from Senior Notes issuance	491,000,000
Senior Notes debt issuance costs, gross	$ (9,000,000)
6.75% Senior Notes Due 2026 [Member]
Senior Notes [Line Items]
Senior Notes, interest rate, stated percentage							6.75%
Senior Notes, face amount								500,000,000			$ 500,000,000
Unamortized deferred financing costs							$ 7,242,000	8,078,000
Senior Notes, net of unamortized deferred financing costs							492,758,000	491,922,000
Net proceeds from Senior Notes issuance								491,600,000
Senior Notes debt issuance costs, gross											$ (8,400,000)
6.625% Senior Notes Due 2019 [Member]
Senior Notes [Line Items]
Gain (loss) on extinguishment of debt									(16,600,000)
Loss on extinguishment of debt, acceleration of unamortized deferred financing costs									(4,100,000)
Senior Notes, repurchase premium									$ 12,500,000
Senior Notes [Member]
Senior Notes [Line Items]
Senior Notes, face amount							2,801,392,000	2,803,736,000
Unamortized deferred financing costs							31,729,000	37,017,000
Senior Notes, net of unamortized deferred financing costs							2,769,663,000	2,766,719,000
Senior Notes, covenant compliance, dividends excluded from computation							$ 6,500,000
Senior Notes, repurchased face amount						46,300,000
Senior Notes, repurchased settlement amount						$ 29,900,000
Gain (loss) on extinguishment of debt								15,700,000
Senior Notes, repurchase discount								16,400,000
Loss on extinguishment of debt, acceleration of unamortized deferred financing costs								(700,000)
Senior Notes [Member] | 6.50% Senior Notes Due 2021 [Member]
Senior Notes [Line Items]
Senior Notes, interest rate, stated percentage							6.50%
Senior Notes, face amount							$ 344,611,000	346,955,000
Senior Notes [Member] | 6.125% Senior Notes Due 2022 [Member]
Senior Notes [Line Items]
Senior Notes, interest rate, stated percentage							6.125%
Senior Notes, face amount							$ 561,796,000	561,796,000
Senior Notes [Member] | 6.50% Senior Notes Due 2023 [Member]
Senior Notes [Line Items]
Senior Notes, interest rate, stated percentage							6.50%
Senior Notes, face amount							$ 394,985,000	394,985,000
Senior Notes [Member] | 5% Senior Notes Due 2024 [Member]
Senior Notes [Line Items]
Senior Notes, interest rate, stated percentage							5.00%
Senior Notes, face amount							$ 500,000,000	500,000,000
Senior Notes [Member] | 5.625% Senior Notes Due 2025 [Member]
Senior Notes [Line Items]
Senior Notes, interest rate, stated percentage							5.625%
Senior Notes, face amount							$ 500,000,000	500,000,000
Senior Notes [Member] | 6.75% Senior Notes Due 2026 [Member]
Senior Notes [Line Items]
Senior Notes, interest rate, stated percentage							6.75%
Senior Notes, face amount							$ 500,000,000	$ 500,000,000

Long-term Debt Senior Convertib

Long-term Debt Senior Convertible Notes (Details) - USD ($)	Aug. 12, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Senior Convertible Notes [Line Items]
Senior Convertible Notes, net carrying amount		$ 139,107,000	$ 130,856,000
Capped call transaction costs			24,195,000
Capped call, cap price		$ 60
Capitalized interest costs		$ 12,600,000	17,000,000	$ 25,100,000
1.50% Senior Convertible Notes Due 2021 [Member]
Senior Convertible Notes [Line Items]
Senior Convertible Notes, face amount		$ 172,500,000	172,500,000
Senior Convertible Notes, interest rate, stated percentage		1.50%
Net proceeds from Senior Convertible Notes			166,600,000
Senior Convertible Notes debt issuance costs, gross			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		9,900,000	3,700,000
Senior Convertible Notes, unamortized discount		(30,183,000)	(37,513,000)
Unamortized deferred financing costs		3,210,000	4,131,000
Senior Convertible Notes, net carrying amount		139,107,000	130,856,000
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) MMcf in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)MMcfMMBbls	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Feb. 14, 2018USD ($)
Commitments and Contingencies
Contractual obligation, due in next fiscal year	$ 113,774
Contractual obligation, due in second year	112,860
Contractual obligation, due in third year	111,107
Contractual obligation, due in fourth year	102,606
Contractual obligation, due in fifth year	72,073
Contractual obligation, due after fifth year	62,245
Contractual obligation	574,665
Operating leases, rent expense, net of sublease income	$ 4,800	$ 5,200	$ 6,100
Crude oil pipeline commitment [Member]
Commitments and Contingencies
Oil and gas delivery commitments, remaining minimum contractual volumes | MMBbls	19
Natural gas pipeline commitment [Member]
Commitments and Contingencies
Oil and gas delivery commitments, remaining minimum contractual volumes | MMcf	789
Drilling rig leasing contracts [Member]
Commitments and Contingencies
Contractual obligation	$ 37,800
Early termination penalties for rig contracts	27,700
Expenses related to early termination of office leases	0	$ (8,700)	$ (13,700)
Pipeline transportation commitments [Member]
Commitments and Contingencies
Contractual obligation	463,400
Office space leases [Member]
Commitments and Contingencies
Contractual obligation	43,300
Expenses related to early termination of office leases	(3,200)
Other miscellaneous contracts and leases [Member]
Commitments and Contingencies
Contractual obligation	$ 30,200
Electricity purchase agreement [Member] | Subsequent Event [Member]
Commitments and Contingencies
Contractual obligation				$ 27,900
Water pipeline commitment [Member]
Commitments and Contingencies
Water delivery commitments, remaining minimum contractual volumes | MMBbls	24
Outside-operated Eagle Ford divestiture 2017 [Member] | Crude oil pipeline commitment [Member]
Commitments and Contingencies
Oil, gas, and NGLs delivery commitments, remaining contractual volume on outside-operated Eagle Ford assets | MMBbls	52
Outside-operated Eagle Ford divestiture 2017 [Member] | Natural gas pipeline commitment [Member]
Commitments and Contingencies
Oil, gas, and NGLs delivery commitments, remaining contractual volume on outside-operated Eagle Ford assets | MMcf	514
Outside-operated Eagle Ford divestiture 2017 [Member] | Natural gas liquids pipeline commitment [Member]
Commitments and Contingencies
Oil, gas, and NGLs delivery commitments, remaining contractual volume on outside-operated Eagle Ford assets | MMBbls	13
Outside-operated Eagle Ford divestiture 2017 [Member] | Pipeline transportation commitments [Member]
Commitments and Contingencies
Contractual obligation, outside-operated Eagle Ford assets	$ 501,900

Compensation Plans_ Stock Based

Compensation Plans: Stock Based (Details) $ / shares in Units, $ in Millions		3 Months Ended		12 Months Ended
		Jun. 30, 2017shares	Dec. 31, 2016$ / sharesshares	Dec. 31, 2017USD ($)shares$ / shares	Dec. 31, 2016USD ($)$ / sharesshares	Dec. 31, 2015USD ($)$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Stock Options | $						$ 0
Number of shares available for grant				3,300,000
Impact outright issuance of one share has on number of available shares				1
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					0.2	1
Award Vesting Period				3 years
Stock-based compensation expense | $				$ 9.7	$ 11	$ 10.6
Unrecognized stock based compensation expense | $				$ 18.8
Multiplier assumed				1
Fair value of PSUs/RSUs Granted in Period | $				$ 15.5	$ 11.9	$ 14.5
Performance Share Units Shares Settled Gross of Shares for Tax Withholdings	[1]				44,870	288,962
Shares held for settlement of income and payroll tax obligations (in shares)					(14,809)	(100,683)
Shares Issued in Period					30,061	188,279
Fair value of PSUs/RSUs Vested in Period | $				$ 8.1	$ 8.4	$ 4
Weighted Average Grant Date Fair Value
Non-vested at beginning of year (in shares)	[2]			828,923	626,328	433,660
Granted (in shares)	[2]			977,731	447,971	320,753
Vested (in shares)	[2]			(94,338)	(130,353)	(76,438)
Forfeited (in shares)	[2]			(178,825)	(115,023)	(51,647)
Non-vested at end of year (in shares)	[2]		828,923	1,533,491	828,923	626,328
Non-vested outstanding at the beginning of the period (in dollars per share) | $ / shares	[2]			$ 43.25	$ 61.81	$ 73.63
Granted (in dollars per share) | $ / shares	[2]			15.86	26.56	45.34
Vested (in dollars per share) | $ / shares	[2]			85.85	64.17	51.76
Forfeited (in dollars per share) | $ / shares	[2]			44.99	55.59	73.62
Non-vested outstanding at the end of the period (in dollars per share) | $ / shares	[2]		$ 43.25	$ 22.97	$ 43.25	$ 61.81
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense | $				$ 10.3	$ 11.9	$ 13.4
Unrecognized stock based compensation expense | $				19.3
Fair value of PSUs/RSUs Granted in Period | $				$ 17	$ 11.7	$ 15.6
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vesting Increment				0.33	0.33	0.33
Shares held for settlement of income and payroll tax obligations (in shares)				(74,747)	(72,181)	(91,045)
Shares Issued in Period				171,278	169,182	187,244
Fair value of PSUs/RSUs Vested in Period | $				$ 10.8	$ 14	$ 17.6
Number of Shares Represented by Each RSU				1
Restricted Stock, Shares Settled Gross of Shares for Tax Withholdings	[3]			246,025	241,363	278,289
Weighted Average Grant Date Fair Value
Non-vested at beginning of year (in shares)				604,116	543,737	515,724
Granted (in shares)				1,020,780	417,065	356,246
Vested (in shares)				(246,025)	(241,363)	(278,289)
Forfeited (in shares)				(134,609)	(115,323)	(49,944)
Non-vested at end of year (in shares)			604,116	1,244,262	604,116	543,737
Non-vested outstanding at the beginning of the period (in dollars per share) | $ / shares				$ 37.39	$ 55.01	$ 68.29
Granted (in dollars per share) | $ / shares				16.64	28.08	43.72
Vested (in dollars per share) | $ / shares				43.99	58.06	63.12
Forfeited (in dollars per share) | $ / shares				26.38	43.52	66.53
Non-vested outstanding at the end of the period (in dollars per share) | $ / shares			$ 37.39	$ 20.25	$ 37.39	$ 55.01
Shares Issued to the Board of Directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award Vesting Period				1 year
Stock-based compensation expense | $				$ 1.6	$ 2	$ 1.6
Director Shares
Minimum Service Requirement for Immediate Vesting of Granted Shares				5 years
Minimum [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Multiplier Applied to PSU Awards at Settlement				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
Director [Member]
Director Shares
Stock Issued During Period, Shares, Share-based Compensation, Gross		71,573	53,473			39,903
Director [Member] | Restricted Stock Units (RSUs) [Member]
Weighted Average Grant Date Fair Value
Granted (in shares)		8,794
[1]	During the years ended December 31, 2016, and 2015, the Company issued shares of common stock for PSUs granted in 2013, and 2012. 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]	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]	During the years ended December 31, 2017, 2016, and 2015, the Company issued shares of common stock for RSUs 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, 2017	Dec. 31, 2016	Dec. 31, 2015
Compensation plans
Number of shares available for grant	3,300,000
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 available for grant	1,800,000
Issuance of common stock under Employee Stock Purchase Plan (in shares)	186,665	218,135	197,214
Proceeds from Issuance of Shares under Incentive and Share-based Compensation Plans, Excluding Stock Options	$ 2,600,000	$ 4,200,000	$ 4,800,000
Risk free interest rate	0.90%	0.40%	0.10%
Dividend yield	0.50%	0.40%	0.20%
Volatility factor of the expected market price of the Company's common stock	62.50%	95.00%	61.20%
Expected life (in years)	6 months	6 months	6 months
Stock-based compensation expense	$ 1,000,000	$ 2,000,000	$ 1,800,000

Compensation Plans Non Stock-Ba

Compensation Plans Non Stock-Based Compensation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
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%
Total Cash Payments, Made or Accrued under Profit Sharing Plan	$ (54)	$ 6,608	$ 3,498
Cash Payments Made or Accrued under Profit Sharing Plan Related to Divested Property	2,753	24,349	3,789
Total net settlements under Profit Sharing Plan	$ 2,699	30,957	7,287
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, Employees Hired December 31, 2014 and Prior	6.00%
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay, Employees Hired After December 31, 2014	9.00%
Defined Contribution Plan, Cost	$ 4,500	$ 5,400	$ 5,600

Pension Benefits (Details)

Pension Benefits (Details) - USD ($)		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Projected benefit obligation at beginning of year		$ 69,659,000	$ 62,547,000
Defined Benefit Plan, Service Cost		6,638,000	8,200,000	$ 7,949,000
Defined Benefit Plan, Interest Cost		2,689,000	2,908,000	2,496,000
Defined Benefit Plan, Actuarial Loss		3,708,000	2,662,000
Defined Benefit Plan, Benefits Paid		(10,757,000)	(6,658,000)
Projected benefit obligation at end of year		71,937,000	69,659,000	62,547,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair value of plan assets at beginning of year		31,731,000	25,769,000
Defined Benefit Plan, Actual Return on Plan Assets		2,956,000	1,575,000
Defined Benefit Plan, Employer Contribution		7,048,000	11,045,000	6,400,000
Defined Benefit Plan, Benefits Paid		(10,757,000)	(6,658,000)	(8,200,000)
Defined Benefit Plan, Fair value of plan assets at end of year		30,978,000	31,731,000	25,769,000
Defined Benefit Plan, Funded (Unfunded) Status		(40,959,000)	(37,928,000)
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year		4,000,000
Defined Benefit Plan, Pension Plan with Accumulated Benefit Obligation in Excess of Plan Assets [Abstract]
Defined Benefit Plan, Projected Benefit Obligation		71,937,000	69,659,000
Defined Benefit Plan, Accumulated Benefit Obligation		56,045,000	54,681,000
Defined Benefit Plan, Fair Value of Plan Assets		30,978,000	31,731,000
Defined Benefit Plan, Unfunded Accumulated Benefit Obligation		$ 25,067,000	22,950,000
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		$ 21,397,000	22,708,000
Defined Benefit Plan, Unrecognized Prior Service Costs		66,000	83,000
Defined Benefit Plan, Accumulated Other Comprehensive Loss		21,463,000	22,791,000
Defined Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Loss) in Next Fiscal Year		1,300,000
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Other Comprehensive Income (Loss), Defined Benefit Plan, Net Actuarial Loss		(2,995,000)	(3,322,000)	(4,990,000)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Amortization of Prior Service Cost		17,000	16,000	17,000
Other Comprehensive Income (Loss), Defined Benefit Plan, Amortization of Net Actuarial Loss		1,297,000	1,582,000	1,486,000
Other Comprehensive Income (Loss), Defined Benefit Plan, Settlements		3,009,000	0	350,000
Other Comprehensive (Income) Loss, Defined Benefit Plan, Total Pension Liability Adjustment, Pre-Tax		1,328,000	(1,724,000)	(3,137,000)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Tax (Expense) Benefit		(561,000)	570,000	1,047,000
Other Comprehensive (Income) Loss, Defined Benefit Plan, Total Pension Liability Adjustment, Net of Tax	[1]	(767,000)	1,154,000	2,090,000
Components of Net Periodic Benefit Costs for Both Pension Plans
Defined Benefit Plan, Service Cost		6,638,000	8,200,000	7,949,000
Defined Benefit Plan, Interest Cost		2,689,000	2,908,000	2,496,000
Defined Benefit Plan, Expected Return on Plan Assets that Reduces Periodic Pension Benefit Cost		(2,244,000)	(2,235,000)	(2,182,000)
Defined Benefit Plan, Amortization of Prior Service Cost		17,000	16,000	17,000
Defined Benefit Plan, Amortization Net Actuarial Loss		1,297,000	1,582,000	1,486,000
Defined Benefit Plan, Settlements		3,009,000	0	350,000
Defined Benefit Plan, Net Periodic Benefit Cost		$ 11,406,000	$ 10,471,000	$ 10,116,000
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation and Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		3.80%	4.20%
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		4.20%	4.70%	4.30%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Return on Plan Assets	[2]	6.50%	7.50%	7.50%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		6.20%	6.20%	6.20%
Future Benefit Payments
Defined Benefit Plan, Expected Future Benefit Payments in Year One		$ 4,217,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Two		3,818,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Three		4,363,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Four		5,561,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Five		6,117,000
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter		36,279,000
Qualified Plan [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Plan Assets Returned		0
Nonqualified Plan [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair value of plan assets at beginning of year		0	$ 0
Defined Benefit Plan, Fair value of plan assets at end of year		$ 0	$ 0	$ 0
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation and Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Return on Plan Assets			0.00%	0.00%
[1]	Please refer to Note 8 – Pension Benefits for additional discussion on the pension liability adjustment.
[2]	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.

Pension Benefits Fair Value of

Pension Benefits Fair Value of Plan Assets in Heirarchy (Details) - USD ($)		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Return on Plan Assets	[1]	6.50%	7.50%	7.50%
Defined Benefit Plan, Target Allocation Percentage of Assets		100.00%
Defined Benefit Plan, Asset Allocation	[2]	100.00%	100.00%
Defined Benefit Plan, Fair Value of Plan Assets		$ 30,978,000	$ 31,731,000	$ 25,769,000
Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		21,524,000	19,481,000
Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		4,245,000	7,036,000
Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		5,209,000	5,214,000	$ 5,045,000
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases		300,000	561,000
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Realized Gain on Assets		130,000	54,000
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Unrealized Gain on Assets		120,000	115,000
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Disposition		$ (555,000)	$ (561,000)
Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Asset Allocation	[2]	0.00%	0.00%
Defined Benefit Plan, Fair Value of Plan Assets		$ 0	$ 0
Cash [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Cash [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Cash [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 0	$ 0
Domestic Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Asset Allocation	[2],[3]	22.20%	18.70%
Defined Benefit Plan, Fair Value of Plan Assets	[3]	$ 6,865,000	$ 5,945,000
Domestic Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[3]	4,805,000	4,471,000
Domestic Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[3]	2,060,000	1,474,000
Domestic Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[3]	$ 0	$ 0
International Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Asset Allocation	[2],[4]	16.20%	10.10%
Defined Benefit Plan, Fair Value of Plan Assets	[4]	$ 5,032,000	$ 3,192,000
International Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[4]	3,806,000	3,192,000
International Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[4]	1,226,000	0
International Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[4]	$ 0	$ 0
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets		35.00%
Defined Benefit Plan, Asset Allocation	[2]	38.40%	28.80%
Defined Benefit Plan, Fair Value of Plan Assets		$ 11,897,000	$ 9,137,000
Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		8,611,000	7,663,000
Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		3,286,000	1,474,000
Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 0	$ 0
High-yield Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Asset Allocation	[2],[5]	2.80%	2.60%
Defined Benefit Plan, Fair Value of Plan Assets	[5]	$ 876,000	$ 822,000
High-yield Bonds [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[5]	876,000	822,000
High-yield Bonds [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[5]	0	0
High-yield Bonds [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[5]	$ 0	$ 0
Fixed Income Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Asset Allocation	[2],[6]	28.60%	25.00%
Defined Benefit Plan, Fair Value of Plan Assets	[6]	$ 8,842,000	$ 7,923,000
Fixed Income Investments [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[6]	8,842,000	7,923,000
Fixed Income Investments [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[6]	0	0
Fixed Income Investments [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[6]	$ 0	$ 0
Floating Rate Corporate Loans [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Asset Allocation	[2],[7]	8.40%	7.90%
Defined Benefit Plan, Fair Value of Plan Assets	[7]	$ 2,607,000	$ 2,495,000
Floating Rate Corporate Loans [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[7]	2,607,000	2,495,000
Floating Rate Corporate Loans [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[7]	0	0
Floating Rate Corporate Loans [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[7]	$ 0	$ 0
Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets		43.00%
Defined Benefit Plan, Asset Allocation	[2]	39.80%	35.50%
Defined Benefit Plan, Fair Value of Plan Assets		$ 12,325,000	$ 11,240,000
Fixed Income Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		12,325,000	11,240,000
Fixed Income Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Fixed Income Securities [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		$ 0	$ 0
Commodity Contracts [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Asset Allocation	[2],[8]	1.90%	1.80%
Defined Benefit Plan, Fair Value of Plan Assets	[8]	$ 588,000	$ 578,000
Commodity Contracts [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[8]	588,000	578,000
Commodity Contracts [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[8]	0	0
Commodity Contracts [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[8]	$ 0	$ 0
Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Asset Allocation	[2],[9]	5.60%	5.10%
Defined Benefit Plan, Fair Value of Plan Assets	[9]	$ 1,735,000	$ 1,629,000
Real Estate [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[9]	0	0
Real Estate [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[9]	0	0
Real Estate [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[9]	$ 1,735,000	$ 1,629,000
Collective Investment Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Asset Allocation	[2],[10]	3.10%	17.50%
Defined Benefit Plan, Fair Value of Plan Assets	[10]	$ 959,000	$ 5,562,000
Collective Investment Trusts [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[10]	0	0
Collective Investment Trusts [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[10]	959,000	5,562,000
Collective Investment Trusts [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[10]	$ 0	$ 0
Hedge Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Asset Allocation	[2],[11]	11.20%	11.30%
Defined Benefit Plan, Fair Value of Plan Assets	[11]	$ 3,474,000	$ 3,585,000
Hedge Fund [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[11]	0	0
Hedge Fund [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[11]	0	0
Hedge Fund [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	[11]	$ 3,474,000	$ 3,585,000
Other Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets		22.00%
Defined Benefit Plan, Asset Allocation	[2]	21.80%	35.70%
Defined Benefit Plan, Fair Value of Plan Assets		$ 6,756,000	$ 11,354,000
Other Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		588,000	578,000
Other Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		959,000	5,562,000
Other Securities [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		5,209,000	$ 5,214,000
Nonqualified Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Return on Plan Assets			0.00%	0.00%
Defined Benefit Plan, Fair Value of Plan Assets		$ 0	$ 0	$ 0
[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.
[2]	Percentages may not calculate due to rounding.
[3]	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 this fund is to approximate the S&P 500 by investing in one or more collective investment funds.
[4]	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]	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]	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]	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]	Investments with exposure to commodity price movements, primarily through the use of futures, swaps and other commodity-linked securities.
[9]	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]	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]	The hedge fund portfolio includes an investment in an actively traded global mutual fund that focuses on alternative investments and a hedge fund of funds that invests both long and short using a variety of investment strategies.

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($)		12 Months Ended
		Dec. 31, 2017		Dec. 31, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning asset retirement obligations		$ 123,307,000	[1],[2]	$ 140,874,000
Liabilities incurred	[3]	7,588,000		21,293,000
Liabilities settled	[4]	(30,432,000)		(57,100,000)
Accretion expense		5,988,000		7,795,000
Revision to estimated cash flows		8,019,000		10,445,000
Ending asset retirement obligations	[1],[2]	114,470,000		123,307,000
Asset retirement obligations associated with oil and gas properties held for sale		11,369,000		26,241,000
Current asset retirement obligation liability		$ 75,000		$ 932,000
[1]	Balances as of December 31, 2017, and 2016, included $11.4 million and $26.2 million, respectively, of asset retirement obligations associated with oil and gas properties held for sale.
[2]	Balances as of December 31, 2017, and 2016, included $75,000 and $932,000, respectively, related to the Company’s current asset retirement obligation liability, which is recorded in accounts payable and accrued expenses on the accompanying balance sheets.
[3]	Reflects liabilities incurred through drilling activities and acquisitions of drilled wells.
[4]	Reflects liabilities settled through plugging and abandonment activities and divestitures of properties.

Derivative Financial Instrume53

Derivative Financial Instruments (Details) bbl in Thousands, MMBTU in Thousands		Dec. 31, 2017MMBTU$ / EnergyContent$ / Barrelsbbl	Feb. 14, 2018$ / Barrelsbbl
NYMEX Oil Swap Contract First Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		1,075
Derivative, Swap Type, Average Fixed Price | $ / Barrels		50.16
NYMEX Oil Swap Contract Second Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		1,534
Derivative, Swap Type, Average Fixed Price | $ / Barrels		49.57
NYMEX Oil Swap Contract Third Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		1,769
Derivative, Swap Type, Average Fixed Price | $ / Barrels		49.77
NYMEX Oil Swap Contract Fourth Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		1,894
Derivative, Swap Type, Average Fixed Price | $ / Barrels		49.87
NYMEX Oil Swap Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		1,940
Derivative, Swap Type, Average Fixed Price | $ / Barrels		50.70
NYMEX Oil Swap Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		8,212
NYMEX Oil Collar Contract First Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		1,445
Derivative, Floor Price | $ / Barrels		50
Derivative, Ceiling Price | $ / Barrels		59.07
NYMEX Oil Collar Contract Second Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		1,459
Derivative, Floor Price | $ / Barrels		50
Derivative, Ceiling Price | $ / Barrels		59.03
NYMEX Oil Collar Contract Third Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		1,948
Derivative, Floor Price | $ / Barrels		50
Derivative, Ceiling Price | $ / Barrels		58.61
NYMEX Oil Collar Contract Fourth Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		2,222
Derivative, Floor Price | $ / Barrels		50
Derivative, Ceiling Price | $ / Barrels		58.44
NYMEX Oil Collar Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		5,908
Derivative, Floor Price | $ / Barrels		47.65
Derivative, Ceiling Price | $ / Barrels		59.19
NYMEX Oil Collar Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		12,982
Oil Basis Swap Contract First Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		2,113
Weighted-Average Contract Price | $ / Barrels	[1]	(1.15)
Oil Basis Swap Contract Second Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		2,392
Weighted-Average Contract Price | $ / Barrels	[1]	(1.03)
Oil Basis Swap Contract Third Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		3,018
Weighted-Average Contract Price | $ / Barrels	[1]	(1.06)
Oil Basis Swap Contract Fourth Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		3,327
Weighted-Average Contract Price | $ / Barrels	[1]	(1.08)
Oil Basis Swap Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		5,788
Weighted-Average Contract Price | $ / Barrels	[1]	(1.09)
Oil Basis Swap [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		16,638
Gas Swaps Contract First Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent		3.55
Derivative, Nonmonetary Notional Amount, Energy Measure, Sold Volumes | MMBTU		28,910
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | MMBTU		(8,121)
Derivative, Swap Type, Weighted-Average Fixed Price, Purchased Volumes | $ / EnergyContent		4.34
Derivative, Nonmonetary Notional Amount, Energy Measure, Net Volumes | MMBTU	[2]	20,789
Gas Swaps Contract Second Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent		3.31
Derivative, Nonmonetary Notional Amount, Energy Measure, Sold Volumes | MMBTU		23,507
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | MMBTU		(7,795)
Derivative, Swap Type, Weighted-Average Fixed Price, Purchased Volumes | $ / EnergyContent		4.24
Derivative, Nonmonetary Notional Amount, Energy Measure, Net Volumes | MMBTU	[2]	15,712
Gas Swaps Contract Third Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent		3.29
Derivative, Nonmonetary Notional Amount, Energy Measure, Sold Volumes | MMBTU		24,627
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | MMBTU		(7,480)
Derivative, Swap Type, Weighted-Average Fixed Price, Purchased Volumes | $ / EnergyContent		4.23
Derivative, Nonmonetary Notional Amount, Energy Measure, Net Volumes | MMBTU	[2]	17,147
Gas Swaps Contract Fourth Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent		3.29
Derivative, Nonmonetary Notional Amount, Energy Measure, Sold Volumes | MMBTU		25,856
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | MMBTU		(7,210)
Derivative, Swap Type, Weighted-Average Fixed Price, Purchased Volumes | $ / EnergyContent		4.27
Derivative, Nonmonetary Notional Amount, Energy Measure, Net Volumes | MMBTU	[2]	18,646
Gas Swaps Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent		3.76
Derivative, Nonmonetary Notional Amount, Energy Measure, Sold Volumes | MMBTU		41,394
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | MMBTU		(24,415)
Derivative, Swap Type, Weighted-Average Fixed Price, Purchased Volumes | $ / EnergyContent		4.34
Derivative, Nonmonetary Notional Amount, Energy Measure, Net Volumes | MMBTU	[2]	16,979
Gas Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure, Sold Volumes | MMBTU	[2]	144,294
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | MMBTU	[2]	(55,021)
Derivative, Nonmonetary Notional Amount, Energy Measure, Net Volumes | MMBTU	[2]	89,273
IF HSC [Member]
Derivative Financial Instruments
Index percent of natural gas fixed swaps		99.00%
IF El Paso Permian [Member]
Derivative Financial Instruments
Index percent of natural gas fixed swaps		1.00%
OPIS Purity Ethane Mont Belvieu [Member] | NGL Swaps Contract First Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		923
Derivative, Swap Type, Average Fixed Price | $ / Barrels		10.90
OPIS Purity Ethane Mont Belvieu [Member] | NGL Swaps Contract Second Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		915
Derivative, Swap Type, Average Fixed Price | $ / Barrels		10.87
OPIS Purity Ethane Mont Belvieu [Member] | NGL Swaps Contract Third Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		1,033
Derivative, Swap Type, Average Fixed Price | $ / Barrels		10.99
OPIS Purity Ethane Mont Belvieu [Member] | NGL Swaps Contract Fourth Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		1,146
Derivative, Swap Type, Average Fixed Price | $ / Barrels		11.18
OPIS Purity Ethane Mont Belvieu [Member] | NGL Swaps Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		3,533
Derivative, Swap Type, Average Fixed Price | $ / Barrels		12.31
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		8,089
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract First Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		629
Derivative, Swap Type, Average Fixed Price | $ / Barrels		25.39
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Second Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		554
Derivative, Swap Type, Average Fixed Price | $ / Barrels		24.94
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		610
Derivative, Swap Type, Average Fixed Price | $ / Barrels		24.27
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		671
Derivative, Swap Type, Average Fixed Price | $ / Barrels		24.39
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		1,503
Derivative, Swap Type, Average Fixed Price | $ / Barrels		27.83
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		3,967
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract First Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		206
Derivative, Swap Type, Average Fixed Price | $ / Barrels		35.83
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Second Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		84
Derivative, Swap Type, Average Fixed Price | $ / Barrels		35.69
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		93
Derivative, Swap Type, Average Fixed Price | $ / Barrels		35.70
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		102
Derivative, Swap Type, Average Fixed Price | $ / Barrels		35.70
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		154
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		639
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract First Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		167
Derivative, Swap Type, Average Fixed Price | $ / Barrels		35.76
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Second Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		66
Derivative, Swap Type, Average Fixed Price | $ / Barrels		35.07
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		70
Derivative, Swap Type, Average Fixed Price | $ / Barrels		35.07
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		76
Derivative, Swap Type, Average Fixed Price | $ / Barrels		35.07
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		117
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		496
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract First Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		188
Derivative, Swap Type, Average Fixed Price | $ / Barrels		49.40
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract Second Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		109
Derivative, Swap Type, Average Fixed Price | $ / Barrels		49.57
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		118
Derivative, Swap Type, Average Fixed Price | $ / Barrels		49.56
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		129
Derivative, Swap Type, Average Fixed Price | $ / Barrels		49.57
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		197
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		741
Subsequent Event [Member] | OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			228
Derivative, Swap Type, Average Fixed Price | $ / Barrels			53.34
[1]	Represents the price differential between WTI prices at Midland, Texas and WTI prices at Cushing, Oklahoma.
[2]	Total net volumes of gas swaps are comprised of IF HSC (99%) and IF El Paso Permian (1%).

Derivative Financial Instrume54

Derivative Financial Instruments Fair Value (Details) - USD ($) $ in Thousands	Dec. 31, 2017		Dec. 31, 2016
Fair value of derivative assets and liabilities
Derivative, Fair Value, Net	$ 139,400		$ 91,700
Derivative Assets, Current	64,266		54,521
Derivative Liabilities, Current	172,582		115,464
Derivative Assets, Noncurrent	40,362		67,575
Derivative Liabilities, Noncurrent	71,402		98,340
Derivative Asset, Fair Value, Gross Asset	104,628		122,096
Derivative Liability, Fair Value, Gross Liability	243,984		213,804
Derivative Asset, Not Offset in the Accompanying Balance Sheets	(100,035)		(118,080)
Derivative Liability, Not Offset in the Accompanying Balance Sheets	100,035		118,080
Derivative Asset, Fair Value, Net Amounts	4,593		4,016
Derivative Liability, Fair Value, Net Amounts	(143,949)		(95,724)
Not Designated as Hedging Instrument [Member]
Fair value of derivative assets and liabilities
Derivative Assets, Current	64,266		54,521
Derivative Liabilities, Current	172,582		115,464
Derivative Assets, Noncurrent	40,362		67,575
Derivative Liabilities, Noncurrent	71,402		98,340
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Not Designated as Hedging Instrument [Member]
Fair value of derivative assets and liabilities
Derivative Asset, Fair Value, Gross Asset	104,628	[1]	122,096	[2]
Derivative Liability, Fair Value, Gross Liability	$ 243,984	[1]	$ 213,804	[2]
[1]	This represents a financial asset or liability that is measured at fair value on a recurring basis.
[2]	This represents a financial asset or liability that is measured at fair value on a recurring basis.

Derivative Financial Instrume55

Derivative Financial Instruments Gains and Losses (Details) $ in Thousands		12 Months Ended
		Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Derivative Instruments, Gain (Loss) [Line Items]
Derivative settlement (gain) loss		$ (21,234)	$ (329,478)	$ (512,566)
Net derivative (gain) loss		26,414	250,633	(408,831)
Oil Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative settlement (gain) loss		31,176	(243,102)	(362,219)
Net derivative (gain) loss		71,502	85,370	(191,165)
Gas Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative settlement (gain) loss	[1]	(87,857)	(94,936)	(123,180)
Net derivative (gain) loss		(76,315)	81,060	(189,734)
Gain on Early Settlement of Derivatives				15,300
NGL Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative settlement (gain) loss		35,447	8,560	(27,167)
Net derivative (gain) loss		$ 31,227	$ 84,203	$ (27,932)
Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Number of Instruments Held		0	0	0
[1]	Gas derivative settlements for the year ended December 31, 2015, include $15.3 million of early settlements of futures contracts as a result of divesting assets in the Company’s Mid-Continent region.

Derivative Financial Instrume56

Derivative Financial Instruments Credit Facility and Derivative Counterparties (Details)	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Percentage of Proved Property Secured for Credit Facility Borrowing	90.00%

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) shares in Millions		Dec. 21, 2016	Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
Financial assets and liabilities measured at fair value on a recurring basis
Impairment of Long-Lived Assets Held-for-use			$ 0		$ 0		$ 49,369,000
Impairment of Proved Oil and Gas Properties			3,806,000		354,614,000		$ 468,679,000
Assets:
Derivatives			104,628,000		122,096,000
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability			243,984,000		213,804,000
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Assets:
Derivatives	[1]		0
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	[1]		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Assets:
Derivatives	[1]		0
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	[1]		0
Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 1 [Member]
Assets:
Total property and equipment, net	[2]				0
Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 2 [Member]
Assets:
Total property and equipment, net	[2]				0
Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member]
Assets:
Total property and equipment, net	[2]				88,205,000
Disposal group, held-for-sale, not discontinued operations [Member] | Divide County disposal group [Member]
Financial assets and liabilities measured at fair value on a recurring basis
Impairment of Proved Oil and Gas Properties			526,500,000
QStar Acquisition 2016 [Member]
Liabilities [Abstract]
Private issuance of Common Stock for an acquisition		13.4
Not Designated as Hedging Instrument [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Assets:
Derivatives	[3]				0
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	[3]				0
Not Designated as Hedging Instrument [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Assets:
Derivatives			104,628,000	[1]	122,096,000	[3]
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability			$ 243,984,000	[1]	213,804,000	[3]
Not Designated as Hedging Instrument [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Assets:
Derivatives	[3]				0
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	[3]				$ 0
[1]	This represents a financial asset or liability that is measured at fair value on a recurring basis.
[2]	This represents a non-financial asset that is measured at fair value on a nonrecurring basis.
[3]	This represents a financial asset or liability that is measured at fair value on a recurring basis.

Fair Value Measurements (Deta58

Fair Value Measurements (Details 2) - USD ($) $ in Thousands, shares in Millions	Dec. 21, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Sep. 12, 2016	May 21, 2015	Nov. 17, 2014	May 20, 2013	Jun. 29, 2012	Nov. 08, 2011
Proved Oil and Gas Properties
Impairment of proved properties		$ 3,806	$ 354,614	$ 468,679
Abandonment and impairment of unproved properties		12,272	80,367	78,643
Impairment of other property and equipment		$ 0	0	$ 49,369
6.50% Senior Notes Due 2021 [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Senior Notes, interest rate, stated percentage		6.50%
Senior Notes, face amount			346,955							$ 350,000
6.125% Senior Notes Due 2022 [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Senior Notes, interest rate, stated percentage		6.125%
Senior Notes, face amount			561,796				$ 600,000
6.50% Senior Notes Due 2023 [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Senior Notes, interest rate, stated percentage		6.50%
Senior Notes, face amount			394,985						$ 400,000
5% Senior Notes Due 2024 [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Senior Notes, interest rate, stated percentage		5.00%
Senior Notes, face amount			500,000					$ 500,000
5.625% Senior Notes Due 2025 [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Senior Notes, interest rate, stated percentage		5.625%
Senior Notes, face amount			500,000			$ 500,000
6.75% Senior Notes Due 2026 [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Senior Notes, interest rate, stated percentage		6.75%
Senior Notes, face amount			500,000		$ 500,000
Oil and Gas Properties [Member]
Proved Oil and Gas Properties
Period of New York Mercantile Exchange Strip Pricing Used for Price Forecast		5 years
Minimum [Member] | Oil and Gas Properties [Member]
Proved Oil and Gas Properties
Fair Value Inputs, Discount Rate		10.00%
Maximum [Member] | Oil and Gas Properties [Member]
Proved Oil and Gas Properties
Fair Value Inputs, Discount Rate		15.00%
Senior Notes [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Senior Notes, face amount		$ 2,801,392	2,803,736
Senior Notes [Member] | 6.50% Senior Notes Due 2021 [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Senior Notes, interest rate, stated percentage		6.50%
Senior Notes, face amount		$ 344,611	346,955
Long-term Debt, Fair Value		$ 351,682	354,546
Senior Notes [Member] | 6.125% Senior Notes Due 2022 [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Senior Notes, interest rate, stated percentage		6.125%
Senior Notes, face amount		$ 561,796	561,796
Long-term Debt, Fair Value		$ 571,627	570,925
Senior Notes [Member] | 6.50% Senior Notes Due 2023 [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Senior Notes, interest rate, stated percentage		6.50%
Senior Notes, face amount		$ 394,985	394,985
Long-term Debt, Fair Value		$ 403,434	403,134
Senior Notes [Member] | 5% Senior Notes Due 2024 [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Senior Notes, interest rate, stated percentage		5.00%
Senior Notes, face amount		$ 500,000	500,000
Long-term Debt, Fair Value		$ 483,440	475,975
Senior Notes [Member] | 5.625% Senior Notes Due 2025 [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Senior Notes, interest rate, stated percentage		5.625%
Senior Notes, face amount		$ 500,000	500,000
Long-term Debt, Fair Value		$ 494,355	485,000
Senior Notes [Member] | 6.75% Senior Notes Due 2026 [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Senior Notes, interest rate, stated percentage		6.75%
Senior Notes, face amount		$ 500,000	500,000
Long-term Debt, Fair Value		$ 516,350	516,565
Convertible Debt [Member] | 1.50% Senior Convertible Notes Due 2021 [Domain]
Debt Instrument, Fair Value Disclosure [Abstract]
Senior Notes, interest rate, stated percentage		1.50%
Senior Notes, face amount		$ 172,500	172,500
Long-term Debt, Fair Value		$ 168,291	$ 202,189
QStar Acquisition 2016 [Member]
Proved Oil and Gas Properties
Private issuance of Common Stock for an acquisition	13.4

Suspended Well Costs (Details)

Suspended Well Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Beginning balance	$ 19,846	$ 11,952	$ 43,589
Additions to capitalized exploratory well costs pending the determination of proved reserves	49,446	19,846	11,952
Divestitures	0	0	(809)
Reclassification to wells, facilities, and equipment based on the determination of proved reserves	(19,846)	(11,952)	(18,485)
Capitalized exploratory well costs charged to expense	0	0	(24,295)
Ending balance	49,446	$ 19,846	$ 11,952
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, 2017	Dec. 31, 2016	Dec. 31, 2015
Class of Stock [Line Items]
Issuance of common stock from stock offerings, shares					0
Net proceeds from sale of common stock					$ 2,623	$ 938,268	$ 4,844
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]	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.