SM Energy (SM) 10-K 23 Feb 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information Document - USD ($)	12 Months Ended
	Dec. 31, 2016	Feb. 15, 2017	Jun. 30, 2016
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, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		111,257,703
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 1,819,754,424

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
ASSETS
Cash and cash equivalents	$ 9,372	$ 18
Accounts receivable	151,950	134,124
Derivative asset	54,521	367,710
Prepaid expenses and other	8,799	17,137
Total current assets	224,642	518,989
Proved oil and gas properties	5,700,418	7,606,405
Less - accumulated depletion, depreciation, and amortization	(2,836,532)	(3,481,836)
Unproved oil and gas properties	2,471,947	284,538
Wells in Progress	235,147	387,432
Oil and gas properties held for sale, net	372,621	641
Other property and equipment, net of accumulated depreciation of $42,882 and $32,956, respectively	137,753	153,100
Total property and equipment, net	6,081,354	4,950,280
Derivative asset	67,575	120,701
Other noncurrent assets	19,940	31,673
Total other noncurrent assets	87,515	152,374
Total Assets	6,393,511	5,621,643
LIABILITIES
Accounts payable and accrued expenses	299,708	302,517
Derivative liability	115,464	8
Total current liabilities	415,172	302,525
Revolving credit facility	0	202,000
Senior Notes, net of unamortized deferred financing costs	2,766,719	2,315,970
Senior Convertible Notes, net of unamortized discount and deferred financing costs	130,856	0
Asset retirement obligation	96,134	137,284
Asset retirement obligations associated with oil and gas properties held for sale	26,241	241
Deferred income taxes	315,672	758,279
Derivative liability	98,340	0
Other noncurrent liabilities	47,244	52,943
Total noncurrent liabilities	3,481,206	3,466,717
Commitments and contingencies (note 6)
STOCKHOLDERS' EQUITY
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 111,257,500 and 68,075,700 shares, respectively	1,113	681
Additional paid-in capital	1,716,556	305,607
Retained earnings	794,020	1,559,515
Accumulated other comprehensive loss	(14,556)	(13,402)
Total stockholders' equity	2,497,133	1,852,401
Total Liabilities and Stockholders' Equity	$ 6,393,511	$ 5,621,643

CONSOLIDATED BALANCE SHEETS Par

CONSOLIDATED BALANCE SHEETS Parenthetical - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Property, Plant and Equipment, Other, Accumulated Depreciation	$ 42,882	$ 32,956
Common Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Common Stock, Shares Authorized	200,000,000	200,000,000
Common Stock, Shares, Issued	111,257,500	68,075,700
Common Stock, Shares, Outstanding	111,257,500	68,075,700

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating revenues and other income:
Oil, gas, and NGL production revenue	$ 1,178,426	$ 1,499,905	$ 2,481,544
Net gain on divestiture activity	37,074	43,031	646
Marketed gas system revenue	0	9,485	24,897
Other operating revenues	1,950	4,544	15,220
Total operating revenues and other income	1,217,450	1,556,965	2,522,307
Operating Expenses:
Oil, gas, and NGL production expense	597,565	723,633	715,878
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	790,745	921,009	767,532
Exploration	65,641	120,569	129,857
Impairment of proved properties	354,614	468,679	84,480
Abandonment and impairment of unproved properties	80,367	78,643	75,638
Impairment of other property and equipment	0	49,369	0
General and administrative	126,428	157,668	167,103
Change In Net Profits Plan Liability	(7,200)	(19,525)	(29,849)
Net derivative (gain) loss	250,633	(408,831)	(583,264)
Marketed gas system expense	0	13,922	24,460
Other operating expenses	17,972	30,612	4,658
Total operating expenses	2,276,765	2,135,748	1,356,493
Income (loss) from operations	(1,059,315)	(578,783)	1,165,814
Non-operating income (expense):
Interest expense	(158,685)	(128,149)	(98,554)
Gain (loss) on extinguishment of debt	15,722	(16,578)	0
Other, net	362	649	(2,561)
Income (loss) before income taxes	(1,201,916)	(722,861)	1,064,699
Income tax (expense) benefit	444,172	275,151	(398,648)
Net income (loss)	$ (757,744)	$ (447,710)	$ 666,051
Earnings Per Share, Basic [Abstract]
Basic weighted-average common shares outstanding	76,568	67,723	67,230
Basic net income (loss) per common share	$ (9.90)	$ (6.61)	$ 9.91
Earnings Per Share, Diluted [Abstract]
Diluted weighted-average common shares outstanding	76,568	67,723	68,044
Diluted net income (loss) per common share	$ (9.90)	$ (6.61)	$ 9.79

CONSOLIDATED STATEMENT OF COMPR

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Statement of Comprehensive Income [Abstract]
Net income (loss)		$ (757,744)	$ (447,710)	$ 666,051
Other Comprehensive loss, net of tax, Pension liability adjustment,	[1]	(1,154)	(2,090)	(5,896)
Total other comprehensive loss, net of tax		(1,154)	(2,090)	(5,896)
Total comprehensive income (loss)		$ (758,898)	$ (449,800)	$ 660,155
[1]	Refer to Note 1 - Summary of Significant Accounting Policies for detail of the pension amount reclassified to general and administrative expense on the Company’s consolidated statements of operations.

CONSOLIDATED STATEMENTS OF STOC

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) $ in Thousands	Total	Common Stock	Additional Paid-in Capital	Treasury Stock	Retained Earnings	Accumulated Other Comprehensive Income (Loss)
Common Stock, Dividends, Per Share, Declared	$ 0.10
Balances, Common Shares, Beginning at Dec. 31, 2013		67,078,853
Balances, Beginning at Dec. 31, 2013	$ 1,606,821	$ 671	$ 257,720		$ 1,354,669	$ (5,416)
Balances, Treasury Shares, Beginning at Dec. 31, 2013				(22,412)
Balances, Treasury Stock, Value, Beginning at Dec. 31, 2013				$ (823)
Increase (Decrease) in Stockholders' Equity
Net income (loss)	666,051				666,051
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent	(5,896)					(5,896)
Cash dividends, $ 0.10 per share	(6,723)				(6,723)
Issuance of common stock under Employee Stock Purchase Plan (in shares)		83,136
Issuance of common stock under Employee Stock Purchase Plan	4,061	$ 1	4,060
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings (in shares)		256,718
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings	$ (10,624)	$ 3	(10,627)
Issuance of common stock upon stock option exercises (in shares)	39,088	39,088
Issuance of common stock upon stock option exercises	$ 816		816
Stock-based compensation expense (in shares)		5,265		22,412
Stock-based compensation expense	32,694		31,871	$ 823
Other income tax expense	(545)		(545)
Balances, Common Shares, Ending at Dec. 31, 2014		67,463,060
Balances, Ending at Dec. 31, 2014	$ 2,286,655	$ 675	283,295		2,013,997	(11,312)
Balances, Treasury Shares, Ending at Dec. 31, 2014				0
Balances, Treasury Stock, Value, Ending at Dec. 31, 2014				$ 0
Common Stock, Dividends, Per Share, Declared	$ 0.10
Increase (Decrease) in Stockholders' Equity
Net income (loss)	$ (447,710)				(447,710)
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent	(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		27,467
Other income tax expense	(1,315)		(1,315)
Balances, Common Shares, Ending at Dec. 31, 2015		68,075,700
Balances, Ending at Dec. 31, 2015	$ 1,852,401	$ 681	305,607		1,559,515	(13,402)
Balances, Treasury Shares, Ending at Dec. 31, 2015				0
Balances, Treasury Stock, Value, Ending at Dec. 31, 2015				$ 0
Common Stock, Dividends, Per Share, Declared	$ 0.10
Increase (Decrease) in Stockholders' Equity
Net income (loss)	$ (757,744)				(757,744)
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent	(1,154)					(1,154)
Cash dividends, $ 0.10 per share	(7,751)				(7,751)
Issuance of common stock under Employee Stock Purchase Plan (in shares)		218,135
Issuance of common stock under Employee Stock Purchase Plan	4,198	$ 2	4,196
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings (in shares)		199,243
Issuance of common stock upon vesting of RSUs and settlement of PSUs, net of shares used for tax withholdings	(2,354)	$ 2	(2,356)
Stock-based compensation expense (in shares)		53,473
Stock-based compensation expense	26,897	$ 1	26,896
Issuance of common stock from stock offerings, net of tax (in shares)		42,710,949
Issuance of common stock from stock offerings, net of tax	1,383,093	$ 427	1,382,666
Equity component of 1.50 % Senior Convertible Notes due 2021 issuance, net of tax	33,575		33,575
Purchase of capped call transactions	(24,195)		(24,195)
Other income tax expense	(9,833)		(9,833)
Balances, Common Shares, Ending at Dec. 31, 2016		111,257,500
Balances, Ending at Dec. 31, 2016	$ 2,497,133	$ 1,113	$ 1,716,556		$ 794,020	$ (14,556)
Balances, Treasury Shares, Ending at Dec. 31, 2016				0
Balances, Treasury Stock, Value, Ending at Dec. 31, 2016				$ 0

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash flows from operating activities:
Net income (loss)		$ (757,744)	$ (447,710)	$ 666,051
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net gain on divestiture activity		(37,074)	(43,031)	(646)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion		790,745	921,009	767,532
Exploratory dry hole expense		(16)	36,612	44,427
Impairment of proved properties		354,614	468,679	84,480
Abandonment and impairment of unproved properties		80,367	78,643	75,638
Impairment of other property and equipment		0	49,369	0
Stock-based compensation expense		26,897	27,467	32,694
Change In Net Profits Plan liability		(7,200)	(19,525)	(29,849)
Net derivative (gain) loss		250,633	(408,831)	(583,264)
Derivative settlement gain		329,478	512,566	12,615
Amortization of discount and deferred financing costs		9,938	7,710	6,146
Non-cash (gain) loss on extinguishment of debt		(15,722)	4,123	0
Deferred income taxes		(448,643)	(276,722)	397,780
Plugging and abandonment		(6,214)	(7,496)	(8,796)
Other, net		3,499	13,761	1,069
Changes in current assets and liabilities:
Accounts receivable		(10,562)	140,200	24,088
Prepaid expenses and other		8,478	2,563	(1,822)
Accounts payable and accrued expenses		(53,210)	(86,267)	9,466
Accrued derivative settlements		34,540	5,232	(41,034)
Net Cash Provided by Operating Activities		552,804	978,352	1,456,575
Cash flows from investing activities:
Net proceeds from the sale of oil and gas properties		946,062	357,938	43,858
Capital expenditures		(629,911)	(1,493,608)	(1,974,798)
Acquisition of proved and unproved oil and gas properties		(2,183,790)	(7,984)	(544,553)
Other, net		(3,000)	(985)	(3,256)
Net Cash Used in Investing Activities		(1,870,639)	(1,144,639)	(2,478,749)
Cash flows from financing activities:
Proceeds from credit facility		947,000	1,872,500	1,285,500
Repayment of credit facility		(1,149,000)	(1,836,500)	(1,119,500)
Debt issuance costs related to credit facility		(3,132)	0	(3,388)
Net proceeds from Senior Notes		491,640	490,951	589,991
Cash paid to repurchase Senior Notes		29,904	350,000	0
Net proceeds from Senior Convertible Notes		166,617	0	0
Cash paid for capped call transactions		(24,195)	0	0
Net proceeds from sale of common stock		938,268	4,844	4,877
Dividends paid		(7,751)	(6,772)	(6,723)
Net share settlement from issuance of stock awards		(2,354)	(8,678)	(10,624)
Other, net		0	(160)	(87)
Net Cash Provided by Financing Activities		1,327,189	166,185	740,046
Net change in cash and cash equivalents		9,354	(102)	(282,128)
Cash and cash equivalents at beginning of period		18	120	282,248
Cash and cash equivalents at end of period		9,372	18	120
Supplemental schedule of additional cash flow information and non-cash activities:
Cash paid for interest, net of capitalized interest		129,761	126,988	89,145
Net cash (refunded) paid for income taxes		(4,690)	1,630	1,936
Changes in capital expenditure accruals and other		8,044	(210,819)	130,143
Fair value of properties exchanged		733	0	6,164
Value of common stock from issuance of private placement for an asset acquisition	[1]	$ 437,194	$ 0	$ 0
[1]	Refer to Note 3 - Acquisitions, Divestitures, and Assets Held for Sale and Note 15 - Equity for additional discussion.

Summary of Significant Accounti

Summary of Significant Accounting Policies (Notes)	12 Months Ended
	Dec. 31, 2016
Basis of Presentation and Significant Accounting Policies [Abstract]
Basis of Presentation and 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 crude oil and condensate, natural 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, 2016 , through the filing date of this report. Additionally, certain prior period amounts have been reclassified to conform to current period presentation in the consolidated financial statements. Use of Estimates in the Preparation of Financial Statements The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of proved oil and gas reserves, assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of proved oil and gas reserve quantities provide the basis for the calculation of depletion, depreciation, and amortization expense, impairment of proved properties, and asset retirement obligations, each of which represents a significant component of the accompanying consolidated financial statements. Cash and Cash Equivalents The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments. Accounts Receivable The Company’s accounts receivable 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 and gas 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. The Company’s allowance for doubtful accounts as of December 31, 2016 , and 2015 , totaled $1.7 million and $1.1 million , respectively, primarily for receivables from joint interest owners. 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 crude oil, natural gas, and NGLs are products with well-established markets and numerous purchasers in the Company’s operating regions. The Company had the following major customer and sales to entities under common ownership, which accounted for 10 percent or more of its total oil, natural gas, and NGL production revenue for at least one of the periods presented: For the Years Ended December 31, 2016 2015 2014 Major customer (1) 18 % 21 % 19 % Group #1 of entities under common ownership (2) 15 % 10 % 14 % Group #2 of entities under common ownership (2) 8 % 11 % 9 % ____________________________________________ (1) This major customer is the operator of the Company’s outside-operated Eagle Ford shale program, in which the Company entered into various marketing agreements with during 2013, whereby the Company is subject to certain gathering, transportation, and processing throughput commitments for up to 10 years pursuant to each contract. Because the Company shares with its operator the risk of non-performance by its counterparty purchasers, the Company has included its operator as a major customer in the table above. Several of the operator’s counterparty purchasers under these contracts are also direct purchasers of the Company’s production from other areas. As of December 31, 2016, the Company’s outside-operated Eagle Ford shale assets were classified as held for sale. (2) In the aggregate these groups of entities under common ownership represent more than 10 percent of total production revenue for the period(s) shown, however, none of the entities comprising either group individually represented more than 10 percent of the Company’s 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 date of this report. The Company has accounts in the following locations with a national bank: Denver, Colorado ; Houston, Texas ; Midland, Texas ; and Billings, Montana . The Company’s policy is to invest in highly-rated instruments and to limit the amount of credit exposure at each individual institution. 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, producing 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 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 consolidated statements of operations (“accompanying statements of operations”) for all other sales of proved properties. Unproved properties . Unproved properties consist of costs to acquire undeveloped leases as well as acquisitions of unproved reserves. When successful wells are drilled on undeveloped leaseholds, unproved property costs 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. The partial sale of unproved property is accounted for as a recovery of cost when substantial uncertainty exists as to the ultimate recovery of the cost applicable to the interest retained. A net gain on divestiture activity is recognized to the extent that the sales price exceeds the carrying amount of the unproved property. A net gain or loss on divestiture activity is recognized in the accompanying statements of operations for all other sales of unproved property. 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 consolidated 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 three 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 consolidated balance sheets (“accompanying balance sheets”) at the lower of carrying value or fair value less the cost to sell. Please refer to Note 3 – Acquisitions, Divestitures, and Assets Held for Sale 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 consolidated 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, 2016, and 2015. 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 natural 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. Stock-Based Compensation At December 31, 2016 , the Company had stock-based employee compensation plans that included RSUs and PSUs issued to employees 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. 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 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 Basic net income (loss) per common share is calculated by dividing net income or loss available to common stockholders by the basic weighted-average common shares outstanding for the respective period. The earnings per share calculations reflect the impact of any repurchases of shares of common stock made by the Company. Diluted net income (loss) per common share is calculated by dividing adjusted net income or loss by the diluted weighted-average common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist of unvested RSUs, contingent PSUs, shares issuable upon the conversion of the Senior Convertible Notes, and in-the-money outstanding stock options, which are measured using the treasury stock method. All outstanding stock options were exercised during the year ended December 31, 2014. When the Company recognizes a loss from continuing operations, as was the case for the years ended December 31, 2016 , and 2015 , all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted earnings per share. 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 allows the Company to settle the principal amount of the Senior Convertible Notes in cash and to settle the excess conversion value in shares, as well as cash in lieu of fractional shares. However, the Company reserves the right to settle the Senior Convertible Notes in any manner allowed under the indenture as business conditions warrant. Shares of the Company’s common stock traded at an average closing price below the $40.50 conversion price for the portion of the year ended December 31, 2016, during which the Senior Convertible Notes were outstanding. In connection with the Senior Convertible Notes offering, the Company entered into capped call transactions with affiliates of the underwriters that effectively prevent dilution upon settlement up to the $60.00 cap price. The capped call transactions are not reflected in diluted net income per share, nor will they ever be, as they are anti-dilutive. Please refer to Note 5 - Long-Term Debt for additional discussion. The following table details the weighted-average dilutive and anti-dilutive securities for the years presented: For the Years Ended December 31, 2016 2015 2014 (in thousands) Dilutive — — 814 Anti-dilutive 280 256 — The following table sets forth the calculations of basic and diluted earnings per share: For the Years Ended December 31, 2016 2015 2014 (in thousands, except per share amounts) Net income (loss) $ (757,744 ) $ (447,710 ) $ 666,051 Basic weighted-average common shares outstanding 76,568 67,723 67,230 Add: dilutive effect of unvested RSUs, contingent PSUs, and stock options (1) — — 814 Add: dilutive effect of 1.50% Senior Convertible Notes (2) — — — Diluted weighted-average common shares outstanding 76,568 67,723 68,044 Basic net income (loss) per common share $ (9.90 ) $ (6.61 ) $ 9.91 Diluted net income (loss) per common share $ (9.90 ) $ (6.61 ) $ 9.79 ____________________________________________ (1) For the years ended December 31, 2016 , and 2015 , the shares were anti-dilutive and excluded from the calculation of diluted earnings per share. (2) For the year ended December 31, 2016 , shares of the Company’s common stock traded at an average closing price below the $40.50 conversion price, and therefore, had no dilutive impact and were excluded from the calculation of diluted earnings per share. 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). The changes in the balances of components comprising other comprehensive income (loss) are presented in the following table: Pension Liability Adjustments (in thousands) For the year ended December 31, 2014 Net actuarial loss $ (10,062 ) Reclassification to earnings 706 Tax benefit 3,460 Loss, net of tax $ (5,896 ) For the year ended December 31, 2015 Net actuarial loss $ (4,990 ) Reclassification to earnings 1,853 Tax benefit 1,047 Loss, net of tax $ (2,090 ) For the year ended December 31, 2016 Net actuarial loss $ (3,322 ) Reclassification to earnings 1,598 Tax benefit 570 Loss, net of tax $ (1,154 ) 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, 2016 , compared with $202.0 million of outstanding loans as of December 31, 2015 . 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 within the United States. The Company reports as a single industry segment. Prior to the sale of the Company’s Mid-Continent assets in 2015, the Company acted as the first purchaser of natural gas and natural gas liquids produced by third parties in certain cases. The Company considered this function as ancillary to its oil and gas producing activities. The amount of income these operations generated from marketing gas produced by third parties was not material to the Company’s results of operations, and segmentation of such activity would not have provided a better understanding of the Company’s performance. However, gross revenue and expense related to marketing activities for gas produced by third parties is presented in the marketed gas system revenue and marketed gas system expense line items in the accompanying statements of operations. There was no marketed gas system revenue or expense recorded for the year ended December 31, 2016. 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 special purpose entities (“SPE”), 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 2016 or 2015 . Recently Issued Accounting Standards Effective January 1, 2016, the Company adopted, on a retrospective basis, Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis . This ASU clarifies the consolidation reporting guidance in GAAP. There was no impact to the Company’s financial statements or disclosures from the adoption of this standard. Effective December 31, 2016, the Company adopted FASB ASU No. 2014-15, Presentation of Financial Statements-Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern . This ASU requires management to evaluate whether there are conditions or events that raise substantial doubt about an entity’s ability to continue as a going concern within one year after the date that the entity’s financial statements are issued, or within one year after the date the entity’s financial statements are available to be issued, and to provide disclosures when certain criteria are met. There was no impact to the Company’s financial statements or disclosures from the adoption of this standard. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”) for the recognition of revenue from contracts with customers. Subsequent to the issuance of this ASU, the FASB issued additional related ASUs as follows: • In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date . This ASU deferred the effective date of ASU 2014-09 by one year. • In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net) . This ASU amends the principal versus agent guidance in ASU No. 2014-09. • In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing . This ASU amends the identification of performance obligations and accounting for licenses in ASU 2014-09. • In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients. This ASU amends certain issues in ASU 2014-09 on transition, collectibility, noncash consideration, and the presentation of sales taxes and other similar taxes. • In December 2016, the FASB issued ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers . This ASU is meant to improve and clarify or to correct unintended application of narrow aspects of the guidance in ASU 2014-09. ASU 2014-09 and each update have the same effective date and transition requirements. That is, the guidance under these standards is to be applied using a full retrospective method or a modified retrospective method, as outlined in ASU 2014-09, and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted only for annual periods, and interim periods within those annual periods, beginning after December 15, 2016. The Company has established a cross-functional implementation team that is currently evaluating the provisions of each of these standards, analyzing their impact on the Company’s contract portfolio, reviewing current accounting policies and practices to identify potential differences that would result from applying the requirements of these standards to the Company’s revenue contracts, and assessing their potential impact on the Company’s financial statements and disclosures. The Company currently plans to apply the modified retrospective method upon adoption and plans to adopt the guidance on the effective date of January 1, 2018. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which changes the accounting for leases. This guidance is to be applied using a modified retrospective method and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2018. Early adoption is permitted. The Company is currently evaluating the provisions of this guidance and assessing its potential impact on the Company’s financial statements and disclosures. In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting . This ASU makes targeted amendments to the accounting for employee share-based payments. This guidance is to be applied using various transition methods, such as full retrospective, modified retrospective, and prospective, based on the criteria for the specific amendments as outlined in the guidance. The guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2016. Early adoption is permitted, as long as all of the amendments are adopted in the same period; however, the Company plans on adopting in the first quarter of 2017. The Company is currently evaluating the provisions of this guidance and assessing its potential impact on the Company’s financial statements and disclosures. In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. This ASU is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. This guidance is to be applied using a retrospective method. The guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted, as long as all of the amendments are adopted in the same period. The Company is currently evaluating the provisions of this guidance and assessing its potential impact on the Company’s financial statements and disclosures. In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. This ASU clarifies how entities should present restricted cash and restricted cash equivalents in the statement of cash flows. This guidance is to be applied using a retrospective method and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted. The Company is currently evaluating the provisions of this guidance and assessing its potential impact on the Company’s financial statements and disclosures. In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU 2017-01”). This ASU 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. This guidance is to be applied using a prospective method and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted as outlined in ASU 2017-01. The Company is currently evaluating the provisions of this guidance and as

Accounts Receivable and Account

Accounts Receivable and Accounts Payable and Accrued Expenses	12 Months Ended
	Dec. 31, 2016
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: As of December 31, 2016 2015 (in thousands) Accrued oil, gas, and NGL production revenue $ 96,101 $ 58,256 Amounts due from joint interest owners 29,669 22,269 State severance tax refunds 15,320 12,072 Accrued derivative settlements 6,512 34,579 Other 4,348 6,948 Total accounts receivable $ 151,950 $ 134,124 Accounts payable and accrued expenses are comprised of the following: As of December 31, 2016 2015 (in thousands) Accrued capital expenditures $ 107,009 $ 97,355 Revenue and severance tax payable 39,617 44,387 Accrued lease operating expense 15,956 21,943 Accrued property taxes 6,606 14,078 Accrued compensation 34,761 41,154 Accrued derivative settlements 6,473 — Accrued interest 45,059 34,378 Other 44,227 49,222 Total accounts payable and accrued expenses $ 299,708 $ 302,517

Acquisitions, Divestitures, and

Acquisitions, Divestitures, and Assets Held for Sale	12 Months Ended
	Dec. 31, 2016
Acquisitions, Divestitures, and Assets Held for Sale Disclosure [Abstract]
Acquisitions, Divestitures, and Assets Held for Sale	Note 3 – Acquisitions, Divestitures, and Assets Held for Sale 2016 Acquisition Activity • Rock Oil Acquisition. On October 4, 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”) for an adjusted purchase price of $991.0 million . The effective date of the acquisition was September 1, 2016. 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 15 - 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 preliminary 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 $ 991,038 Fair value of assets and liabilities acquired: Wells in progress $ 5,672 Proved oil and gas properties 81,917 Unproved oil and gas properties 913,594 Other assets 5,338 Total fair value of oil and gas properties acquired 1,006,521 Working capital (7,888 ) Asset retirement obligation (7,595 ) Total fair value of net assets acquired $ 991,038 • QStar Acquisition. On December 21, 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”) for $1.6 billion , consisting of $1.2 billion in cash consideration and the issuance of approximately 13.4 million shares of the Company’s common stock. The cash consideration was funded by proceeds from the recent Raven/Bear Den divestiture and the December 2016 equity offering. Please refer to Note 15 - Equity for additional discussion. The effective date of the acquisition was September 1, 2016 . 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 preliminary 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 $ 1,167,373 Fair value of equity consideration (1) 437,194 Total consideration at closing $ 1,604,567 Assets and liabilities acquired: Wells in progress $ 21,812 Proved oil and gas properties 61,614 Unproved oil and gas properties 1,537,923 Total oil and gas properties acquired 1,621,349 Working capital (9,141 ) Asset retirement obligation (7,641 ) Total net assets acquired $ 1,604,567 ____________________________________________ (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 prohibits the sale of such stock until no earlier than the 90th day after issuance. The Rock Oil Acquisition and QStar Acquisition are each subject to normal post-closing adjustments expected to occur in the first half of 2017. These post-closing adjustments are estimated as of December 31, 2016, and reflected in the tables above. • Other Acquisitions. During the fourth quarter of 2016, the Company entered into a definitive purchase agreement to acquire approximately 2,900 net acres of oil and gas assets in the Midland Basin for a gross purchase price of $60 million , subject to customary purchase price adjustments. This acquisition closed subsequent to December 31, 2016. 2015 Acquisition Activity There was no significant acquisition activity during the year ended December 31, 2015. 2014 Acquisition Activity • Gooseneck Property Acquisitions On September 24, 2014 , the Company acquired approximately 61,000 net acres of proved and unproved oil and gas properties in its Gooseneck area in North Dakota, along with related equipment, contracts, records, and other assets. Total cash consideration paid by the Company after final closing adjustments was $321.8 million and the effective date for the acquisition was July 1, 2014 . On October 15, 2014 , the Company acquired additional interests in proved and unproved oil and gas properties in its Gooseneck area. Total cash consideration paid by the Company was $84.8 million and the effective date for the acquisition was August 1, 2014 . Each of these acquisitions qualified as a business combination under ASC Topic 805, Business Combinations . The Company allocated the final adjusted purchase prices to the acquired assets and liabilities based on fair value as of the respective acquisition dates, as summarized in the table below. These measurements resulted in no goodwill or bargain purchase gain being recognized. Acquisition #1 Acquisition #2 As of September 24, 2014 As of October 15, 2014 (in thousands) Cash consideration $ 321,807 $ 84,836 Fair value of assets and liabilities acquired: Proved oil and gas properties $ 203,467 $ 54,612 Unproved oil and gas properties 126,588 29,610 Total fair value of oil and gas properties acquired 330,055 84,222 Working capital (6,135 ) 2,232 Asset retirement obligation (2,113 ) (1,618 ) Total fair value of net assets acquired $ 321,807 $ 84,836 • Rocky Mountain Acquisitions. In addition to the Gooseneck property acquisitions discussed above, the Company acquired other proved and unproved properties in its Rocky Mountain region during 2014, primarily in the Powder River Basin, in multiple transactions for approximately $135.5 million in total cash consideration after final closing adjustments, plus approximately 7,000 net acres of non-core assets in the Company’s Rocky Mountain region. 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 total cash received at closing, net of commissions and payments to Net Profits Plan participants (referred throughout this report as “net divestiture proceeds”), of $110.6 million . The Company recorded a net gain of $16.4 million related to these divested assets for the year ended December 31, 2016 . 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 $756.2 million . The Company recorded a net gain of $29.5 million related to these divested assets for the year ended December 31, 2016 . In conjunction with the divestiture of certain Rocky Mountain assets, the Company closed its Billings, Montana office. Please refer to Note 14 - Exit and Disposal Costs for additional discussion. The following table presents income (loss) before income taxes of the Raven/Bear Den assets sold on December 1, 2016, for the years ended December 31, 2016, 2015, and 2014. This divestiture is considered a disposal of a significant asset group. For the Years Ended December 31, 2016 2015 2014 (in thousands) Income (loss) before income taxes (1) $ (6,601 ) $ (12,530 ) $ 197,256 ____________________________________________ (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 impairment of proved properties expense of approximately $17.8 million for the year ended December 31, 2015. • Permian Divestiture. During the third quarter of 2016, the Company divested its non-core properties in southeast New Mexico for net divestiture proceeds of $54.6 million and recorded a net loss of $10.1 million for the year ended December 31, 2016 . Each of these divestitures are subject to normal post-closing adjustments, and the respective post-closings are expected to occur in the first half of 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. Please refer to Note 14 - Exit and Disposal Costs for additional discussion. • 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. 2014 Divestiture Activity • Rocky Mountain Divestiture. During the second quarter of 2014, the Company divested certain non-core assets in the Montana portion of the Williston Basin. Net divestiture proceeds were $42.0 million and the final net gain on this divestiture was $26.9 million . The Company recorded $27.6 million of write-downs to fair value less estimated costs to sell for assets that were held for sale during the year ended December 31, 2014, which offset the net gain on the Rocky Mountain Divestiture 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 there is reasonable certainty 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 costs to sell. Any subsequent changes to the fair value less estimated costs to sell impact the measurement of assets held for sale, with any gain or loss reflected in the net gain on divestiture activity line item in the accompanying statements of operations. As of December 31, 2016 , the accompanying balance sheets present $372.6 million of assets held for sale, net of accumulated depletion, depreciation, and amortization expense, which consists of the Company’s outside-operated Eagle Ford shale assets. A corresponding aggregate asset retirement obligation liability of $26.2 million is separately presented. There were no material assets held for sale as of December 31, 2015. Subsequent to December 31, 2016 , the Company entered into a definitive agreement with Venado EF LLC (“Venado”) for the sale of its outside-operated Eagle Ford shale assets, including its ownership interest in related midstream assets (the “Eagle Ford Transaction”) for a gross purchase price of $800 million , subject to customary purchase price adjustments. The Company expects to close the Eagle Ford Transaction in the first quarter of 2017. Pursuant to the Venado definitive agreement, the Company entered into certain NYMEX swap contracts to be novated to Venado at closing, as summarized below: • Oil swap contracts through the fourth quarter of 2021 for a total of 4.3 million Bbls of oil production at contract prices ranging from $54.05 to $57.00 per Bbl. • Gas swap contracts through the fourth quarter of 2021 for a total of 4.6 million MMBtu of gas production at contract prices ranging from $2.82 to $2.99 per MMBtu. • NGL swap contracts through the fourth quarter of 2019 for a total of 4.5 million Bbls of NGL production at contract prices ranging from $11.81 to $48.51 per Bbl. The Company is not at risk of a net financial obligation with the derivative counterparties should the value of the contracts become negative, unless the Eagle Ford Transaction is terminated because the Company did not comply in all material respects with its covenants under the definitive agreement or because of a material inaccuracy of the Company’s representations and warranties. The closing of the Eagle Ford Transaction is subject to the satisfaction of customary closing conditions, and there can be no assurance that it will close on the expected closing date or at all. The following table presents income (loss) before income taxes for the years ended December 31, 2016, 2015, and 2014, of the Company’s outside-operated Eagle Ford shale assets held for sale as of December 31, 2016, which is considered a significant asset disposal group. For the Years Ended December 31, 2016 2015 2014 (in thousands) Income (loss) before income taxes (1) $ (218,506 ) $ 71,556 $ 294,376 ____________________________________________ (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 expense. Additionally, loss before income taxes for the year ended December 31, 2016 , includes $269.6 million of proved property impairment expense. Subsequent to December 31, 2016, the Company announced its plans to sell its remaining Williston Basin assets in the Divide County, North Dakota area (referred to as “Divide County” throughout this report) by mid-year 2017. These assets were classified as held and used as of December 31, 2016. Based on preliminary estimates of fair value less selling costs as of the filing date of this report, the Company expects to record a write down in the range of $200 million to $400 million in the first quarter of 2017 upon the Divide County assets being reclassified to held for sale. The Company determined that neither these planned nor executed asset sales qualify for discontinued operations accounting under financial statement presentation authoritative guidance.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 2014 (in thousands) Current portion of income tax expense Federal $ 2,932 $ — $ — State 1,539 1,571 868 Deferred portion of income tax expense (benefit) (448,643 ) (276,722 ) 397,780 Total income tax expense (benefit) $ (444,172 ) $ (275,151 ) $ 398,648 Effective tax rate 37.0 % 38.1 % 37.4 % The components of the net deferred income tax liabilities are as follows: As of December 31, 2016 2015 (in thousands) Deferred tax liabilities: Oil and gas properties $ 518,394 $ 854,029 Derivative asset — 179,543 Other 7,733 1,233 Total deferred tax liabilities 526,127 1,034,805 Deferred tax assets: Federal and state tax net operating loss carryovers 151,343 244,942 Derivative liability 31,349 — Stock compensation 10,083 14,529 Credit carryover 12,448 6,952 Other liabilities 10,567 20,497 Total deferred tax assets 215,790 286,920 Valuation allowance (5,335 ) (10,394 ) Net deferred tax assets 210,455 276,526 Total net deferred tax liabilities $ 315,672 $ 758,279 Current federal income tax refundable $ 644 $ 5,378 Current state income tax refundable $ — $ 65 Current state income tax payable $ 1,181 $ — At December 31, 2016 , the Company estimated its federal net operating loss (“NOL”) carryforward at $540.2 million , which includes unrecognized excess income tax benefits associated with stock awards of $126.7 million . The Company also has federal R&D credit carryforwards of $7.2 million . The federal NOL carryforward begins to expire in 2031 and the federal R&D credit carryforwards expire between 2028 and 2033. The Company’s alternative minimum tax (“AMT”) credit carryforward of $5.6 million does not expire. State NOL carryforwards were $184.6 million and state tax credits were $528,000 as of December 31, 2016 . State NOLs and credits expire between 2017 and 2037. The Company’s current valuation allowance relates to state NOL carryforwards and state tax credits, which the Company anticipates will expire before they can be utilized. The change in the valuation allowance from 2015 to 2016 primarily relates to anticipated utilization of accumulated charitable contributions and an allocable change to the Company’s mix of state apportioned losses and the anticipated utilization of state cumulative NOLs. Federal income tax expense differs from the amount that would be provided by applying the statutory United States federal income tax rate to income before income taxes primarily due to the effect of state income taxes, changes in valuation allowances, R&D credits, and accumulated impacts of other smaller permanent differences, reported as follows: For the Years Ended December 31, 2016 2015 2014 (in thousands) Federal statutory tax expense (benefit) $ (420,671 ) $ (253,001 ) $ 372,644 Increase (decrease) in tax resulting from: State tax expense (benefit) (net of federal benefit) (17,549 ) (21,583 ) 21,350 Change in valuation allowance (5,059 ) 3,148 2,245 Research and development credit — (1,971 ) — Other (893 ) (1,744 ) 2,409 Income tax expense (benefit) $ (444,172 ) $ (275,151 ) $ 398,648 Acquisitions, divestitures, drilling activity, and basis differentials impacting 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, and after significant acquisitions, divestitures, or changes in drilling activity or estimated state revenue occurs during the year. In 2016, most of this activity occurred in the fourth quarter. 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 tax year, the Company is no longer subject to United States federal or state income tax examinations by these tax authorities for years before 2013. 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. 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 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 2017 . The total amount recorded for unrecognized tax benefits is presented below: For the Years Ended December 31, 2016 2015 2014 (in thousands) Beginning balance $ 2,782 $ 1,582 $ 2,358 Additions for tax positions of prior years 9 1,200 140 Settlements (2,345 ) — (916 ) Ending balance $ 446 $ 2,782 $ 1,582

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Long-Term Debt	Note 5 – Long-Term Debt Revolving Credit Facility The Company’s Fifth Amended and Restated Credit Agreement (the “Credit Agreement”) provides for a maximum loan amount of $2.5 billion and has a maturity date of December 10, 2019 . During 2016, the following amendments were made to the Credit Agreement: • On April 8, 2016 , as part of the regular, semi-annual borrowing base redetermination process, the Company entered into a Sixth Amendment to the Credit Agreement, which reduced the Company’s borrowing base to $1.25 billion from $2.0 billion at December 31, 2015. This expected reduction was primarily due to a decline in commodity prices, which resulted in a decrease in the Company’s proved reserves as of December 31, 2015. The amendment also reduced the aggregate lender commitments to $1.25 billion , and changed the required percentage of oil and gas properties subject to a mortgage 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. Further, this amendment revised certain of the Company’s covenants under the Credit Agreement and modified the borrowing base utilization grid, as discussed below. The Company incurred approximately $3.1 million in deferred financing costs associated with this amendment to the Credit Agreement. • On August 8, 2016 , the Company entered into a Seventh Amendment to the Credit Agreement to allow for capped call transactions. • Upon issuing the Senior Convertible Notes and 2026 Notes (as defined and discussed below) during the third quarter of 2016, the Company’s borrowing base and aggregate lender commitments were reduced to $1.1 billion . • On September 30, 2016, as part of the regular, semi-annual borrowing base redetermination process, the Company entered into an Eighth Amendment to the Credit Agreement, which increased the Company’s borrowing base to $1.35 billion and the aggregate lender commitments to $1.25 billion due to an increase in commodity prices and the value of the proved reserves associated with the Rock Oil Acquisition. • On December 1, 2016 , the Company’s borrowing base and aggregate lender commitments were reduced to $1.17 billion as a result of closing the sale of the Company’s Raven/Bear Den assets. As a result of the various reductions to the Company’s borrowing base and aggregate lender commitments throughout 2016, the Company recorded approximately $2.5 million of expense related to the acceleration of unamortized deferred financing costs for the year ended 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 scheduled redetermination date is April 1, 2017 , and the Company expects a reduction to its borrowing base as a result of the anticipated sale of its outside-operated Eagle Ford shale assets and the decrease in proved reserves at December 31, 2016. 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, 2016 , and through the filing date 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, and available borrowing capacity under the Credit Agreement as of February 15, 2017 , December 31, 2016 , and December 31, 2015 : As of February 15, 2017 As of December 31, 2016 As of December 31, 2015 (in thousands) Credit facility balance (1) $ 103,500 $ — $ 202,000 Letters of credit (2) 200 200 200 Available borrowing capacity 1,061,300 1,164,800 1,297,800 Total aggregate lender commitment amount $ 1,165,000 $ 1,165,000 $ 1,500,000 ____________________________________________ (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 $5.9 million and $4.9 million as of December 31, 2016 , and 2015 , respectively. (2) Letters of credit 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, 2016 , and 2015 , consisted of the following: As of December 31, 2016 2015 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 $ 346,955 $ 3,372 $ 343,583 $ 350,000 $ 4,106 $ 345,894 6.125% Senior Notes due 2022 561,796 6,979 554,817 600,000 8,714 591,286 6.50% Senior Notes due 2023 394,985 4,436 390,549 400,000 5,231 394,769 5.0% Senior Notes due 2024 500,000 6,533 493,467 500,000 7,455 492,545 5.625% Senior Notes due 2025 500,000 7,619 492,381 500,000 8,524 491,476 6.75% Senior Notes due 2026 500,000 8,078 491,922 — — — Total $ 2,803,736 $ 37,017 $ 2,766,719 $ 2,350,000 $ 34,030 $ 2,315,970 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, 2016 , and through the filing date of this report. All Senior Notes are registered under the Securities Act as of December 31, 2016 . 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. The Company canceled all repurchased Senior Notes upon cash settlement. 2019 Notes . On May 7, 2015 , the Company commenced a cash tender offer for any and all of its outstanding 6.625% Senior Notes due 2019 (“2019 Notes”) at a price of $1,036.88 per $1,000 of principal amount for all 2019 Notes tendered by May 20, 2015 (“Consent Payment Deadline”), and at a price of $1,006.88 per $1,000 of principal amount for all 2019 Notes properly tendered thereafter. On the Consent Payment Deadline, the Company received tenders and consents from the holders of approximately $242.9 million in aggregate principal amount, or approximately 69% , of its outstanding 2019 Notes in connection with the cash tender offer. Following its entry into the supplemental indenture dated as of May 21, 2015, to the indenture dated as of February 7, 2011, between the Company and U.S. Bank National Association, as trustee, the Company accepted the 2019 Notes tendered as of the Consent Payment Deadline in exchange for payment of total consideration, including accrued interest, of approximately $256.2 million under the Tender Offer and Consent Solicitation. On June 5, 2015 , the Company accepted $1.5 million of 2019 Notes tendered after the Consent Payment Deadline in exchange for payment of total consideration, including accrued interest, of approximately $1.6 million . On June 22, 2015 , the Company redeemed the remaining outstanding 2019 Notes at a redemption price of 103.313% of the principal amount for payment of total consideration, including accrued interest, of approximately $111.5 million . The Company recorded a loss on extinguishment of debt related to the tender offer and redemption of its 2019 Notes 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. 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. The net proceeds were used to repay outstanding borrowings under the Company’s credit facility and for general corporate purposes. 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 on October 4, 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 2021 (“the Senior Convertible Notes”), which mature on July 1, 2021 . 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 net proceeds were used to partially fund the Rock Oil Acquisition that closed on October 4, 2016 , as well as pay the cost of the capped call transactions discussed below. The Senior Convertible Notes mature on July 1, 2021 , unless earlier repurchased or 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, regardless of the foregoing circumstances. 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 allows the Company to settle the principal amount of the Senior Convertible Notes in cash and to settle the excess conversion value in shares, as well as cash in lieu of fractional shares. The Senior Convertible Notes were not convertible at the option of holders as of December 31, 2016 , or through the filing date of this report. Notwithstanding the inability to convert, the if-converted value of the Senior Convertible Notes as of December 31, 2016 , did not exceed the principal amount. In accounting for the Senior Convertible Notes at issuance, the Company allocated proceeds from the Senior Convertible Notes into debt and equity components according to the authoritative accounting guidance for convertible debt instruments that may be fully or partially settled in cash upon conversion. The initial carrying amount of the debt component, which approximates its fair value, was estimated using an interest rate for nonconvertible debt with terms similar to the Senior Convertible Notes. The effective interest rate used was 7.25% . The 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 carrying value of the Senior Convertible Notes as interest expense through the maturity date of July 1, 2021 . Upon issuance of the Senior Convertible Notes, the Company recorded $132.3 million as long-term debt and $40.2 million as additional paid-in capital in stockholders’ equity in the accompanying balance sheets. Interest expense recognized on the Senior Convertible Notes related to the stated interest rate and amortization of the debt discount totaled $3.7 million for the year ended December 31, 2016 . 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, 2016 : As of December 31, 2016 (in thousands) Principal amount of Senior Convertible Notes $ 172,500 Unamortized debt discount (37,513 ) Unamortized deferred financing costs (4,131 ) Net carrying amount $ 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, 2016 : As of December 31, 2016 (in thousands) Equity component due to allocation of proceeds to equity $ 40,217 Less: related issuance costs (1,375 ) Less: deferred tax liability (5,267 ) Net carrying amount $ 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, 2016 , and through the filing date 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, as measured under the terms of the capped call transactions (“market price per share”), 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 and is subject to anti-dilution adjustments substantially similar to those applicable to the conversion rate of the Senior Convertible Notes. The cap price of the capped call transactions was initially $60.00 per share, and is subject to certain adjustments under the terms of the capped call transactions. If, however, the market price per share exceeds the cap price of the capped call transactions, there would be dilution and/or there would not be an offset of such potential cash payments, in each case, to the extent that such market price per share exceeds the cap price of the capped call transactions. 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, 2016 , 2015 , and 2014 , were $17.0 million , $25.1 million , and $16.2 million , respectively.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2016
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 $31.1 million , gathering, processing, and transportation throughput commitments of $970.9 million , office leases, including maintenance, of $50.1 million , and other miscellaneous contracts and leases of $6.0 million . The annual minimum payments for the next five years and total minimum payments thereafter are presented below: Years Ending December 31, Amount (1) (in thousands) 2017 $ 145,075 2018 148,240 2019 144,379 2020 141,010 2021 141,654 Thereafter 337,745 Total $ 1,058,103 ____________________________________________ (1) During the third quarter of 2015, the Company closed its office in Tulsa, Oklahoma. These amounts include lease payments for the Tulsa office, net of sublease income. The Company expects to receive $2.7 million of total sublease income through 2019 . Drilling Rig Contracts The Company has several drilling rig contracts in place to facilitate drilling plans. Early termination of these rig contracts as of December 31, 2016 , would have resulted in termination penalties of $14.2 million , which would be in lieu of paying the remaining drilling commitments of $31.1 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. Pipeline Transportation Commitments The Company has gathering, processing, and transportation throughput commitments with various third parties that require delivery of a minimum amount of natural gas, crude oil, NGLs, and water. As of December 31, 2016 , the Company has commitments to deliver a minimum of 1,461 Bcf of natural gas, 70 MMBbl of crude oil, 13 MMBbl of NGLs, and 25 MMBbl of water through 2034 . 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, 2016 , if the Company delivered no further product, the aggregate undiscounted deficiency payments total approximately $970.9 million through 2034. If a shortfall in the minimum volume commitment for natural 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. Subsequent to December 31, 2016 , the Company entered into a definitive agreement for the sale of its outside-operated Eagle Ford shale assets held for sale at December 31, 2016 , and expects to close the transaction in the first quarter of 2017. Upon closing of the sale, the Company would no longer be subject to transportation throughput commitments totaling 514 Bcf of natural gas, 52 MMBbl of oil, and 13 MMBbl of NGLs, or $501.9 million of the potential undiscounted deficiency payments presented in the table above. As of the filing date 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, 2016 , 2015 , and 2014 , was $5.2 million , $6.1 million , and $6.5 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 will not 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, 2016
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, 2016 , approximately 5.5 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. Stock options were issued out of the St. Mary Land & Exploration Company Stock Option Plan and the St. Mary Land & Exploration Company Incentive Stock Option Plan, both predecessors to the Equity Plan, although the last grant was in 2004, and all remaining stock options were exercised during the year ended December 31, 2014. 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 0% to 200% of the number of PSUs awarded and is determined based on certain performance criteria over a three -year measurement period. The performance criteria for the 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 was 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 will 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 $11.0 million , $10.6 million , and $16.0 million for the years ended December 31, 2016 , 2015 , and 2014 , respectively. As of December 31, 2016 , there was $15.9 million of total unrecognized expense related to PSUs, which is being amortized through 2019 . A summary of the status and activity of non-vested PSUs is presented in the following table: For the Years Ended December 31, 2016 2015 2014 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) 626,328 $ 61.81 433,660 $ 73.63 572,469 $ 66.07 Granted (1) 447,971 $ 26.56 320,753 $ 45.34 202,404 $ 94.66 Vested (1) (130,353 ) $ 64.17 (76,438 ) $ 51.76 (206,830 ) $ 64.79 Forfeited (1) (115,023 ) $ 55.59 (51,647 ) $ 73.62 (134,383 ) $ 86.72 Non-vested at end of year (1) 828,923 $ 43.25 626,328 $ 61.81 433,660 $ 73.63 ____________________________________________ (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 2016 , 2015 , and 2014 was $11.9 million , $14.5 million , and $19.2 million , respectively. The PSUs granted in 2015 and 2014 will remain unvested 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 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 unvested portions of a PSU award will be forfeited when the employee leaves the company. A summary of the shares of common stock issued to settle PSUs is presented in the table below: For the Years Ended December 31, 2016 2015 2014 Shares of common stock issued to settle PSUs (1) 44,870 288,962 130,163 Less: shares of common stock withheld for income and payroll taxes (14,809 ) (100,683 ) (45,042 ) Net shares of common stock issued 30,061 188,279 85,121 Multiplier earned 0.2 1.0 0.55 ____________________________________________ (1) During the years ended December 31, 2016 , 2015 , and 2014 , the Company issued shares of common stock for PSUs granted in 2013, 2012, and 2011. The Company and the 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, 2016, 2015, and 2014 was $8.4 million , $4.0 million , and $13.4 million , respectively. 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 RSUs for the years ended December 31, 2016 , 2015 , and 2014 , was $11.9 million , $13.4 million , and $13.9 million , respectively. As of December 31, 2016 , there was $14.4 million of total unrecognized expense related to unvested RSU awards, which is being amortized through 2019 . 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 is presented below: For the Years Ended December 31, 2016 2015 2014 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 543,737 $ 55.01 515,724 $ 68.29 580,431 $ 57.05 Granted 417,065 $ 28.08 356,246 $ 43.72 234,560 $ 83.98 Vested (241,363 ) $ 58.06 (278,289 ) $ 63.12 (253,031 ) $ 58.19 Forfeited (115,323 ) $ 43.52 (49,944 ) $ 66.53 (46,236 ) $ 62.06 Non-vested at end of year 604,116 $ 37.39 543,737 $ 55.01 515,724 $ 68.29 The fair value of RSUs granted in 2016 , 2015 , and 2014 was $11.7 million , $15.6 million , and $19.7 million , respectively. The RSUs granted in 2015 and 2014 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 2016 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 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 unvested 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 RSUs is presented in the table below: For the Years Ended December 31, 2016 2015 2014 Shares of common stock issued to settle RSUs (1) 241,363 278,289 253,031 Less: shares of common stock withheld for income and payroll taxes (72,181 ) (91,045 ) (81,434 ) Net shares of common stock issued 169,182 187,244 171,597 ____________________________________________ (1) During the years ended December 31, 2016 , 2015 , and 2014 , the Company issued shares of common stock for RSUs granted in previous years. The Company and the 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 RSUs that vested during the years ended December 31, 2016, 2015, and 2014 was $14.0 million , $17.6 million , and $14.7 million , respectively. Stock Option Grants The Company previously granted stock options under the St. Mary Land & Exploration Company Stock Option Plan and the St. Mary Land & Exploration Company Incentive Stock Option Plan. The last issuance of stock options occurred on December 31, 2004. Stock options to purchase shares of the Company’s common stock were granted to eligible employees and members of the Board of Directors. All options granted under the option plans were granted at exercise prices equal to the respective closing market price of the Company’s underlying common stock on the grant dates. All stock options granted under the option plans were exercisable for a period of up to 10 years from the date of grant. The remaining options from the 2004 grant were exercised during the year ended December 31, 2014, and thus there is no unrecognized compensation expense related to stock option awards. A summary of activity associated with the Company’s Stock Option Plans during the year ended December 31, 2014, is presented in the following table: Shares Weighted-Average Exercise Price Aggregate Intrinsic Value For the year ended December 31, 2014 Outstanding, start of year 39,088 $ 20.87 $ — Exercised (39,088 ) $ 20.87 $ 1,993,726 Forfeited — $ — $ — Outstanding, end of year — $ — $ — Vested and exercisable at end of year — $ — $ — The fair value of options was measured at the date of grant using the Black-Scholes-Merton option-pricing model. Cash received from stock options exercised for the year ended December 31, 2014 , was $4.0 million . Cash flows resulting from excess tax benefits are classified as part of cash flows from financing activities. Excess tax benefits are realized tax benefits from tax deductions for vested RSUs, settled PSUs, and exercised options in excess of the deferred tax asset attributable to stock compensation costs for such equity awards. The Company recorded no excess tax benefits for the years ended December 31, 2016 , 2015 , and 2014 . Director Shares In 2016 , 2015 , and 2014 , the Company issued 53,473 , 39,903 , and 27,677 shares, respectively, of its common stock to its non-employee directors under the Company’s Equity Plan. The Company recorded $2.0 million of compensation expense for the year ended December 31, 2016 , related to director shares issued, and $1.6 million for each of the years ended December 31, 2015 , and 2014 . 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. 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 the lower of 85% of the closing price of the stock on the first day of the offering period or 85% of the closing price of the stock on the purchase date, and shares issued under the ESPP have no restriction period. The ESPP is intended to qualify under Section 423 of the IRC. The Company had approximately 0.7 million shares available for issuance under the ESPP as of December 31, 2016 . There were 218,135 , 197,214 , and 83,136 shares issued under the ESPP in 2016 , 2015 , and 2014 , respectively. Total proceeds to the Company for the issuance of these shares were $4.2 million , $4.8 million , and $4.1 million for the years ended December 31, 2016 , 2015 , and 2014 , respectively. The fair value of ESPP grants is measured at the date of grant using the Black-Scholes-Merton option-pricing model. Expected volatility was 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, 2016 2015 2014 Risk free interest rate 0.4 % 0.1 % 0.1 % Dividend yield 0.4 % 0.2 % 0.1 % Volatility factor of the expected market price of the Company’s common stock 95.0 % 61.2 % 33.0 % Expected life (in years) 0.5 0.5 0.5 The Company expensed $2.0 million , $1.8 million , and $1.1 million for the years ended December 31, 2016 , 2015 , and 2014 , 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 $5.4 million , $5.6 million , and $6.4 million for the years ended December 31, 2016 , 2015 , and 2014 , 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, 2016 2015 2014 (in thousands) Cash payments made or accrued related to operations $ 6,608 $ 3,498 $ 9,016 Cash payments made or accrued related to divestitures 24,349 3,789 8,341 Total net settlements $ 30,957 $ 7,287 $ 17,357

Pension Benefits

Pension Benefits	12 Months Ended
	Dec. 31, 2016
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [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 (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 December 31, 2015. Employees participating in the Pension Plans as of December 31, 2015, 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 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, 2016 2015 (in thousands) Change in benefit obligation: Projected benefit obligation at beginning of year $ 62,547 $ 57,867 Service cost 8,200 7,949 Interest cost 2,908 2,496 Actuarial loss 2,662 2,397 Benefits paid (6,658 ) (8,162 ) Projected benefit obligation at end of year 69,659 62,547 Change in plan assets: Fair value of plan assets at beginning of year 25,769 27,940 Actual return on plan assets 1,575 (410 ) Employer contribution 11,045 6,401 Benefits paid (6,658 ) (8,162 ) Fair value of plan assets at end of year 31,731 25,769 Funded status at end of year $ (37,928 ) $ (36,778 ) The Company’s underfunded status for the Pension Plans as of December 31, 2016 , and 2015 , is $37.9 million and $36.8 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, 2016 . 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, 2016 2015 (in thousands) Projected benefit obligation $ 69,659 $ 62,547 Accumulated benefit obligation $ 54,681 $ 46,439 Less: Fair value of plan assets (31,731 ) (25,769 ) Underfunded accumulated benefit obligation $ 22,950 $ 20,670 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. Pre-tax amounts not yet recognized in net periodic pension costs, but rather recognized in accumulated other comprehensive loss during 2016 , 2015 , and 2014 , were as follows: For the Years Ended December 31, 2016 2015 2014 (in thousands) Unrecognized actuarial losses $ 22,708 $ 20,966 $ 17,812 Unrecognized prior service costs 83 101 118 Unrecognized transition obligation — — — Accumulated other comprehensive loss $ 22,791 $ 21,067 $ 17,930 The estimated net loss that will be amortized from accumulated other comprehensive loss into net periodic benefit cost over the next fiscal year is $1.6 million . Pre-tax changes recognized in other comprehensive loss during 2016 , 2015 , and 2014 , were as follows: For the Years Ended December 31, 2016 2015 2014 (in thousands) Net actuarial loss $ (3,322 ) $ (4,990 ) $ (10,062 ) Prior service cost — — — Less: Amortization of prior service cost (16 ) (17 ) (17 ) Amortization of net actuarial loss (1,582 ) (1,486 ) (689 ) Settlements — (350 ) — Total other comprehensive loss $ (1,724 ) $ (3,137 ) $ (9,356 ) Components of Net Periodic Benefit Cost for the Pension Plans For the Years Ended December 31, 2016 2015 2014 (in thousands) Components of net periodic benefit cost: Service cost $ 8,200 $ 7,949 $ 6,335 Interest cost 2,908 2,496 2,191 Expected return on plan assets that reduces periodic pension cost (2,235 ) (2,182 ) (1,978 ) Amortization of prior service cost 16 17 17 Amortization of net actuarial loss 1,582 1,486 689 Settlements — 350 — Net periodic benefit cost $ 10,471 $ 10,116 $ 7,254 Pension Plan Assumptions Weighted-average assumptions used to measure the Company’s projected benefit obligation and net periodic benefit cost are as follows: As of December 31, 2016 2015 2014 Projected benefit obligation Discount rate 4.2% 4.7% 4.3% Rate of compensation increase 6.2% 6.2% 6.2% Net periodic benefit cost Discount rate 4.7% 4.3% 5.0% Expected return on plan assets (1) 7.5% 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 does not permit 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 2017 2016 2015 Equity securities 35.0 % 28.8 % 39.1 % Fixed income securities 43.0 % 35.5 % 34.0 % Other securities 22.0 % 35.7 % 26.9 % Total 100.0 % 100.0 % 100.0 % There is no asset allocation of the Nonqualified Pension Plan since there are no plan assets in that plan. An expected return on plan assets of 7.5 percent was used to calculate the Company’s obligation under the Qualified Pension Plan for 2016 and 2015 . Factors considered in determining the expected rate of return include the long-term historical rate of return provided by the equity and debt securities markets and input from the investment consultants and trustees managing the plan assets. The difference in investment income using the projected rate of return compared to the actual rates of return for the past two years was not material and is not expected to have a material effect on the accompanying statements of operations or cash flows from operating activities in future years. Pension Plan Assets The fair values of the Company’s Qualified Pension Plan assets as of December 31, 2016 , and 2015 , utilizing the fair value hierarchy discussed in Note 11 – Fair Value Measurements are as follows: Fair Value Measurements Using: Actual Asset Allocation Total Level 1 Inputs Level 2 Inputs Level 3 Inputs (in thousands) As of December 31, 2016 Cash — % $ — $ — $ — $ — Equity Securities: Domestic (1) 18.7 % 5,945 4,471 1,474 — International (2) 10.1 % 3,192 3,192 — — Total Equity Securities 28.8 % 9,137 7,663 1,474 — Fixed Income Securities: High-Yield Bonds (3) 2.6 % 822 822 — — Core Fixed Income (4) 25.0 % 7,923 7,923 — — Floating Rate Corp Loans (5) 7.9 % 2,495 2,495 — — Total Fixed Income Securities 35.5 % 11,240 11,240 — — Other Securities: Commodities (6) 1.8 % 578 578 — — Real Estate (7) 5.1 % 1,629 — — 1,629 Collective Investment Trusts (8) 17.5 % 5,562 — 5,562 — Hedge Fund (9) 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 As of December 31, 2015 Cash — % $ — $ — $ — $ — Equity Securities: Domestic (1) 26.1 % 6,729 4,943 1,786 — International (2) 13.0 % 3,353 3,353 — — Total Equity Securities 39.1 % 10,082 8,296 1,786 — Fixed Income Securities: High-Yield Bonds (3) 2.8 % 722 722 — — Core Fixed Income (4) 22.5 % 5,789 5,789 — — Floating Rate Corp Loans (5) 8.7 % 2,247 2,247 — — Total Fixed Income Securities 34.0 % 8,758 8,758 — — Other Securities: Commodities (6) 2.7 % 700 700 — — Real Estate (7) 5.8 % 1,499 — — 1,499 Collective Investment Trusts (8) 4.6 % 1,184 — 1,184 — Hedge Fund (9) 13.8 % 3,546 — — 3,546 Total Other Securities 26.9 % 6,929 700 1,184 5,045 Total Investments 100.0 % $ 25,769 $ 17,754 $ 2,970 $ 5,045 ____________________________________________ (1) 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. (2) 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. (3) 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. (4) The objective of core fixed income funds is to achieve value added from sector or issue selection by constructing a portfolio to approximate the investment results of the Barclay’s Capital Aggregate Bond Index with a modest amount of variability in duration around the index. (5) Investments consist of floating rate bank loans. The interest rates on these loans are typically reset on a periodic basis to account for changes in the level of interest rates. (6) Investments with exposure to commodity price movements, primarily through the use of futures, swaps and other commodity-linked securities. (7) 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. (8) 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. (9) 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, 2015 $ 4,864 Purchases — Realized gain on assets 165 Unrealized gain on assets 16 Balance at December 31, 2015 $ 5,045 Purchases 561 Realized gain on assets 54 Unrealized gain on assets 115 Disposition (561 ) Balance at December 31, 2016 $ 5,214 Contributions The Company contributed $11.0 million , $6.4 million , and $5.3 million to the Pension Plans in the years ended December 31, 2016 , 2015 , and 2014 , respectively. The Company expects to make a $7.8 million contribution to the Pension Plans in 2017 . Benefit Payments The Pension Plans made actual benefit payments of $6.7 million , $8.2 million , and $2.8 million in the years ended December 31, 2016 , 2015 , and 2014 , respectively. Expected benefit payments over the next 10 years are as follows: Years Ending December 31, (in thousands) 2017 $ 6,532 2018 $ 3,256 2019 $ 4,480 2020 $ 4,778 2021 $ 5,772 2022 through 2026 $ 38,708

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 (in thousands) Beginning asset retirement obligation $ 140,874 $ 122,124 Liabilities incurred (1) 21,293 14,471 Liabilities settled (2) (57,100 ) (24,781 ) Accretion expense 7,795 5,091 Revision to estimated cash flows 10,445 23,969 Ending asset retirement obligation (3)(4) $ 123,307 $ 140,874 ____________________________________________ (1) Reflects liabilities incurred through drilling activities and acquisitions of drilled wells. (2) Reflects liabilities settled through plugging and abandonment activities and divestitures of properties. (3) Balance as of December 31, 2016, included $26.2 million of asset retirement obligations associated with oil and gas properties held for sale, specifically the Company’s outside-operated Eagle Ford shale assets. There were no material asset retirement obligations related to assets held for sale as of December 31, 2015. (4) Balances as of December 31, 2016 , and 2015 , included $932,000 and $3.3 million , 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, 2016
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, 2016, 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 derivative contracts consist of swap and collar arrangements for oil, 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, 2016 , the Company had commodity derivative contracts outstanding through the second quarter of 2020 for a total of 11.3 million Bbls of oil production, 137.2 million MMBtu of net gas production, and 13.4 million Bbls of NGL production, as summarized in the tables below. Oil Swaps Contract Period NYMEX WTI Volumes Weighted- Average Contract Price (MBbls) (per Bbl) First quarter 2017 1,574 $ 46.41 Second quarter 2017 1,444 $ 46.44 Third quarter 2017 1,340 $ 46.66 Fourth quarter 2017 1,254 $ 46.35 Total 5,612 Oil Collars Contract Period NYMEX WTI Volumes Weighted- Average Floor Price Weighted- Average Ceiling Price (MBbls) (per Bbl) (per Bbl) First quarter 2017 704 $ 45.00 $ 54.17 Second quarter 2017 636 $ 45.00 $ 54.10 Third quarter 2017 583 $ 45.00 $ 54.05 Fourth quarter 2017 540 $ 45.00 $ 54.01 2018 2,312 $ 50.00 $ 59.24 2019 943 $ 50.00 $ 61.15 Total 5,718 Natural Gas Swaps Contract Period Sold Volumes Weighted- Average Contract Price Purchased Volumes (1) Weighted- Average Contract Price Net Volumes (BBtu) (per MMBtu) (BBtu) (per MMBtu) (BBtu) First quarter 2017 29,420 $ 3.76 — $ — 29,420 Second quarter 2017 26,205 $ 3.98 — $ — 26,205 Third quarter 2017 23,657 $ 4.01 — $ — 23,657 Fourth quarter 2017 22,001 $ 3.98 — $ — 22,001 2018 63,166 $ 3.68 (30,606 ) $ 4.27 32,560 2019 27,743 $ 4.20 (24,415 ) $ 4.34 3,328 Total (2) 192,192 (55,021 ) 137,171 ____________________________________________ (1) During 2016, the Company restructured certain of its gas derivative contracts by buying fixed price volumes to offset existing 2018 and 2019 fixed price swap contracts totaling 55.0 million MMBtu. The Company then entered into new 2017 fixed price swap contracts totaling 38.6 million MMBtu with a contract price of $4.43 per MMBtu. No cash or other consideration was included as part of the restructuring. (2) Total net volumes of natural gas swaps are comprised of IF El Paso Permian ( 3% ), IF HSC ( 94% ), and IF NNG Ventura ( 3% ). 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 (MBbls) (per Bbl) (MBbls) (per Bbl) (MBbls) (per Bbl) (MBbls) (per Bbl) (MBbls) (per Bbl) First quarter 2017 847 $ 8.63 692 $ 21.90 122 $ 30.69 94 $ 31.12 156 $ 47.54 Second quarter 2017 787 $ 8.86 634 $ 21.90 112 $ 30.69 86 $ 31.12 143 $ 47.56 Third quarter 2017 736 $ 9.14 588 $ 21.91 104 $ 30.70 80 $ 31.12 133 $ 47.59 Fourth quarter 2017 692 $ 9.10 550 $ 21.91 98 $ 30.70 74 $ 31.12 124 $ 47.61 2018 2,434 $ 10.18 1,442 $ 22.86 — $ — — $ — — $ — 2019 2,176 $ 11.95 — $ — — $ — — $ — — $ — 2020 539 $ 11.13 — $ — — $ — — $ — — $ — Total 8,211 3,906 436 334 556 Commodity Derivative Contracts Entered Into After December 31, 2016 Subsequent to December 31, 2016, and pursuant to a definitive agreement, the Company entered into certain NYMEX swap contracts on behalf of the buyer of its outside-operated Eagle Ford shale assets, which will be novated to the buyer at closing expected to occur in the first quarter of 2017. Please refer to Note 3 – Acquisitions, Divestitures, and Assets Held for Sale . Additionally, subsequent to December 31, 2016, the Company entered into various derivative contracts, as summarized below: • derivative costless collar contracts through the fourth quarter of 2019 for a total of 2.7 million Bbls of oil production with contract floor prices of $50.00 per Bbl and contract ceiling prices ranging from $57.00 per Bbl to $58.40 per Bbl; • derivative fixed price Midland-Cushing basis swap contracts through the fourth quarter of 2019 for a total of 3.7 million Bbls of oil production at contract prices ranging from ($1.23) per Bbl to ($1.45) per Bbl; and • derivative fixed price swap contracts through the first quarter of 2018 for a total of 1.1 million Bbls of NGL production at contract prices ranging from $35.07 per Bbl to $49.88 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 fair value of the commodity derivative contracts was a net liability of $91.7 million at December 31, 2016 , and net asset of $488.4 million at December 31, 2015 . The following tables detail the fair value of derivatives recorded in the accompanying balance sheets, by category: 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 Derivatives not designated as hedging instruments $ 122,096 $ 213,804 As of December 31, 2015 Derivative Assets Derivative Liabilities Balance Sheet Classification Fair Value Balance Sheet Classification Fair Value (in thousands) Commodity contracts Current assets $ 367,710 Current liabilities $ 8 Commodity contracts Noncurrent assets 120,701 Noncurrent liabilities — Derivatives not designated as hedging instruments $ 488,411 $ 8 Offsetting of Derivative Assets and Liabilities As of December 31, 2016 , and 2015 , all derivative instruments held by the Company were subject to master netting arrangements by 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 2016 2015 2016 2015 (in thousands) Gross amounts presented in the accompanying balance sheets $ 122,096 $ 488,411 $ (213,804 ) $ (8 ) Amounts not offset in the accompanying balance sheets (118,080 ) (8 ) 118,080 8 Net amounts $ 4,016 $ 488,403 $ (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 loss. The Company had no derivatives designated as hedging instruments for the years ended December 31, 2016 , 2015 , and 2014 . 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, 2016 2015 2014 (in thousands) Derivative settlement (gain) loss: Oil contracts $ (243,102 ) $ (362,219 ) $ (28,410 ) Gas contracts (1) (94,936 ) (123,180 ) 26,706 NGL contracts 8,560 (27,167 ) (10,911 ) Total derivative settlement gain $ (329,478 ) $ (512,566 ) $ (12,615 ) Total derivative (gain) loss: Oil contracts $ 85,370 $ (191,165 ) $ (457,082 ) Gas contracts 81,060 (189,734 ) (93,267 ) NGL contracts 84,203 (27,932 ) (32,915 ) Total net derivative (gain) loss $ 250,633 $ (408,831 ) $ (583,264 ) ____________________________________________ (1) Natural gas derivative settlements for the years ended December 31, 2015, and 2014, include $15.3 million and $5.6 million , respectively, 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, 2016, and through the filing date 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, 2016
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, 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 $ — Net Profits Plan (1) $ — $ — $ 411 ____________________________________________ (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. 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, 2015 : Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 488,411 $ — Total property and equipment, net (2) $ — $ — $ 124,813 Liabilities: Derivatives (1) $ — $ 8 $ — Net Profits Plan (1) $ — $ — $ 7,611 ____________________________________________ (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 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 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 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 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, 2016 , and 2015 . 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 Mont Belvieu pricing, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. The following table presents impairment of proved properties expense recorded for the periods presented: For the Years Ended December 31, 2016 2015 2014 (in millions) Impairment of proved properties $ 354.6 $ 468.7 $ 84.5 Impairments of proved properties during 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. Impairments of proved properties during the year ended December 31, 2015 , were due to the decline in expected reserve cash flows driven by commodity price declines and were 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. Impairments of proved properties during the year ended December 31, 2014, resulted from the significant decline in commodity prices in late 2014 and recognition of the outcomes of exploration and delineation wells in certain prospects in the Company’s South Texas & Gulf Coast and Permian regions. Unproved oil and gas properties . Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. To measure the fair value of unproved properties, the Company uses a market approach, which takes into account the following significant assumptions: remaining lease terms, future development plans, risk weighted potential resource recovery, estimated reserve values, and estimated acreage value based on price(s) received for similar, recent acreage transactions by the Company or other market participants. The following table presents abandonment and impairment of unproved properties expense recorded for the periods presented: For the Years Ended December 31, 2016 2015 2014 (in millions) Abandonment and impairment of unproved properties $ 80.4 $ 78.6 $ 75.6 Abandonment and impairment of unproved properties during the year ended December 31, 2016, 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 recent third-party acreage transactions. In all other periods, 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 2016 or 2014. 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 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, 2016 , or 2015 , as the carrying values were below the estimated fair values less costs to sell. Please refer to Note 3 – Acquisitions, Divestitures, and Assets Held for Sale 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. The Rock Oil Acquisition closed on October 4, 2016, and therefore, was not recorded at fair value as of December 31. 2016. 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 – Acquisitions, Divestitures, and Assets Held for Sale for additional discussion. Net Profits Plan The Net Profits Plan is a liability for which there is no available market price, principal market, or market participants. The inputs available for this instrument are unobservable and are therefore classified as Level 3 inputs. The Company employs the income valuation technique, which converts expected future cash flow amounts to a single present value amount. The estimate is highly dependent on commodity prices, cost assumptions, discount rates, and overall market conditions. Due to divestitures of assets subject to the Net Profits Plan in recent years, the liability has been significantly reduced and is no longer considered a significant accounting estimate. The Net Profits Plan liability is included in the other noncurrent liabilities line on the accompanying balance sheets. The following table reflects the activity for the Company’s Net Profits Plan liability measured at fair value using Level 3 inputs: For the Years Ended December 31, 2016 2015 2014 (in thousands) Beginning balance $ 7,611 $ 27,136 $ 56,985 Net increase (decrease) in liability (1) 23,757 (12,238 ) (12,492 ) Net settlements (1) (2) (30,957 ) (7,287 ) (17,357 ) Transfers in (out) of Level 3 — — — Ending balance $ 411 $ 7,611 $ 27,136 ____________________________________________ (1) Net changes in the Company’s Net Profits Plan liability are shown in the change in Net Profits Plan liability line item of the accompanying statements of operations. (2) Settlements represent cash payments made or accrued under the Net Profits Plan and are recognized as compensation expense or a reduction to the net gain on divestiture activity line in the accompanying statements of operations, as discussed in Note 7 – Compensation Plans. 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, 2016 , or 2015 , 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, 2016 2015 Principal Amount Fair Value Principal Amount Fair Value (in thousands) 6.50% Senior Notes due 2021 $ 346,955 $ 354,546 $ 350,000 $ 262,938 6.125% Senior Notes due 2022 $ 561,796 $ 570,925 $ 600,000 $ 440,250 6.50% Senior Notes due 2023 $ 394,985 $ 403,134 $ 400,000 $ 296,000 5.0% Senior Notes due 2024 $ 500,000 $ 475,975 $ 500,000 $ 334,065 5.625% Senior Notes due 2025 $ 500,000 $ 485,000 $ 500,000 $ 326,875 6.75% Senior Notes due 2026 $ 500,000 $ 516,565 $ — $ — 1.50% Senior Convertible Notes due 2021 $ 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.

Acquisition and Development Agr

Acquisition and Development Agreement and Carry and Earning Agreement	12 Months Ended
	Dec. 31, 2016
Acquisition and Development Agreement and Carry and Earning Agreement [Abstract]
Acquisition and Development Agreement and Carry and Earning Agreement	Note 12 - Acquisition and Development Agreement In June 2011, the Company entered into an Acquisition and Development Agreement with Mitsui E&P Texas LP (“Mitsui” and the “Acquisition and Development Agreement”). Pursuant to the Acquisition and Development Agreement, the Company agreed to transfer to Mitsui a 12.5 percent working interest in certain outside-operated oil and gas assets representing approximately 39,000 net acres in Dimmit, LaSalle, Maverick, and Webb Counties, Texas. As consideration for the oil and gas interests transferred, Mitsui agreed to pay, or carry, 90 percent of certain drilling and completion costs attributable to the Company’s remaining interest in these assets until Mitsui expended an aggregate $680.0 million on behalf of the Company. The Acquisition and Development Agreement also provided for reimbursement of capital expenditures and other costs, net of revenues, paid by the Company that were attributable to the transferred interest during the period between the effective date and the closing date, which the parties agreed would be applied over the carry period to cover the Company’s remaining 10 percent of drilling and completion costs for the affected acreage. During the second quarter of 2014, the remainder of the carry under the Acquisition and Development Agreement was expended.

Suspended Well Costs

Suspended Well Costs	12 Months Ended
	Dec. 31, 2016
Suspended Well Costs [Abstract]
Suspended Well Costs Disclosure [Text Block]	Note 13 - Suspended Well Costs The following table reflects the net changes in capitalized exploratory well costs during 2016 , 2015 , and 2014 . 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, 2016 2015 2014 (in thousands) Beginning balance on January 1, $ 11,952 $ 43,589 $ 34,527 Additions to capitalized exploratory well costs pending the determination of proved reserves 19,846 11,952 43,589 Divestitures — (809 ) — Reclassifications to wells, facilities, and equipment based on the determination of proved reserves (11,952 ) (18,485 ) (33,340 ) Capitalized exploratory well costs charged to expense — (24,295 ) (1,187 ) Ending balance at December 31, $ 19,846 $ 11,952 $ 43,589 As of December 31, 2016 , there were no exploratory well costs that were capitalized for more than one year.

Exit and Disposal Costs

Exit and Disposal Costs	12 Months Ended
	Dec. 31, 2016
Restructuring and Related Activities [Abstract]
Restructuring and Related Activities Disclosure [Text Block]	Note 14 - Exit and Disposal Costs 2016 Activity . In the third quarter of 2016, the Company conducted a company-wide reduction in workforce and in the fourth quarter of 2016, the Company closed its Billings, Montana regional office and relocated certain employees to the Company’s corporate office in Denver, Colorado or other Company offices. This decision was made in an effort to reduce future costs and better position the Company for efficient growth in response to prolonged commodity price weakness. The Company expects to incur approximately $7.6 million of total exit and disposal costs related to termination benefits, relocation of certain employees, and other related matters, excluding lease expenses discussed below, all of which are included in general and administrative expense in the accompanying statements of operations. The Company incurred $5.1 million of exit and disposal costs during the year ended December 31, 2016 , and expects to incur the remaining costs in early 2017. Upon closing the office in Billings, Montana, the Company paid $3.2 million to the lessor to terminate the lease. 2015 Activity . In conjunction with its Mid-Continent divestitures in 2015, the Company closed its Tulsa, Oklahoma regional office and incurred $9.3 million of exit and disposal costs, excluding the lease expenses discussed below, all of which were included in general and administrative expense in the accompanying statements of operations for the year ended December 31, 2015. The Company subsequently subleased its space for a portion of the remaining lease term. As of December 31, 2016, the Company is obligated to pay lease costs of approximately $3.8 million , net of expected income from subleased office space, which will be expensed over the remaining duration of the lease, which expires in 2022.

Equity

Equity	12 Months Ended
	Dec. 31, 2016
Equity [Abstract]
Stockholders' Equity Note Disclosure [Text Block]	Note 15 - 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 on October 4, 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. These 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 - Acquisitions, Divestitures, and Assets Held for Sale for additional discussion.

Summary of Significant Accoun23

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Consolidation, Policy [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, 2016 , through the filing date 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 [Policy Text Block]	Use of Estimates in the Preparation of Financial Statements The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of proved oil and gas reserves, assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of proved oil and gas reserve quantities provide the basis for the calculation of depletion, depreciation, and amortization expense, impairment of proved properties, and asset retirement obligations, each of which represents a significant component of the accompanying consolidated financial statements.
Cash and Cash Equivalents, Policy [Policy Text Block]	Cash and Cash Equivalents The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments.
Receivables, Policy [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 and gas 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 Risk, Credit Risk, Policy [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 crude oil, natural gas, and NGLs are products with well-established markets and numerous purchasers in the Company’s operating regions. The Company had the following major customer and sales to entities under common ownership, which accounted for 10 percent or more of its total oil, natural gas, and NGL production revenue for at least one of the periods presented: For the Years Ended December 31, 2016 2015 2014 Major customer (1) 18 % 21 % 19 % Group #1 of entities under common ownership (2) 15 % 10 % 14 % Group #2 of entities under common ownership (2) 8 % 11 % 9 % ____________________________________________ (1) This major customer is the operator of the Company’s outside-operated Eagle Ford shale program, in which the Company entered into various marketing agreements with during 2013, whereby the Company is subject to certain gathering, transportation, and processing throughput commitments for up to 10 years pursuant to each contract. Because the Company shares with its operator the risk of non-performance by its counterparty purchasers, the Company has included its operator as a major customer in the table above. Several of the operator’s counterparty purchasers under these contracts are also direct purchasers of the Company’s production from other areas. As of December 31, 2016, the Company’s outside-operated Eagle Ford shale assets were classified as held for sale. (2) In the aggregate these groups of entities under common ownership represent more than 10 percent of total production revenue for the period(s) shown, however, none of the entities comprising either group individually represented more than 10 percent of the Company’s 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 date of this report. The Company has accounts in the following locations with a national bank: Denver, Colorado ; Houston, Texas ; Midland, Texas ; and Billings, Montana . The Company’s policy is to invest in highly-rated instruments and to limit the amount of credit exposure at each individual institution.
Full Cost or Successful Efforts, Policy [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, producing 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 Policy [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 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 consolidated statements of operations (“accompanying statements of operations”) for all other sales of proved properties. Unproved properties . Unproved properties consist of costs to acquire undeveloped leases as well as acquisitions of unproved reserves. When successful wells are drilled on undeveloped leaseholds, unproved property costs 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. The partial sale of unproved property is accounted for as a recovery of cost when substantial uncertainty exists as to the ultimate recovery of the cost applicable to the interest retained. A net gain on divestiture activity is recognized to the extent that the sales price exceeds the carrying amount of the unproved property. A net gain or loss on divestiture activity is recognized in the accompanying statements of operations for all other sales of unproved property. 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 consolidated statements of cash flows.
Property, Plant and Equipment, Policy [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 three 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 consolidated balance sheets (“accompanying balance sheets”) at the lower of carrying value or fair value less the cost to sell.
Asset Retirement Obligations, Policy [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 consolidated 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.
Derivatives, Policy [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 [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 natural 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.
Share-based Compensation, Option and Incentive Plans Policy [Policy Text Block]	Stock-Based Compensation At December 31, 2016 , the Company had stock-based employee compensation plans that included RSUs and PSUs issued to employees 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.
Income Tax, Policy [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 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 [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 common shares outstanding for the respective period. The earnings per share calculations reflect the impact of any repurchases of shares of common stock made by the Company. Diluted net income (loss) per common share is calculated by dividing adjusted net income or loss by the diluted weighted-average common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist of unvested RSUs, contingent PSUs, shares issuable upon the conversion of the Senior Convertible Notes, and in-the-money outstanding stock options, which are measured using the treasury stock method. All outstanding stock options were exercised during the year ended December 31, 2014. When the Company recognizes a loss from continuing operations, as was the case for the years ended December 31, 2016 , and 2015 , all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted earnings per share. 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 allows the Company to settle the principal amount of the Senior Convertible Notes in cash and to settle the excess conversion value in shares, as well as cash in lieu of fractional shares. However, the Company reserves the right to settle the Senior Convertible Notes in any manner allowed under the indenture as business conditions warrant. Shares of the Company’s common stock traded at an average closing price below the $40.50 conversion price for the portion of the year ended December 31, 2016, during which the Senior Convertible Notes were outstanding. In connection with the Senior Convertible Notes offering, the Company entered into capped call transactions with affiliates of the underwriters that effectively prevent dilution upon settlement up to the $60.00 cap price. The capped call transactions are not reflected in diluted net income per share, nor will they ever be, as they are anti-dilutive.
Comprehensive Income, Policy [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 [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, 2016 , compared with $202.0 million of outstanding loans as of December 31, 2015 . 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.
Segment Reporting, Policy [Policy Text Block]	Industry Segment and Geographic Information The Company operates in the exploration and production segment of the oil and gas industry within the United States. The Company reports as a single industry segment. Prior to the sale of the Company’s Mid-Continent assets in 2015, the Company acted as the first purchaser of natural gas and natural gas liquids produced by third parties in certain cases. The Company considered this function as ancillary to its oil and gas producing activities. The amount of income these operations generated from marketing gas produced by third parties was not material to the Company’s results of operations, and segmentation of such activity would not have provided a better understanding of the Company’s performance. However, gross revenue and expense related to marketing activities for gas produced by third parties is presented in the marketed gas system revenue and marketed gas system expense line items in the accompanying statements of operations.
Off-Balance-Sheet Credit Exposure, Policy [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 special purpose entities (“SPE”), 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.
New Accounting Pronouncements, Policy [Policy Text Block]	Recently Issued Accounting Standards Effective January 1, 2016, the Company adopted, on a retrospective basis, Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis . This ASU clarifies the consolidation reporting guidance in GAAP. There was no impact to the Company’s financial statements or disclosures from the adoption of this standard. Effective December 31, 2016, the Company adopted FASB ASU No. 2014-15, Presentation of Financial Statements-Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern . This ASU requires management to evaluate whether there are conditions or events that raise substantial doubt about an entity’s ability to continue as a going concern within one year after the date that the entity’s financial statements are issued, or within one year after the date the entity’s financial statements are available to be issued, and to provide disclosures when certain criteria are met. There was no impact to the Company’s financial statements or disclosures from the adoption of this standard. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”) for the recognition of revenue from contracts with customers. Subsequent to the issuance of this ASU, the FASB issued additional related ASUs as follows: • In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date . This ASU deferred the effective date of ASU 2014-09 by one year. • In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net) . This ASU amends the principal versus agent guidance in ASU No. 2014-09. • In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing . This ASU amends the identification of performance obligations and accounting for licenses in ASU 2014-09. • In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients. This ASU amends certain issues in ASU 2014-09 on transition, collectibility, noncash consideration, and the presentation of sales taxes and other similar taxes. • In December 2016, the FASB issued ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers . This ASU is meant to improve and clarify or to correct unintended application of narrow aspects of the guidance in ASU 2014-09. ASU 2014-09 and each update have the same effective date and transition requirements. That is, the guidance under these standards is to be applied using a full retrospective method or a modified retrospective method, as outlined in ASU 2014-09, and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted only for annual periods, and interim periods within those annual periods, beginning after December 15, 2016. The Company has established a cross-functional implementation team that is currently evaluating the provisions of each of these standards, analyzing their impact on the Company’s contract portfolio, reviewing current accounting policies and practices to identify potential differences that would result from applying the requirements of these standards to the Company’s revenue contracts, and assessing their potential impact on the Company’s financial statements and disclosures. The Company currently plans to apply the modified retrospective method upon adoption and plans to adopt the guidance on the effective date of January 1, 2018. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which changes the accounting for leases. This guidance is to be applied using a modified retrospective method and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2018. Early adoption is permitted. The Company is currently evaluating the provisions of this guidance and assessing its potential impact on the Company’s financial statements and disclosures. In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting . This ASU makes targeted amendments to the accounting for employee share-based payments. This guidance is to be applied using various transition methods, such as full retrospective, modified retrospective, and prospective, based on the criteria for the specific amendments as outlined in the guidance. The guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2016. Early adoption is permitted, as long as all of the amendments are adopted in the same period; however, the Company plans on adopting in the first quarter of 2017. The Company is currently evaluating the provisions of this guidance and assessing its potential impact on the Company’s financial statements and disclosures. In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. This ASU is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. This guidance is to be applied using a retrospective method. The guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted, as long as all of the amendments are adopted in the same period. The Company is currently evaluating the provisions of this guidance and assessing its potential impact on the Company’s financial statements and disclosures. In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. This ASU clarifies how entities should present restricted cash and restricted cash equivalents in the statement of cash flows. This guidance is to be applied using a retrospective method and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted. The Company is currently evaluating the provisions of this guidance and assessing its potential impact on the Company’s financial statements and disclosures. In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU 2017-01”). This ASU 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. This guidance is to be applied using a prospective method and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted as outlined in ASU 2017-01. The Company is currently evaluating the provisions of this guidance and assessing its potential impact on the Company’s financial statements and disclosures. 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 . This ASU is meant to clarify the scope of 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. This guidance is to be applied using a full retrospective method or a modified retrospective method as outlined in the guidance and is effective at the same time as ASU 2014-09. Further, the Company is required to adopt this guidance at the same time that it adopts the guidance in ASU 2014-09. The Company is currently evaluating the provisions of this guidance and assessing its potential impact on the Company’s financial statements and disclosures. There are no other accounting standards applicable to the Company that would have a material effect on the Company’s financial statements and disclosures that have been issued but not yet adopted by the Company as of December 31, 2016 , and through the filing date of this report.
Derivatives, Methods of Accounting, Derivatives Not Designated or Qualifying as Hedges [Policy Text Block]	Derivatives The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivatives. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration forward commodity price curves, counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit-price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The 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.
Pension and Other Postretirement Plans, Pensions, Policy [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 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.

Summary of Significant Accoun24

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2016
Basis of Presentation and Significant Accounting Policies [Abstract]
Schedule of Revenue by Major Customers by Reporting Segments [Table Text Block]	The Company had the following major customer and sales to entities under common ownership, which accounted for 10 percent or more of its total oil, natural gas, and NGL production revenue for at least one of the periods presented: For the Years Ended December 31, 2016 2015 2014 Major customer (1) 18 % 21 % 19 % Group #1 of entities under common ownership (2) 15 % 10 % 14 % Group #2 of entities under common ownership (2) 8 % 11 % 9 % ____________________________________________ (1) This major customer is the operator of the Company’s outside-operated Eagle Ford shale program, in which the Company entered into various marketing agreements with during 2013, whereby the Company is subject to certain gathering, transportation, and processing throughput commitments for up to 10 years pursuant to each contract. Because the Company shares with its operator the risk of non-performance by its counterparty purchasers, the Company has included its operator as a major customer in the table above. Several of the operator’s counterparty purchasers under these contracts are also direct purchasers of the Company’s production from other areas. As of December 31, 2016, the Company’s outside-operated Eagle Ford shale assets were classified as held for sale. (2) In the aggregate these groups of entities under common ownership represent more than 10 percent of total production revenue for the period(s) shown, however, none of the entities comprising either group individually represented more than 10 percent of the Company’s production revenue.
Dilutive and Anti-Dilutive Shares for Earnings per Share [Table Text Block]	The following table details the weighted-average dilutive and anti-dilutive securities for the years presented: For the Years Ended December 31, 2016 2015 2014 (in thousands) Dilutive — — 814 Anti-dilutive 280 256 —
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]	The following table sets forth the calculations of basic and diluted earnings per share: For the Years Ended December 31, 2016 2015 2014 (in thousands, except per share amounts) Net income (loss) $ (757,744 ) $ (447,710 ) $ 666,051 Basic weighted-average common shares outstanding 76,568 67,723 67,230 Add: dilutive effect of unvested RSUs, contingent PSUs, and stock options (1) — — 814 Add: dilutive effect of 1.50% Senior Convertible Notes (2) — — — Diluted weighted-average common shares outstanding 76,568 67,723 68,044 Basic net income (loss) per common share $ (9.90 ) $ (6.61 ) $ 9.91 Diluted net income (loss) per common share $ (9.90 ) $ (6.61 ) $ 9.79 ____________________________________________ (1) For the years ended December 31, 2016 , and 2015 , the shares were anti-dilutive and excluded from the calculation of diluted earnings per share. (2) For the year ended December 31, 2016 , shares of the Company’s common stock traded at an average closing price below the $40.50 conversion price, and therefore, had no dilutive impact and were excluded from the calculation of diluted earnings per share.
Comprehensive Income (Loss) [Table Text Block]	The changes in the balances of components comprising other comprehensive income (loss) are presented in the following table: Pension Liability Adjustments (in thousands) For the year ended December 31, 2014 Net actuarial loss $ (10,062 ) Reclassification to earnings 706 Tax benefit 3,460 Loss, net of tax $ (5,896 ) For the year ended December 31, 2015 Net actuarial loss $ (4,990 ) Reclassification to earnings 1,853 Tax benefit 1,047 Loss, net of tax $ (2,090 ) For the year ended December 31, 2016 Net actuarial loss $ (3,322 ) Reclassification to earnings 1,598 Tax benefit 570 Loss, net of tax $ (1,154 )

Accounts Receivable and Accou25

Accounts Receivable and Accounts Payable and Accrued Expenses Accounts Receivable and Accounts Payable and Accrued Expenses (Tables)	12 Months Ended
	Dec. 31, 2016
Accounts Receivable and Accounts Payable and Accrued Expenses [Abstract]
Schedule of Accounts, Notes, Loans and Financing Receivable [Table Text Block]	Accounts receivable are comprised of the following: As of December 31, 2016 2015 (in thousands) Accrued oil, gas, and NGL production revenue $ 96,101 $ 58,256 Amounts due from joint interest owners 29,669 22,269 State severance tax refunds 15,320 12,072 Accrued derivative settlements 6,512 34,579 Other 4,348 6,948 Total accounts receivable $ 151,950 $ 134,124
Schedule of Accounts Payable and Accrued Liabilities [Table Text Block]	Accounts payable and accrued expenses are comprised of the following: As of December 31, 2016 2015 (in thousands) Accrued capital expenditures $ 107,009 $ 97,355 Revenue and severance tax payable 39,617 44,387 Accrued lease operating expense 15,956 21,943 Accrued property taxes 6,606 14,078 Accrued compensation 34,761 41,154 Accrued derivative settlements 6,473 — Accrued interest 45,059 34,378 Other 44,227 49,222 Total accounts payable and accrued expenses $ 299,708 $ 302,517

Acquisitions, Divestitures, a26

Acquisitions, Divestitures, and Assets Held for Sale Fair Value of Acquired Properties (Tables)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]	QStar Acquisition. On December 21, 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”) for $1.6 billion , consisting of $1.2 billion in cash consideration and the issuance of approximately 13.4 million shares of the Company’s common stock. The cash consideration was funded by proceeds from the recent Raven/Bear Den divestiture and the December 2016 equity offering. Please refer to Note 15 - Equity for additional discussion. The effective date of the acquisition was September 1, 2016 . 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 preliminary 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 $ 1,167,373 Fair value of equity consideration (1) 437,194 Total consideration at closing $ 1,604,567 Assets and liabilities acquired: Wells in progress $ 21,812 Proved oil and gas properties 61,614 Unproved oil and gas properties 1,537,923 Total oil and gas properties acquired 1,621,349 Working capital (9,141 ) Asset retirement obligation (7,641 ) Total net assets acquired $ 1,604,567 ____________________________________________ (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 prohibits 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 preliminary 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 $ 991,038 Fair value of assets and liabilities acquired: Wells in progress $ 5,672 Proved oil and gas properties 81,917 Unproved oil and gas properties 913,594 Other assets 5,338 Total fair value of oil and gas properties acquired 1,006,521 Working capital (7,888 ) Asset retirement obligation (7,595 ) Total fair value of net assets acquired $ 991,038	Each of these acquisitions qualified as a business combination under ASC Topic 805, Business Combinations . The Company allocated the final adjusted purchase prices to the acquired assets and liabilities based on fair value as of the respective acquisition dates, as summarized in the table below. These measurements resulted in no goodwill or bargain purchase gain being recognized. Acquisition #1 Acquisition #2 As of September 24, 2014 As of October 15, 2014 (in thousands) Cash consideration $ 321,807 $ 84,836 Fair value of assets and liabilities acquired: Proved oil and gas properties $ 203,467 $ 54,612 Unproved oil and gas properties 126,588 29,610 Total fair value of oil and gas properties acquired 330,055 84,222 Working capital (6,135 ) 2,232 Asset retirement obligation (2,113 ) (1,618 ) Total fair value of net assets acquired $ 321,807 $ 84,836
Disposal Groups, Including Discontinued Operations [Table Text Block]	The following table presents income (loss) before income taxes of the Raven/Bear Den assets sold on December 1, 2016, for the years ended December 31, 2016, 2015, and 2014. This divestiture is considered a disposal of a significant asset group. For the Years Ended December 31, 2016 2015 2014 (in thousands) Income (loss) before income taxes (1) $ (6,601 ) $ (12,530 ) $ 197,256 ____________________________________________ (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 impairment of proved properties expense of approximately $17.8 million for the year ended December 31, 2015. The following table presents income (loss) before income taxes for the years ended December 31, 2016, 2015, and 2014, of the Company’s outside-operated Eagle Ford shale assets held for sale as of December 31, 2016, which is considered a significant asset disposal group. For the Years Ended December 31, 2016 2015 2014 (in thousands) Income (loss) before income taxes (1) $ (218,506 ) $ 71,556 $ 294,376 ____________________________________________ (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 expense. Additionally, loss before income taxes for the year ended December 31, 2016 , includes $269.6 million of proved property impairment expense.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Schedule of componenets of provision for income taxes	The provision for income taxes consists of the following: For the Years Ended December 31, 2016 2015 2014 (in thousands) Current portion of income tax expense Federal $ 2,932 $ — $ — State 1,539 1,571 868 Deferred portion of income tax expense (benefit) (448,643 ) (276,722 ) 397,780 Total income tax expense (benefit) $ (444,172 ) $ (275,151 ) $ 398,648 Effective tax rate 37.0 % 38.1 % 37.4 %
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	The components of the net deferred income tax liabilities are as follows: As of December 31, 2016 2015 (in thousands) Deferred tax liabilities: Oil and gas properties $ 518,394 $ 854,029 Derivative asset — 179,543 Other 7,733 1,233 Total deferred tax liabilities 526,127 1,034,805 Deferred tax assets: Federal and state tax net operating loss carryovers 151,343 244,942 Derivative liability 31,349 — Stock compensation 10,083 14,529 Credit carryover 12,448 6,952 Other liabilities 10,567 20,497 Total deferred tax assets 215,790 286,920 Valuation allowance (5,335 ) (10,394 ) Net deferred tax assets 210,455 276,526 Total net deferred tax liabilities $ 315,672 $ 758,279 Current federal income tax refundable $ 644 $ 5,378 Current state income tax refundable $ — $ 65 Current state income tax payable $ 1,181 $ —
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	Federal income tax expense differs from the amount that would be provided by applying the statutory United States federal income tax rate to income before income taxes primarily due to the effect of state income taxes, changes in valuation allowances, R&D credits, and accumulated impacts of other smaller permanent differences, reported as follows: For the Years Ended December 31, 2016 2015 2014 (in thousands) Federal statutory tax expense (benefit) $ (420,671 ) $ (253,001 ) $ 372,644 Increase (decrease) in tax resulting from: State tax expense (benefit) (net of federal benefit) (17,549 ) (21,583 ) 21,350 Change in valuation allowance (5,059 ) 3,148 2,245 Research and development credit — (1,971 ) — Other (893 ) (1,744 ) 2,409 Income tax expense (benefit) $ (444,172 ) $ (275,151 ) $ 398,648
Schedule of Unrecognized Tax Benefits Roll Forward [Table Text Block]	The total amount recorded for unrecognized tax benefits is presented below: For the Years Ended December 31, 2016 2015 2014 (in thousands) Beginning balance $ 2,782 $ 1,582 $ 2,358 Additions for tax positions of prior years 9 1,200 140 Settlements (2,345 ) — (916 ) Ending balance $ 446 $ 2,782 $ 1,582

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Schedule of Borrowing Base Utilization, 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 Line of Credit Facilities [Table Text Block]	The following table presents the outstanding balance, total amount of letters of credit, and available borrowing capacity under the Credit Agreement as of February 15, 2017 , December 31, 2016 , and December 31, 2015 : As of February 15, 2017 As of December 31, 2016 As of December 31, 2015 (in thousands) Credit facility balance (1) $ 103,500 $ — $ 202,000 Letters of credit (2) 200 200 200 Available borrowing capacity 1,061,300 1,164,800 1,297,800 Total aggregate lender commitment amount $ 1,165,000 $ 1,165,000 $ 1,500,000 ____________________________________________ (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 $5.9 million and $4.9 million as of December 31, 2016 , and 2015 , respectively. (2) Letters of credit reduce the amount available under the credit facility on a dollar-for-dollar basis.
Schedule of Long-term Debt Instruments [Table Text Block]	The Senior Notes, net of unamortized deferred financing costs line on the accompanying balance sheets as of December 31, 2016 , and 2015 , consisted of the following: As of December 31, 2016 2015 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 $ 346,955 $ 3,372 $ 343,583 $ 350,000 $ 4,106 $ 345,894 6.125% Senior Notes due 2022 561,796 6,979 554,817 600,000 8,714 591,286 6.50% Senior Notes due 2023 394,985 4,436 390,549 400,000 5,231 394,769 5.0% Senior Notes due 2024 500,000 6,533 493,467 500,000 7,455 492,545 5.625% Senior Notes due 2025 500,000 7,619 492,381 500,000 8,524 491,476 6.75% Senior Notes due 2026 500,000 8,078 491,922 — — — Total $ 2,803,736 $ 37,017 $ 2,766,719 $ 2,350,000 $ 34,030 $ 2,315,970
Convertible Debt [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, 2016 : As of December 31, 2016 (in thousands) Principal amount of Senior Convertible Notes $ 172,500 Unamortized debt discount (37,513 ) Unamortized deferred financing costs (4,131 ) Net carrying amount $ 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, 2016 : As of December 31, 2016 (in thousands) Equity component due to allocation of proceeds to equity $ 40,217 Less: related issuance costs (1,375 ) Less: deferred tax liability (5,267 ) Net carrying amount $ 33,575

Commitments and Contingencies C

Commitments and Contingencies Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Contractual Obligation, Fiscal Year Maturity Schedule [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 (1) (in thousands) 2017 $ 145,075 2018 148,240 2019 144,379 2020 141,010 2021 141,654 Thereafter 337,745 Total $ 1,058,103 ____________________________________________ (1) During the third quarter of 2015, the Company closed its office in Tulsa, Oklahoma. These amounts include lease payments for the Tulsa office, net of sublease income. The Company expects to receive $2.7 million of total sublease income through 2019 .

Compensation Plans (Tables)

Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 2014 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) 626,328 $ 61.81 433,660 $ 73.63 572,469 $ 66.07 Granted (1) 447,971 $ 26.56 320,753 $ 45.34 202,404 $ 94.66 Vested (1) (130,353 ) $ 64.17 (76,438 ) $ 51.76 (206,830 ) $ 64.79 Forfeited (1) (115,023 ) $ 55.59 (51,647 ) $ 73.62 (134,383 ) $ 86.72 Non-vested at end of year (1) 828,923 $ 43.25 626,328 $ 61.81 433,660 $ 73.63 ____________________________________________ (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 is presented in the table below: For the Years Ended December 31, 2016 2015 2014 Shares of common stock issued to settle PSUs (1) 44,870 288,962 130,163 Less: shares of common stock withheld for income and payroll taxes (14,809 ) (100,683 ) (45,042 ) Net shares of common stock issued 30,061 188,279 85,121 Multiplier earned 0.2 1.0 0.55 ____________________________________________ (1) During the years ended December 31, 2016 , 2015 , and 2014 , the Company issued shares of common stock for PSUs granted in 2013, 2012, and 2011. The Company and the 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 is presented below: For the Years Ended December 31, 2016 2015 2014 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 543,737 $ 55.01 515,724 $ 68.29 580,431 $ 57.05 Granted 417,065 $ 28.08 356,246 $ 43.72 234,560 $ 83.98 Vested (241,363 ) $ 58.06 (278,289 ) $ 63.12 (253,031 ) $ 58.19 Forfeited (115,323 ) $ 43.52 (49,944 ) $ 66.53 (46,236 ) $ 62.06 Non-vested at end of year 604,116 $ 37.39 543,737 $ 55.01 515,724 $ 68.29
Schedule of Shares Settled, Restricted Stock Units [Table Text Block]	A summary of the shares of common stock issued to settle RSUs is presented in the table below: For the Years Ended December 31, 2016 2015 2014 Shares of common stock issued to settle RSUs (1) 241,363 278,289 253,031 Less: shares of common stock withheld for income and payroll taxes (72,181 ) (91,045 ) (81,434 ) Net shares of common stock issued 169,182 187,244 171,597 ____________________________________________ (1) During the years ended December 31, 2016 , 2015 , and 2014 , the Company issued shares of common stock for RSUs granted in previous years. The Company and the 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 stock option grants under prior stock option plans	A summary of activity associated with the Company’s Stock Option Plans during the year ended December 31, 2014, is presented in the following table: Shares Weighted-Average Exercise Price Aggregate Intrinsic Value For the year ended December 31, 2014 Outstanding, start of year 39,088 $ 20.87 $ — Exercised (39,088 ) $ 20.87 $ 1,993,726 Forfeited — $ — $ — Outstanding, end of year — $ — $ — Vested and exercisable at end of year — $ — $ —
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, 2016 2015 2014 Risk free interest rate 0.4 % 0.1 % 0.1 % Dividend yield 0.4 % 0.2 % 0.1 % Volatility factor of the expected market price of the Company’s common stock 95.0 % 61.2 % 33.0 % 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, 2016 2015 2014 (in thousands) Cash payments made or accrued related to operations $ 6,608 $ 3,498 $ 9,016 Cash payments made or accrued related to divestitures 24,349 3,789 8,341 Total net settlements $ 30,957 $ 7,287 $ 17,357
[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, 2016
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]
Schedule of Net Funded Status [Table Text Block]	For the Years Ended December 31, 2016 2015 (in thousands) Change in benefit obligation: Projected benefit obligation at beginning of year $ 62,547 $ 57,867 Service cost 8,200 7,949 Interest cost 2,908 2,496 Actuarial loss 2,662 2,397 Benefits paid (6,658 ) (8,162 ) Projected benefit obligation at end of year 69,659 62,547 Change in plan assets: Fair value of plan assets at beginning of year 25,769 27,940 Actual return on plan assets 1,575 (410 ) Employer contribution 11,045 6,401 Benefits paid (6,658 ) (8,162 ) Fair value of plan assets at end of year 31,731 25,769 Funded status at end of year $ (37,928 ) $ (36,778 )
Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets [Table Text Block]	Accumulated Benefit Obligation in Excess of Plan Assets for the Pension Plans As of December 31, 2016 2015 (in thousands) Projected benefit obligation $ 69,659 $ 62,547 Accumulated benefit obligation $ 54,681 $ 46,439 Less: Fair value of plan assets (31,731 ) (25,769 ) Underfunded accumulated benefit obligation $ 22,950 $ 20,670
Schedule of Net Periodic Benefit Cost Not yet Recognized [Table Text Block]	Pre-tax amounts not yet recognized in net periodic pension costs, but rather recognized in accumulated other comprehensive loss during 2016 , 2015 , and 2014 , were as follows: For the Years Ended December 31, 2016 2015 2014 (in thousands) Unrecognized actuarial losses $ 22,708 $ 20,966 $ 17,812 Unrecognized prior service costs 83 101 118 Unrecognized transition obligation — — — Accumulated other comprehensive loss $ 22,791 $ 21,067 $ 17,930
Schedule of Amounts Recognized in Other Comprehensive Income (Loss) [Table Text Block]	Pre-tax changes recognized in other comprehensive loss during 2016 , 2015 , and 2014 , were as follows: For the Years Ended December 31, 2016 2015 2014 (in thousands) Net actuarial loss $ (3,322 ) $ (4,990 ) $ (10,062 ) Prior service cost — — — Less: Amortization of prior service cost (16 ) (17 ) (17 ) Amortization of net actuarial loss (1,582 ) (1,486 ) (689 ) Settlements — (350 ) — Total other comprehensive loss $ (1,724 ) $ (3,137 ) $ (9,356 )
Components of the net periodic benefit cost for both the Qualified and the Nonqualified Pension Plan	Components of Net Periodic Benefit Cost for the Pension Plans For the Years Ended December 31, 2016 2015 2014 (in thousands) Components of net periodic benefit cost: Service cost $ 8,200 $ 7,949 $ 6,335 Interest cost 2,908 2,496 2,191 Expected return on plan assets that reduces periodic pension cost (2,235 ) (2,182 ) (1,978 ) Amortization of prior service cost 16 17 17 Amortization of net actuarial loss 1,582 1,486 689 Settlements — 350 — Net periodic benefit cost $ 10,471 $ 10,116 $ 7,254
Schedule of Assumptions Used [Table Text Block]	Weighted-average assumptions used to measure the Company’s projected benefit obligation and net periodic benefit cost are as follows: As of December 31, 2016 2015 2014 Projected benefit obligation Discount rate 4.2% 4.7% 4.3% Rate of compensation increase 6.2% 6.2% 6.2% Net periodic benefit cost Discount rate 4.7% 4.3% 5.0% Expected return on plan assets (1) 7.5% 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 Allocation of Plan Assets Summary [Table Text Block]	The weighted-average asset allocation of the Qualified Pension Plan is as follows: Target As of December 31, Asset Category 2017 2016 2015 Equity securities 35.0 % 28.8 % 39.1 % Fixed income securities 43.0 % 35.5 % 34.0 % Other securities 22.0 % 35.7 % 26.9 % Total 100.0 % 100.0 % 100.0 %
Schedule of Allocation of Plan Assets [Table Text Block]	The fair values of the Company’s Qualified Pension Plan assets as of December 31, 2016 , and 2015 , utilizing the fair value hierarchy discussed in Note 11 – Fair Value Measurements are as follows: Fair Value Measurements Using: Actual Asset Allocation Total Level 1 Inputs Level 2 Inputs Level 3 Inputs (in thousands) As of December 31, 2016 Cash — % $ — $ — $ — $ — Equity Securities: Domestic (1) 18.7 % 5,945 4,471 1,474 — International (2) 10.1 % 3,192 3,192 — — Total Equity Securities 28.8 % 9,137 7,663 1,474 — Fixed Income Securities: High-Yield Bonds (3) 2.6 % 822 822 — — Core Fixed Income (4) 25.0 % 7,923 7,923 — — Floating Rate Corp Loans (5) 7.9 % 2,495 2,495 — — Total Fixed Income Securities 35.5 % 11,240 11,240 — — Other Securities: Commodities (6) 1.8 % 578 578 — — Real Estate (7) 5.1 % 1,629 — — 1,629 Collective Investment Trusts (8) 17.5 % 5,562 — 5,562 — Hedge Fund (9) 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 As of December 31, 2015 Cash — % $ — $ — $ — $ — Equity Securities: Domestic (1) 26.1 % 6,729 4,943 1,786 — International (2) 13.0 % 3,353 3,353 — — Total Equity Securities 39.1 % 10,082 8,296 1,786 — Fixed Income Securities: High-Yield Bonds (3) 2.8 % 722 722 — — Core Fixed Income (4) 22.5 % 5,789 5,789 — — Floating Rate Corp Loans (5) 8.7 % 2,247 2,247 — — Total Fixed Income Securities 34.0 % 8,758 8,758 — — Other Securities: Commodities (6) 2.7 % 700 700 — — Real Estate (7) 5.8 % 1,499 — — 1,499 Collective Investment Trusts (8) 4.6 % 1,184 — 1,184 — Hedge Fund (9) 13.8 % 3,546 — — 3,546 Total Other Securities 26.9 % 6,929 700 1,184 5,045 Total Investments 100.0 % $ 25,769 $ 17,754 $ 2,970 $ 5,045 ____________________________________________ (1) 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. (2) 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. (3) 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. (4) The objective of core fixed income funds is to achieve value added from sector or issue selection by constructing a portfolio to approximate the investment results of the Barclay’s Capital Aggregate Bond Index with a modest amount of variability in duration around the index. (5) Investments consist of floating rate bank loans. The interest rates on these loans are typically reset on a periodic basis to account for changes in the level of interest rates. (6) Investments with exposure to commodity price movements, primarily through the use of futures, swaps and other commodity-linked securities. (7) 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. (8) 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. (9) 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 Effect of Significant Unobservable Inputs, Changes in Plan Assets [Table Text Block]	Included below is a summary of the changes in Level 3 plan assets (in thousands): Balance at January 1, 2015 $ 4,864 Purchases — Realized gain on assets 165 Unrealized gain on assets 16 Balance at December 31, 2015 $ 5,045 Purchases 561 Realized gain on assets 54 Unrealized gain on assets 115 Disposition (561 ) Balance at December 31, 2016 $ 5,214
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) 2017 $ 6,532 2018 $ 3,256 2019 $ 4,480 2020 $ 4,778 2021 $ 5,772 2022 through 2026 $ 38,708

Asset Retirement Obligations Re

Asset Retirement Obligations Reconciliation of Asset Retirement Obligation Liability (Tables)	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation [Abstract]
Schedule of Change in Asset Retirement Obligation [Table Text Block]	A reconciliation of the Company’s total asset retirement obligation liability is as follows: As of December 31, 2016 2015 (in thousands) Beginning asset retirement obligation $ 140,874 $ 122,124 Liabilities incurred (1) 21,293 14,471 Liabilities settled (2) (57,100 ) (24,781 ) Accretion expense 7,795 5,091 Revision to estimated cash flows 10,445 23,969 Ending asset retirement obligation (3)(4) $ 123,307 $ 140,874 ____________________________________________ (1) Reflects liabilities incurred through drilling activities and acquisitions of drilled wells. (2) Reflects liabilities settled through plugging and abandonment activities and divestitures of properties. (3) Balance as of December 31, 2016, included $26.2 million of asset retirement obligations associated with oil and gas properties held for sale, specifically the Company’s outside-operated Eagle Ford shale assets. There were no material asset retirement obligations related to assets held for sale as of December 31, 2015. (4) Balances as of December 31, 2016 , and 2015 , included $932,000 and $3.3 million , 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 Instrume33

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2016
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 (MBbls) (per Bbl) First quarter 2017 1,574 $ 46.41 Second quarter 2017 1,444 $ 46.44 Third quarter 2017 1,340 $ 46.66 Fourth quarter 2017 1,254 $ 46.35 Total 5,612 Oil Collars Contract Period NYMEX WTI Volumes Weighted- Average Floor Price Weighted- Average Ceiling Price (MBbls) (per Bbl) (per Bbl) First quarter 2017 704 $ 45.00 $ 54.17 Second quarter 2017 636 $ 45.00 $ 54.10 Third quarter 2017 583 $ 45.00 $ 54.05 Fourth quarter 2017 540 $ 45.00 $ 54.01 2018 2,312 $ 50.00 $ 59.24 2019 943 $ 50.00 $ 61.15 Total 5,718 Natural Gas Swaps Contract Period Sold Volumes Weighted- Average Contract Price Purchased Volumes (1) Weighted- Average Contract Price Net Volumes (BBtu) (per MMBtu) (BBtu) (per MMBtu) (BBtu) First quarter 2017 29,420 $ 3.76 — $ — 29,420 Second quarter 2017 26,205 $ 3.98 — $ — 26,205 Third quarter 2017 23,657 $ 4.01 — $ — 23,657 Fourth quarter 2017 22,001 $ 3.98 — $ — 22,001 2018 63,166 $ 3.68 (30,606 ) $ 4.27 32,560 2019 27,743 $ 4.20 (24,415 ) $ 4.34 3,328 Total (2) 192,192 (55,021 ) 137,171 ____________________________________________ (1) During 2016, the Company restructured certain of its gas derivative contracts by buying fixed price volumes to offset existing 2018 and 2019 fixed price swap contracts totaling 55.0 million MMBtu. The Company then entered into new 2017 fixed price swap contracts totaling 38.6 million MMBtu with a contract price of $4.43 per MMBtu. No cash or other consideration was included as part of the restructuring. (2) Total net volumes of natural gas swaps are comprised of IF El Paso Permian ( 3% ), IF HSC ( 94% ), and IF NNG Ventura ( 3% ). 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 (MBbls) (per Bbl) (MBbls) (per Bbl) (MBbls) (per Bbl) (MBbls) (per Bbl) (MBbls) (per Bbl) First quarter 2017 847 $ 8.63 692 $ 21.90 122 $ 30.69 94 $ 31.12 156 $ 47.54 Second quarter 2017 787 $ 8.86 634 $ 21.90 112 $ 30.69 86 $ 31.12 143 $ 47.56 Third quarter 2017 736 $ 9.14 588 $ 21.91 104 $ 30.70 80 $ 31.12 133 $ 47.59 Fourth quarter 2017 692 $ 9.10 550 $ 21.91 98 $ 30.70 74 $ 31.12 124 $ 47.61 2018 2,434 $ 10.18 1,442 $ 22.86 — $ — — $ — — $ — 2019 2,176 $ 11.95 — $ — — $ — — $ — — $ — 2020 539 $ 11.13 — $ — — $ — — $ — — $ — Total 8,211 3,906 436 334 556
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, 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 Derivatives not designated as hedging instruments $ 122,096 $ 213,804 As of December 31, 2015 Derivative Assets Derivative Liabilities Balance Sheet Classification Fair Value Balance Sheet Classification Fair Value (in thousands) Commodity contracts Current assets $ 367,710 Current liabilities $ 8 Commodity contracts Noncurrent assets 120,701 Noncurrent liabilities — Derivatives not designated as hedging instruments $ 488,411 $ 8
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 2016 2015 2016 2015 (in thousands) Gross amounts presented in the accompanying balance sheets $ 122,096 $ 488,411 $ (213,804 ) $ (8 ) Amounts not offset in the accompanying balance sheets (118,080 ) (8 ) 118,080 8 Net amounts $ 4,016 $ 488,403 $ (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, 2016 2015 2014 (in thousands) Derivative settlement (gain) loss: Oil contracts $ (243,102 ) $ (362,219 ) $ (28,410 ) Gas contracts (1) (94,936 ) (123,180 ) 26,706 NGL contracts 8,560 (27,167 ) (10,911 ) Total derivative settlement gain $ (329,478 ) $ (512,566 ) $ (12,615 ) Total derivative (gain) loss: Oil contracts $ 85,370 $ (191,165 ) $ (457,082 ) Gas contracts 81,060 (189,734 ) (93,267 ) NGL contracts 84,203 (27,932 ) (32,915 ) Total net derivative (gain) loss $ 250,633 $ (408,831 ) $ (583,264 ) ____________________________________________ (1) Natural gas derivative settlements for the years ended December 31, 2015, and 2014, include $15.3 million and $5.6 million , respectively, 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, 2016
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, 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 $ — Net Profits Plan (1) $ — $ — $ 411 ____________________________________________ (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. 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, 2015 : Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 488,411 $ — Total property and equipment, net (2) $ — $ — $ 124,813 Liabilities: Derivatives (1) $ — $ 8 $ — Net Profits Plan (1) $ — $ — $ 7,611 ____________________________________________ (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],[4]
Impairment Of Proved Properties [Table Text Block]	The following table presents impairment of proved properties expense recorded for the periods presented: For the Years Ended December 31, 2016 2015 2014 (in millions) Impairment of proved properties $ 354.6 $ 468.7 $ 84.5
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, 2016 2015 2014 (in millions) Abandonment and impairment of unproved properties $ 80.4 $ 78.6 $ 75.6
Schedule of reconciliation of fair value measurements using Level 3 inputs	The following table reflects the activity for the Company’s Net Profits Plan liability measured at fair value using Level 3 inputs: For the Years Ended December 31, 2016 2015 2014 (in thousands) Beginning balance $ 7,611 $ 27,136 $ 56,985 Net increase (decrease) in liability (1) 23,757 (12,238 ) (12,492 ) Net settlements (1) (2) (30,957 ) (7,287 ) (17,357 ) Transfers in (out) of Level 3 — — — Ending balance $ 411 $ 7,611 $ 27,136 ____________________________________________ (1) Net changes in the Company’s Net Profits Plan liability are shown in the change in Net Profits Plan liability line item of the accompanying statements of operations. (2) Settlements represent cash payments made or accrued under the Net Profits Plan and are recognized as compensation expense or a reduction to the net gain on divestiture activity line in the accompanying statements of operations, as discussed in Note 7 – Compensation Plans.
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, 2016 , or 2015 , 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, 2016 2015 Principal Amount Fair Value Principal Amount Fair Value (in thousands) 6.50% Senior Notes due 2021 $ 346,955 $ 354,546 $ 350,000 $ 262,938 6.125% Senior Notes due 2022 $ 561,796 $ 570,925 $ 600,000 $ 440,250 6.50% Senior Notes due 2023 $ 394,985 $ 403,134 $ 400,000 $ 296,000 5.0% Senior Notes due 2024 $ 500,000 $ 475,975 $ 500,000 $ 334,065 5.625% Senior Notes due 2025 $ 500,000 $ 485,000 $ 500,000 $ 326,875 6.75% Senior Notes due 2026 $ 500,000 $ 516,565 $ — $ — 1.50% Senior Convertible Notes due 2021 $ 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.
[4]	This represents a non-financial asset that is measured at fair value on a nonrecurring basis.

Suspended Well Costs Suspended

Suspended Well Costs Suspended Well Costs (Tables)	12 Months Ended
	Dec. 31, 2016
Suspended Well Costs [Abstract]
Capitalized Exploratory Well Costs, Roll Forward [Table Text Block]	The following table reflects the net changes in capitalized exploratory well costs during 2016 , 2015 , and 2014 . 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, 2016 2015 2014 (in thousands) Beginning balance on January 1, $ 11,952 $ 43,589 $ 34,527 Additions to capitalized exploratory well costs pending the determination of proved reserves 19,846 11,952 43,589 Divestitures — (809 ) — Reclassifications to wells, facilities, and equipment based on the determination of proved reserves (11,952 ) (18,485 ) (33,340 ) Capitalized exploratory well costs charged to expense — (24,295 ) (1,187 ) Ending balance at December 31, $ 19,846 $ 11,952 $ 43,589

Summary of Significant Accoun36

Summary of Significant Accounting Policies Other (Details) $ in Thousands		12 Months Ended
		Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Accounts Receivable Additional Disclosures [Abstract]
Receivables Collection Period		2 months
Allowance for Doubtful Accounts Receivable		$ 1,700	$ 1,100
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
Revenues [Abstract]
Revenue Receipt, Days After Sale, Low End of Range		30 days
Revenue Receipt, Days After Sale, High End of Range		90 days
Income Statement [Abstract]
Marketed gas system revenue		$ 0	9,485	$ 24,897
Marketed gas system expense		$ 0	$ 13,922	$ 24,460
Customer Concentration Risk [Member] | Oil And Gas Sales Revenue [Member] | Major Customer One [Member]
Concentration of Credit Risk and Major Customers [Abstract]
Entity-Wide Revenue, Major Customer, Percentage	[1]	18.00%	21.00%	19.00%
Customer Concentration Risk [Member] | Oil And Gas Sales Revenue [Member] | Unnamed Major Customer One with Related Entities [Member]
Concentration of Credit Risk and Major Customers [Abstract]
Entity-Wide Revenue, Major Customer, Percentage	[2]	15.00%	10.00%	14.00%
Customer Concentration Risk [Member] | Oil And Gas Sales Revenue [Member] | Unnamed Major Customer Two with Related Entities [Member]
Concentration of Credit Risk and Major Customers [Abstract]
Entity-Wide Revenue, Major Customer, Percentage	[2]	8.00%	11.00%	9.00%
Minimum [Member]
Asset Retirement Obligation [Abstract]
Fair Value Assumptions, Risk Free Interest Rate		5.50%
Maximum [Member]
Asset Retirement Obligation [Abstract]
Fair Value Assumptions, Risk Free Interest Rate		12.00%
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
Property, Plant and Equipment, Other Types [Member] | Maximum [Member]
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment, Estimated Useful Lives		30
Revolving Credit Facility [Member] | Line of Credit [Member]
Line of Credit Facility [Abstract]
Revolving credit facility	[3]	$ 0	$ 202,000
[1]	This major customer is the operator of the Company’s outside-operated Eagle Ford shale program, in which the Company entered into various marketing agreements with during 2013, whereby the Company is subject to certain gathering, transportation, and processing throughput commitments for up to 10 years pursuant to each contract. Because the Company shares with its operator the risk of non-performance by its counterparty purchasers, the Company has included its operator as a major customer in the table above. Several of the operator’s counterparty purchasers under these contracts are also direct purchasers of the Company’s production from other areas. As of December 31, 2016, the Company’s outside-operated Eagle Ford shale assets were classified as held for sale.
[2]	In the aggregate these groups of entities under common ownership represent more than 10 percent of total production revenue for the period(s) shown, however, none of the entities comprising either group individually represented more than 10 percent of the Company’s production revenue.
[3]	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 $5.9 million and $4.9 million as of December 31, 2016, and 2015, respectively.

Summary of Significant Accoun37

Summary of Significant Accounting Policies Earnings Per Share (Details) $ / shares in Units, shares in Thousands, $ in Thousands		12 Months Ended
		Dec. 31, 2016USD ($)$ / sharesshares		Dec. 31, 2015USD ($)$ / sharesshares		Dec. 31, 2014USD ($)$ / sharesshares	Aug. 12, 2016USD ($)
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Capped Call, Cap Price | $ / shares		$ 60
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount		280		256		0
Earnings Per Share Reconciliation [Abstract]
Net Income (loss) | $		$ (757,744)		$ (447,710)		$ 666,051
Weighted Average Number of Shares Outstanding, Basic		76,568		67,723		67,230
Incremental Common Shares Attributable to Share-based Payment Arrangements	[1]	0		0		814
Incremental Common Shares Attributable to Conversion of Debt Securities, Treasury Stock Method		0	[2]	0	[2]	0
Weighted Average Number of Shares Outstanding, Diluted		76,568		67,723		68,044
Basic net income (loss) per common share | $ / shares		$ (9.90)		$ (6.61)		$ 9.91
Diluted net income (loss) per common share | $ / shares		$ (9.90)		$ (6.61)		$ 9.79
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		0.55
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
Convertible Debt [Member] | 1.50% Senior Convertible Notes Due 2021 [Domain]
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Debt Instrument, Face Amount | $		$ 172,500		$ 0			$ 172,500
Debt Instrument, Convertible, Conversion Price | $ / shares		$ 40.50
[1]	For the years ended December 31, 2016, and 2015, the shares were anti-dilutive and excluded from the calculation of diluted earnings per share.
[2]	For the year ended December 31, 2016, shares of the Company’s common stock traded at an average closing price below the $40.50 conversion price, and therefore, had no dilutive impact and were excluded from the calculation of diluted earnings per share.

Summary of Significant Accoun38

Summary of Significant Accounting Policies Other Comprehensive Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Other comprehensive income [Abstract]
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, before Tax	$ (3,322)	$ (4,990)	$ (10,062)
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, before Tax	1,598	1,853	706
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Tax, Portion Attributable to Parent	570	1,047	3,460
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax, Portion Attributable to Parent	$ (1,154)	$ (2,090)	$ (5,896)

Accounts Receivable and Accou39

Accounts Receivable and Accounts Payable and Accrued Expenses Accounts Receivable (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Accounts, Notes, Loans and Financing Receivable
Accounts Receivable, Net, Current	$ 151,950	$ 134,124
Accrued oil, gas, and NGL production revenue [Member]
Accounts, Notes, Loans and Financing Receivable
Accounts Receivable, Net, Current	96,101	58,256
Amounts due From Joint Interest Owners [Member]
Accounts, Notes, Loans and Financing Receivable
Accounts Receivable, Net, Current	29,669	22,269
State severance tax refunds [Member]
Accounts, Notes, Loans and Financing Receivable
Accounts Receivable, Net, Current	15,320	12,072
Accrued derivative settlements [Member]
Accounts, Notes, Loans and Financing Receivable
Accounts Receivable, Net, Current	6,512	34,579
Other [Member]
Accounts, Notes, Loans and Financing Receivable
Accounts Receivable, Net, Current	$ 4,348	$ 6,948

Accounts Receivable and Accou40

Accounts Receivable and Accounts Payable and Accrued Expenses Accounts Payable and Accrued Expenses (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Accounts Payable and Accrued Liabilities, Current [Abstract]
Capital Expenditures Incurred but Not yet Paid - Instant	$ 107,009	$ 97,355
Accrued Revenue And Severance Tax Payable	39,617	44,387
Accrued Lease Operating Expense	15,956	21,943
Accrual for Taxes Other than Income Taxes, Current	6,606	14,078
Employee-related Liabilities, Current	34,761	41,154
Derivative Settlement Payable	6,473	0
Interest Payable, Current	45,059	34,378
Other Accrued Liabilities, Current	44,227	49,222
Accounts payable and accrued expenses	$ 299,708	$ 302,517

Acquisitions (Details)

Acquisitions (Details) $ / shares in Units, $ in Thousands, shares in Millions		Dec. 21, 2016USD ($)shares	Oct. 04, 2016USD ($)	Oct. 15, 2014USD ($)	Sep. 24, 2014USD ($)a	Dec. 31, 2016USD ($)a$ / shares	Dec. 31, 2016USD ($)$ / shares	Dec. 31, 2015USD ($)a$ / shares	Dec. 31, 2014USD ($)
Business Acquisition [Line Items]
Wells in Progress						$ 235,147	$ 235,147	$ 387,432
Proved Oil and Gas Property, Successful Effort Method						5,700,418	5,700,418	7,606,405
Unproved Oil and Gas Property, Successful Effort Method						2,471,947	2,471,947	284,538
Asset Retirement Obligations, Noncurrent						$ (96,134)	$ (96,134)	$ (137,284)
Common Stock, Par or Stated Value Per Share | $ / shares						$ 0.01	$ 0.01	$ 0.01
Payments to Acquire Oil and Gas Property and Equipment							$ 2,183,790	$ 7,984	$ 544,553
Value of common stock from issuance of private placement for an asset acquisition	[1]						$ 437,194	0	$ 0
QStar Acquisition 2016 [Member]
Business Acquisition [Line Items]
Wells in Progress		$ 21,812
Proved Oil and Gas Property, Successful Effort Method		61,614
Unproved Oil and Gas Property, Successful Effort Method		1,537,923
Oil and Gas Property, Successful Effort Method, Gross		1,621,349
Working Capital Acquired		(9,141)
Asset Retirement Obligations, Noncurrent		(7,641)
Acquisition of Oil and Gas Property And Equipment, Consideration Transferred		$ 1,604,567
Stock Issued During Period, Shares, Acquisitions | shares		13.4
Payments to Acquire Oil and Gas Property and Equipment		$ 1,167,373
Value of common stock from issuance of private placement for an asset acquisition	[2]	437,194
Noncash or Part Noncash Acquisition, Value of Assets Acquired		$ 1,604,567
Other Midland Basin Acquisition 2016 [Member]
Business Acquisition [Line Items]
Net acres acquired | a						2,900
Payments to Acquire Oil and Gas Property and Equipment						$ 60,000
Rocky Mountain Acquisition 2014 [Member]
Business Acquisition [Line Items]
Payments to Acquire Oil and Gas Property and Equipment								$ 135,500
Leasehold Acres Consideration to Acquire Unproved Property | a								7,000
Gooseneck Second Prospect Acquisition 2014 [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross				$ 84,836
Proved Oil and Gas Property, Successful Effort Method				54,612
Unproved Oil and Gas Property, Successful Effort Method				29,610
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets				84,222
Working Capital Acquired				2,232
Asset Retirement Obligations, Noncurrent				(1,618)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net				$ 84,836
Gooseneck Prospect Acquisition 2014 [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross					$ 321,807
Proved Oil and Gas Property, Successful Effort Method					203,467
Unproved Oil and Gas Property, Successful Effort Method					126,588
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets					330,055
Working Capital Acquired					(6,135)
Asset Retirement Obligations, Noncurrent					(2,113)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net					$ 321,807
Net acres acquired | a					61,000
Rock Oil Acquisition 2016 [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross			$ 991,038
Wells in Progress			5,672
Proved Oil and Gas Property, Successful Effort Method			81,917
Unproved Oil and Gas Property, Successful Effort Method			913,594
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets			5,338
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets			1,006,521
Working Capital Acquired			(7,888)
Asset Retirement Obligations, Noncurrent			(7,595)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net			$ 991,038
[1]	Refer to Note 3 - Acquisitions, Divestitures, and Assets Held for Sale and Note 15 - Equity for additional discussion.
[2]	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 prohibits the sale of such stock until no earlier than the 90th day after issuance.

Acquisitions, Divestitures, a42

Acquisitions, Divestitures, and Assets Held for Sale Divestitures and Assets Held for Sale (Details) $ in Thousands		Feb. 23, 2017USD ($)	Dec. 31, 2016USD ($)MMBTUbbl	Feb. 15, 2017USD ($)MMBTU$ / EnergyContent$ / Barrelsbbl	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment					$ 946,062	$ 357,938	$ 43,858
Net gain (loss) on divestiture activity					37,074	43,031	646
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest					(1,201,916)	(722,861)	1,064,699
Impairment of proved properties					$ 354,614	468,679	84,480
Assets Held-for-sale
Reasonably certain period within which sale will take place (in years)					1 year
Oil and gas properties held for sale			$ 372,621		$ 372,621	641
Asset Retirement Obligations Assets Held-for-sale Noncurrent			$ 26,241		26,241	241
Rocky Mountain Divestiture 2016 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment					110,600
Net gain (loss) on divestiture activity					16,400
Raven/Bear Den Divestiture 2016 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment					756,200
Net gain (loss) on divestiture activity					29,500
Permian Divestiture 2016 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment					54,600
Net gain (loss) on divestiture activity					(10,100)
Mid Continent Divestiture 2015 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment						310,300
Net gain (loss) on divestiture activity						108,400
Permian Divestiture 2015 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment						25,100
Net gain (loss) on divestiture activity						2,300
Other Divestitures 2015 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Not Discontinued Operation, Loss (Gain) on Write-down						68,600
Rocky Mountain Divestiture 2014 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment							42,000
Net gain (loss) on divestiture activity							26,900
Other Divestitures 2014 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Not Discontinued Operation, Loss (Gain) on Write-down							27,600
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]
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest					(6,601)	(12,530)	197,256
Impairment of proved properties						17,800
Disposal Group, Held-for-sale, Not Discontinued Operations [Member] | Non-Operated Eagle Ford Divestiture 2017 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest					(218,506)	$ 71,556	$ 294,376
Impairment of proved properties					$ 269,600
NYMEX Oil Swap Contracts [Member]
Assets Held-for-sale
Derivative, Nonmonetary Notional Amount, Volume | bbl			5,612,000
Gas Swaps Contracts [Member]
Assets Held-for-sale
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	[1]		192,192,000
Subsequent Event [Member] | Disposal Group, Held-for-sale, Not Discontinued Operations [Member] | Non-Operated Eagle Ford Divestiture 2017 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment				$ 800,000
Subsequent Event [Member] | NYMEX Oil Swap Contracts [Member] | Disposal Group, Held-for-sale, Not Discontinued Operations [Member] | Non-Operated Eagle Ford Divestiture 2017 [Member]
Assets Held-for-sale
Derivative, Nonmonetary Notional Amount, Volume | bbl				4,300,000
Subsequent Event [Member] | Gas Swaps Contracts [Member] | Disposal Group, Held-for-sale, Not Discontinued Operations [Member] | Non-Operated Eagle Ford Divestiture 2017 [Member]
Assets Held-for-sale
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU				4,600,000
Subsequent Event [Member] | NGL Swaps Contracts [Member]
Assets Held-for-sale
Derivative, Nonmonetary Notional Amount, Volume | bbl				1,100,000
Subsequent Event [Member] | NGL Swaps Contracts [Member] | Disposal Group, Held-for-sale, Not Discontinued Operations [Member] | Non-Operated Eagle Ford Divestiture 2017 [Member]
Assets Held-for-sale
Derivative, Nonmonetary Notional Amount, Volume | bbl				4,500,000
Minimum [Member] | Subsequent Event [Member] | NYMEX Oil Swap Contracts [Member] | Disposal Group, Held-for-sale, Not Discontinued Operations [Member] | Non-Operated Eagle Ford Divestiture 2017 [Member]
Assets Held-for-sale
Derivative, Swap Type, Fixed Price | $ / Barrels				54.05
Minimum [Member] | Subsequent Event [Member] | Gas Swaps Contracts [Member] | Disposal Group, Held-for-sale, Not Discontinued Operations [Member] | Non-Operated Eagle Ford Divestiture 2017 [Member]
Assets Held-for-sale
Derivative, Swap Type, Fixed Price | $ / EnergyContent				2.82
Minimum [Member] | Subsequent Event [Member] | NGL Swaps Contracts [Member]
Assets Held-for-sale
Derivative, Swap Type, Fixed Price | $ / Barrels				35.07
Minimum [Member] | Subsequent Event [Member] | NGL Swaps Contracts [Member] | Disposal Group, Held-for-sale, Not Discontinued Operations [Member] | Non-Operated Eagle Ford Divestiture 2017 [Member]
Assets Held-for-sale
Derivative, Swap Type, Fixed Price | $ / Barrels				11.81
Maximum [Member] | Subsequent Event [Member] | NYMEX Oil Swap Contracts [Member] | Disposal Group, Held-for-sale, Not Discontinued Operations [Member] | Non-Operated Eagle Ford Divestiture 2017 [Member]
Assets Held-for-sale
Derivative, Swap Type, Fixed Price | $ / Barrels				57
Maximum [Member] | Subsequent Event [Member] | Gas Swaps Contracts [Member] | Disposal Group, Held-for-sale, Not Discontinued Operations [Member] | Non-Operated Eagle Ford Divestiture 2017 [Member]
Assets Held-for-sale
Derivative, Swap Type, Fixed Price | $ / EnergyContent				2.99
Maximum [Member] | Subsequent Event [Member] | NGL Swaps Contracts [Member]
Assets Held-for-sale
Derivative, Swap Type, Fixed Price | $ / Barrels				49.88
Maximum [Member] | Subsequent Event [Member] | NGL Swaps Contracts [Member] | Disposal Group, Held-for-sale, Not Discontinued Operations [Member] | Non-Operated Eagle Ford Divestiture 2017 [Member]
Assets Held-for-sale
Derivative, Swap Type, Fixed Price | $ / Barrels				48.51
Scenario, Forecast [Member] | Minimum [Member] | Subsequent Event [Member] | Disposal Group, Held-for-sale, Not Discontinued Operations [Member] | Divide County Divestiture 2017 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Not Discontinued Operation, Loss (Gain) on Write-down		$ 200,000
Scenario, Forecast [Member] | Maximum [Member] | Subsequent Event [Member] | Disposal Group, Held-for-sale, Not Discontinued Operations [Member] | Divide County Divestiture 2017 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Not Discontinued Operation, Loss (Gain) on Write-down		$ 400,000
[1]	Total net volumes of natural gas swaps are comprised of IF El Paso Permian (3%), IF HSC (94%), and IF NNG Ventura (3%).

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Components of the provision for income taxes
Federal	$ 2,932	$ 0	$ 0
State	1,539	1,571	868
Deferred portion of income tax expense (benefit)	(448,643)	(276,722)	397,780
Income tax expense (benefit)	$ (444,172)	$ (275,151)	$ 398,648
Effective tax rate (as a percent)	37.00%	38.10%	37.40%
Deferred Income Taxes [Abstract]
Deferred Tax Liabilities, Oil and Gas Properties	$ 518,394	$ 854,029
Deferred Tax Liabilities, Derivative asset	0	179,543
Deferred Tax Liabilities, Other	7,733	1,233
Deferred Tax Liabilities	526,127	1,034,805
Deferred Tax Assets, Federal and State Tax Net Operating Loss Carryforwards	151,343	244,942
Deferred Tax Assets, Derivative Instruments	31,349	0
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Share-based Compensation Cost	10,083	14,529
Deferred Tax Assets, Tax Credit Carryforwards	12,448	6,952
Deferred Tax Assets, Other Liabilities	10,567	20,497
Deferred Tax Assets, Gross	215,790	286,920
Deferred Tax Assets, Valuation Allowance	(5,335)	(10,394)
Deferred Tax Assets, Net	210,455	276,526
Deferred Tax Liabilities, Net	315,672	758,279
Unrecognized Tax Benefits, Exercise of Stock Awards	126,700
Tax Credit Recorded for IRS R&D Settlement		2,000
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits, Beginning Balance	2,782	1,582	$ 2,358
Unrecognized Tax Benefits, Additions For Tax Positions Of Prior Years	9	1,200	140
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities	(2,345)	0	(916)
Unrecognized Tax Benefits, Ending Balance	446	2,782	$ 1,582
State and Local Jurisdiction [Member]
Deferred Income Taxes [Abstract]
Income Taxes Receivable, Current	0	65
Taxes Payable, Current	1,181	0
Operating Loss Carryforwards	184,600
General Business Tax Credit Carryforward [Member] | State and Local Jurisdiction [Member]
Deferred Income Taxes [Abstract]
Tax Credit Carryforward, Amount	528
Internal Revenue Service (IRS) [Member] | Domestic Tax Authority [Member]
Deferred Income Taxes [Abstract]
Income Taxes Receivable, Current	644	$ 5,378
Operating Loss Carryforwards	540,200
Internal Revenue Service (IRS) [Member] | Research Tax Credit Carryforward [Member] | Domestic Tax Authority [Member]
Deferred Income Taxes [Abstract]
Tax Credit Carryforward, Amount	7,200
Internal Revenue Service (IRS) [Member] | Alternative Minimum Tax Credit Carryforward [Member] | Domestic Tax Authority [Member]
Deferred Income Taxes [Abstract]
Tax Credit Carryforward, Amount	$ 5,600

Income Taxes (Reconciliation of

Income Taxes (Reconciliation of Tax Expense (Benefit)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Federal statutory tax expense (benefit)	$ (420,671)	$ (253,001)	$ 372,644
State tax expense (benefit) (net of federal benefit)	(17,549)	(21,583)	21,350
Change in valuation allowance	(5,059)	3,148	2,245
Research and development credit	0	(1,971)	0
Other	(893)	(1,744)	2,409
Income tax expense (benefit)	$ (444,172)	$ (275,151)	$ 398,648

Long-Term Debt (Details)

Long-Term Debt (Details) - USD ($)	Sep. 12, 2016	Jun. 22, 2015	May 21, 2015	Nov. 17, 2014	May 20, 2013	Jun. 29, 2012	Nov. 08, 2011	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Aug. 12, 2016	Jun. 05, 2015	May 20, 2015
Debt Instrument [Line Items]
Senior Notes, net of unamortized deferred financing costs									$ 2,766,719,000	$ 2,315,970,000
Gains (Losses) on Extinguishment of Debt									15,722,000	(16,578,000)	$ 0
Gains (Losses) on Extinguishment of Debt, Non-Cash Portion									15,722,000	(4,123,000)	0
Net proceeds from debt issuance									491,640,000	490,951,000	589,991,000
Proceeds from Convertible Debt Net of Issuance Costs									166,617,000	0	0
Convertible Debt, Noncurrent									130,856,000	0
Adjustments to Additional Paid in Capital, Equity Component of Convertible Debt, Net of Issuance Costs and Deferred Taxes									33,575,000
Capped Call Transaction Costs									$ 24,195,000
Capped Call, Cap Price									$ 60
Interest Costs, Capitalized During Period									$ 17,000,000	25,100,000	$ 16,200,000
Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount									2,803,736,000	2,350,000,000
Unamortized Debt Issuance Expense									37,017,000	34,030,000
Debt Instrument, Covenant Compliance, Dividends Excluded From Computation									6,500,000
Debt Instrument, Repurchased Face Amount								$ 46,300,000
Debt Instrument, Repurchased Settlement Amount								29,900,000
Gains (Losses) on Extinguishment of Debt								15,722,000
Debt Instrument, Repurchase Discount								16,400,000
Gains (Losses) on Extinguishment of Debt, Non-Cash Portion								(700,000)
6.50% Senior Notes Due 2021 [Member]
Debt Instrument [Line Items]
Unamortized Debt Issuance Expense									3,372,000	4,106,000
Senior Notes, net of unamortized deferred financing costs									$ 343,583,000	345,894,000
6.50% Senior Notes Due 2021 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage							6.50%		6.50%
Debt Instrument, Face Amount							$ 350,000,000		$ 346,955,000	350,000,000
Debt Instrument, Repurchased Face Amount								3,100,000
Debt Instrument, Repurchased Settlement Amount								2,300,000
Net proceeds from debt issuance							343,100,000
Debt Issuance Costs, Gross							$ 6,900,000
6.125% Senior Notes Due 2022 [Member]
Debt Instrument [Line Items]
Unamortized Debt Issuance Expense									6,979,000	8,714,000
Senior Notes, net of unamortized deferred financing costs									$ 554,817,000	591,286,000
6.125% Senior Notes Due 2022 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				6.125%					6.125%
Debt Instrument, Face Amount				$ 600,000,000					$ 561,796,000	600,000,000
Debt Instrument, Repurchased Face Amount								38,200,000
Debt Instrument, Repurchased Settlement Amount								24,300,000
Net proceeds from debt issuance				590,000,000
Debt Issuance Costs, Gross				$ 10,000,000
6.50% Senior Notes Due 2023 [Member]
Debt Instrument [Line Items]
Unamortized Debt Issuance Expense									4,436,000	5,231,000
Senior Notes, net of unamortized deferred financing costs									$ 390,549,000	394,769,000
6.50% Senior Notes Due 2023 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage						6.50%			6.50%
Debt Instrument, Face Amount						$ 400,000,000			$ 394,985,000	400,000,000
Debt Instrument, Repurchased Face Amount								5,000,000
Debt Instrument, Repurchased Settlement Amount								$ 3,300,000
Net proceeds from debt issuance						392,100,000
Debt Issuance Costs, Gross						$ 7,900,000
5% Senior Notes Due 2024 [Member]
Debt Instrument [Line Items]
Unamortized Debt Issuance Expense									6,533,000	7,455,000
Senior Notes, net of unamortized deferred financing costs									$ 493,467,000	492,545,000
5% Senior Notes Due 2024 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage					5.00%				5.00%
Debt Instrument, Face Amount					$ 500,000,000				$ 500,000,000	500,000,000
Net proceeds from debt issuance					490,200,000
Debt Issuance Costs, Gross					$ 9,800,000
5.625% Senior Notes Due 2025 [Member]
Debt Instrument [Line Items]
Unamortized Debt Issuance Expense									7,619,000	8,524,000
Senior Notes, net of unamortized deferred financing costs									$ 492,381,000	491,476,000
5.625% Senior Notes Due 2025 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			5.625%						5.625%
Debt Instrument, Face Amount			$ 500,000,000						$ 500,000,000	500,000,000
Net proceeds from debt issuance			491,000,000
Debt Issuance Costs, Gross			$ 9,000,000
6.75% Senior Notes Due 2026 [Member]
Debt Instrument [Line Items]
Unamortized Debt Issuance Expense									8,078,000	0
Senior Notes, net of unamortized deferred financing costs									$ 491,922,000	0
6.75% Senior Notes Due 2026 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.75%								6.75%
Debt Instrument, Face Amount	$ 500,000,000								$ 500,000,000	0
Net proceeds from debt issuance	491,600,000
Debt Issuance Costs, Gross	$ 8,400,000
6.625% Senior Notes Due 2019 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage														6.625%
Debt Instrument, Repurchased Face Amount													$ 1,500,000	$ 242,900,000
Gains (Losses) on Extinguishment of Debt										(16,600,000)
Gains (Losses) on Extinguishment of Debt, Non-Cash Portion										(4,100,000)
Price per Note Tendered													1,006.88	1,036.88
Debt Instrument, Face Amount, Individual Note													1,000	$ 1,000
Percentage of Notes Tendered														69.00%
Debt Instrument, Repurchase Amount													$ 1,600,000	$ 256,200,000
Debt Instrument, Repurchase Premium										12,500,000
6.625% Senior Notes Due 2019 [Member] | From February 15, 2015 to February 14, 2016 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Repurchase Amount		$ 111,500,000
Debt Instrument, Redemption Price, Percentage		103.313%
1.50% Senior Convertible Notes Due 2021 [Domain] | Convertible Debt [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage									1.50%			1.50%
Debt Instrument, Face Amount									$ 172,500,000	$ 0		$ 172,500,000
Unamortized Debt Issuance Expense									4,131,000
Debt Issuance Costs, Gross									5,900,000
Proceeds from Convertible Debt Net of Issuance Costs									$ 166,617,000
Debt Instrument, Convertible, Threshold Trading Days									20
Debt Instrument, Convertible, Threshold Consecutive Trading Days									30 days
Debt Instrument, Convertible, Threshold Percentage of Stock Price Trigger									130.00%
Debt Instrument, Convertible, Threshold Business Days, Trading Price Trigger									5 days
Debt Instrument, Convertible, Threshold Trading Days, Trading Price Trigger									5 days
Debt Instrument, Principal Amount of Note									$ 1,000
Debt Instrument, Convertible, Threshold Percentage of Trading Price Trigger									98.00%
Debt Instrument, Convertible, Conversion Ratio									24.6914
Debt Instrument, Convertible, Conversion Price									$ 40.50
Debt Instrument, Convertible, Comparable Yield									7.25%
Debt Instrument, Convertible, Initial Fair Value of Liability Component												132,300,000
Debt Instrument, Convertible, Initial Fair Value of Liability Component									$ 40,217,000			$ 40,217,000
Interest Expense, Debt									3,700,000
Debt Instrument, Unamortized Discount									(37,513,000)
Convertible Debt, Noncurrent									130,856,000
Debt Issuance Costs, Gross, Equity Component of Convertible Debt									(1,375,000)
Adjustments to Additional Paid in Capital, Equity Component of Convertible Debt									(5,267,000)
Adjustments to Additional Paid in Capital, Equity Component of Convertible Debt, Net of Issuance Costs and Deferred Taxes									$ 33,575,000

Long-term Debt Revolving Credit

Long-term Debt Revolving Credit Facility (Details) $ in Thousands		12 Months Ended
		Dec. 31, 2016USD ($)	Feb. 15, 2017USD ($)	Sep. 30, 2016USD ($)	Aug. 12, 2016USD ($)	Apr. 08, 2016USD ($)	Dec. 31, 2015USD ($)
Line of Credit Facility [Line Items]
Percentage of Proved Oil and Gas Properties Secured for Credit Facility Borrowing		90.00%
Line of Credit [Member] | Borrowing Base Utilization of 25 Percent [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage		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 Facility, Unused Capacity, Commitment Fee Percentage		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 Facility, Unused Capacity, Commitment Fee Percentage		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 Facility, Unused Capacity, Commitment Fee Percentage		0.375%
Line of Credit [Member] | Borrowing Base Utilization Of More Than 90 Percent [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage		0.375%
Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 2,500,000
Borrowing Base, Line of Credit		1,165,000		$ 1,350,000	$ 1,100,000	$ 1,250,000	$ 2,000,000
Line of Credit Facility, Current Borrowing Capacity		1,165,000		$ 1,250,000	$ 1,100,000	$ 1,250,000	1,500,000
Debt Issuance Costs, Gross		3,100
Accelerated Amortization of Debt Issuance Costs Related To Borrowing Base And Lender Commitment Revisions		2,500
Long-term Line of Credit	[1]	0					202,000
Letters of Credit Outstanding, Amount	[2]	200					200
Line of Credit Facility, Remaining Borrowing Capacity		1,164,800					1,297,800
Unamortized Debt Issuance Expense		$ 5,900					$ 4,900
Subsequent Event [Member] | Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Current Borrowing Capacity			$ 1,165,000
Long-term Line of Credit	[1]		103,500
Letters of Credit Outstanding, Amount	[2]		200
Line of Credit Facility, Remaining Borrowing Capacity			$ 1,061,300
Eurodollar [Member] | Line of Credit [Member] | Borrowing Base Utilization of 25 Percent [Member]
Line of Credit Facility [Line Items]
Debt Instrument, 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]
Debt Instrument, 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]
Debt Instrument, 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]
Debt Instrument, 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]
Debt Instrument, 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]
Debt Instrument, 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]
Debt Instrument, 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]
Debt Instrument, 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]
Debt Instrument, 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]
Debt Instrument, Basis Spread on Variable Rate		1.75%
Maximum [Member] | Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt Instrument, 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]
Debt Instrument Covenant Compliance Adjusted Current Ratio		1
Debt Instrument, Covenant Compliance, Adjusted EBITDAX To Interest Expense		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 $5.9 million and $4.9 million as of December 31, 2016, and 2015, respectively.
[2]	Letters of credit reduce the amount available under the credit facility on a dollar-for-dollar basis.

Commitments (Details)

Commitments (Details) MMcf in Thousands, $ in Thousands		12 Months Ended
		Dec. 31, 2016USD ($)MMBblsMMcf	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Commitments and Contingencies
Contractual Obligation, Due in Next Twelve Months	[1]	$ 145,075
Contractual Obligation, Due in Second Year	[1]	148,240
Contractual Obligation, Due in Third Year	[1]	144,379
Contractual Obligation, Due in Fourth Year	[1]	141,010
Contractual Obligation, Due in Fifth Year	[1]	141,654
Contractual Obligation, Due after Fifth Year	[1]	337,745
Contractual Obligation	[1]	1,058,103
Operating Leases, Future Minimum Payments Due, Future Minimum Sublease Rentals		2,700
Operating Leases, Rent Expense		$ 5,200	$ 6,100	$ 6,500
Natural Gas Transportation Commitment [Member]
Commitments and Contingencies
Oil and Gas Delivery Commitments and Contracts, Remaining Contractual Volume | MMcf		1,461
Oil and Gas Delivery Commitments and Contracts, Remaining Contractual Volume on Non-Operated Eagle Ford Assets | MMcf		514
Crude Oil Transportation Commitment [Member]
Commitments and Contingencies
Oil and Gas Delivery Commitments and Contracts, Remaining Contractual Volume | MMBbls		70
Oil and Gas Delivery Commitments and Contracts, Remaining Contractual Volume on Non-Operated Eagle Ford Assets | MMBbls		52
Natural Gas Liquids Transportation Commitment [Member]
Commitments and Contingencies
Oil and Gas Delivery Commitments and Contracts, Remaining Contractual Volume | MMBbls		13
Oil and Gas Delivery Commitments and Contracts, Remaining Contractual Volume on Non-Operated Eagle Ford Assets | MMBbls		13
Drilling Rig Leasing Contracts [Member]
Commitments and Contingencies
Contractual Obligation		$ 31,100
Early Termination Penalty For Rig Contract Cancellation		14,200
Gain (Loss) on Contract Termination		$ (8,700)	$ (13,700)
Water Transportation Commitment [Member]
Commitments and Contingencies
Water Delivery Commitments and Contracts, Remaining Contractual Volume | MMBbls		25
Gas Gathering and Oil, Gas, NGL, and Water Through-put Commitments [Member]
Commitments and Contingencies
Contractual Obligation		$ 970,900
Contractual Obligation, Non-Operated Eagle Ford Assets		501,900
Office Space Leases [Member]
Commitments and Contingencies
Contractual Obligation		50,100
Gain (Loss) on Contract Termination		(3,200)
Other miscellaneous contracts and leases [Member]
Commitments and Contingencies
Contractual Obligation		$ 6,000
[1]	During the third quarter of 2015, the Company closed its office in Tulsa, Oklahoma. These amounts include lease payments for the Tulsa office, net of sublease income. The Company expects to receive $2.7 million of total sublease income through 2019.

Compensation Plans_ Stock Based

Compensation Plans: Stock Based (Details) $ / shares in Units, $ in Thousands		12 Months Ended
		Dec. 31, 2016USD ($)shares$ / shares	Dec. 31, 2015USD ($)$ / sharesshares	Dec. 31, 2014USD ($)$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares available for grant		5,500,000
Impact outright issuance of one share has on number of available shares		1
Stock-based compensation expense | $		$ 26,897	$ 27,467	$ 32,694
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	0.55
Award Vesting Period		3 years
Stock-based compensation expense | $		$ 11,000	$ 10,600	$ 16,000
Unrecognized stock based compensation expense | $		$ 15,900
Multiplier assumed		1
Fair value of PSUs/RSUs Granted in Period | $		$ 11,900	$ 14,500	$ 19,200
Performance Share Units Shares Settled Gross of Shares for Tax Withholdings	[1]	44,870	288,962	130,163
Shares held for settlement of income and payroll tax obligations (in shares)		(14,809)	(100,683)	(45,042)
Shares Issued in Period		30,061	188,279	85,121
Fair value of PSUs/RSUs Vested in Period | $		$ 8,400	$ 4,000	$ 13,400
Weighted Average Grant Date Fair Value
Non-vested at beginning of year (in shares)	[2]	626,328	433,660	572,469
Granted (in shares)	[2]	447,971	320,753	202,404
Vested (in shares)	[2]	(130,353)	(76,438)	(206,830)
Forfeited (in shares)	[2]	(115,023)	(51,647)	(134,383)
Non-vested at end of year (in shares)	[2]	828,923	626,328	433,660
Non-vested outstanding at the beginning of the period (in dollars per share) | $ / shares	[2]	$ 61.81	$ 73.63	$ 66.07
Granted (in dollars per share) | $ / shares	[2]	26.56	45.34	94.66
Vested (in dollars per share) | $ / shares	[2]	64.17	51.76	64.79
Forfeited (in dollars per share) | $ / shares	[2]	55.59	73.62	86.72
Non-vested outstanding at the end of the period (in dollars per share) | $ / shares	[2]	$ 43.25	$ 61.81	$ 73.63
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense | $		$ 11,900	$ 13,400	$ 13,900
Unrecognized stock based compensation expense | $		14,400
Fair value of PSUs/RSUs Granted in Period | $		$ 11,700	$ 15,600	$ 19,700
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)		(72,181)	(91,045)	(81,434)
Shares Issued in Period		169,182	187,244	171,597
Fair value of PSUs/RSUs Vested in Period | $		$ 14,000	$ 17,600	$ 14,700
Number of Shares Represented by Each RSU		1
Restricted Stock, Shares Settled Gross of Shares for Tax Withholdings	[3]	241,363	278,289	253,031
Weighted Average Grant Date Fair Value
Non-vested at beginning of year (in shares)		543,737	515,724	580,431
Granted (in shares)		417,065	356,246	234,560
Vested (in shares)		(241,363)	(278,289)	(253,031)
Forfeited (in shares)		(115,323)	(49,944)	(46,236)
Non-vested at end of year (in shares)		604,116	543,737	515,724
Non-vested outstanding at the beginning of the period (in dollars per share) | $ / shares		$ 55.01	$ 68.29	$ 57.05
Granted (in dollars per share) | $ / shares		28.08	43.72	83.98
Vested (in dollars per share) | $ / shares		58.06	63.12	58.19
Forfeited (in dollars per share) | $ / shares		43.52	66.53	62.06
Non-vested outstanding at the end of the period (in dollars per share) | $ / shares		$ 37.39	$ 55.01	$ 68.29
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 | $		$ 2,000	$ 1,600	$ 1,600
Director Shares
Stock Issued During Period, Shares, Share-based Compensation, Gross		53,473	39,903	27,677
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
[1]	During the years ended December 31, 2016, 2015, and 2014, the Company issued shares of common stock for PSUs granted in 2013, 2012, and 2011. The Company and the 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, 2016, 2015, and 2014, the Company issued shares of common stock for RSUs granted in previous years. The Company and the 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 Stock Option

Compensation Plans Stock Option Grants Under the Equity Incentive Compensation Plan (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Compensation plans
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Stock Options	$ 0	$ 0	$ 0
Proceeds from Stock Options Exercised			4,000,000
Employee Service Share-based Compensation, Tax Benefit Realized from Exercise of Stock Options	$ 0	$ 0	$ 0
Shares
Outstanding, start of year		0	39,088
Exercised			(39,088)
Forfeited			0
Outstanding, end of year			0
Vested and exercisable at end of year			0
Weighted Average Exercise Price
Outstanding, start of year (in dollars per share)		$ 0	$ 20.87
Exercised (in dollars per share)			20.87
Forfeited (in dollars per share)			0
Outstanding, end of year (in dollars per share)			0
Vested and exercisable at end of year (in dollars per share)			$ 0
Aggregate Intrinsic Value
Exercised			$ 1,993,726
Outstanding			0	$ 0
Vested and exercisable at end of year			$ 0
Employee Stock Option [Member]
Compensation plans
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period	10 years

Compensation Plans Employee Sto

Compensation Plans Employee Stock Purchase Plan (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Compensation plans
Number of shares available for grant	5,500,000
Stock-based compensation expense	$ 26,897,000	$ 27,467,000	$ 32,694,000
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	700,000
Issuance of common stock under Employee Stock Purchase Plan (in shares)	218,135	197,214	83,136
Proceeds from Issuance of Shares under Incentive and Share-based Compensation Plans, Excluding Stock Options	$ 4,200,000	$ 4,800,000	$ 4,100,000
Risk free interest rate	0.40%	0.10%	0.10%
Dividend yield	0.40%	0.20%	0.10%
Volatility factor of the expected market price of the Company's common stock	95.00%	61.20%	33.00%
Expected life (in years)	6 months	6 months	6 months
Stock-based compensation expense	$ 2,000,000	$ 1,800,000	$ 1,100,000

Compensation Plans Non Stock-Ba

Compensation Plans Non Stock-Based Compensation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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	$ 6,608	$ 3,498	$ 9,016
Cash Payments Made or Accrued under Profit Sharing Plan Related to Divested Property	24,349	3,789	8,341
Total net settlements under Profit Sharing Plan	$ 30,957	7,287	17,357
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 Recognized	$ 5,400	$ 5,600	$ 6,400

Pension Benefits (Details)

Pension Benefits (Details) - USD ($)		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Defined Benefit Plan, Benefit Obligation Beginning of Year		$ 62,547,000	$ 57,867,000
Defined Benefit Plan, Service Cost		8,200,000	7,949,000	$ 6,335,000
Defined Benefit Plan, Interest Cost		2,908,000	2,496,000	2,191,000
Defined Benefit Plan, Actuarial Gain (Loss)		2,662,000	2,397,000
Defined Benefit Plan, Benefits Paid		(6,658,000)	(8,162,000)	(2,800,000)
Defined Benefit Plan, Benefit Obligation End of Year		69,659,000	62,547,000	57,867,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets Beginning of Year		25,769,000	27,940,000
Defined Benefit Plan, Actual Return on Plan Assets		1,575,000	(410,000)
Defined Benefit Plan, Employer Contribution		11,045,000	6,401,000	5,300,000
Defined Benefit Plan, Fair Value of Plan Assets End of Year		31,731,000	25,769,000	27,940,000
Defined Benefit Plan, Funded Status of Plan		(37,928,000)	(36,778,000)
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year		7,800,000
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets [Abstract]
Defined Benefit Plan, Benefit Obligation End of Year		69,659,000	62,547,000	57,867,000
Defined Benefit Plan, Accumulated Benefit Obligation		54,681,000	46,439,000
Defined Benefit Plan, Fair Value of Plan Assets Beginning of Year		(31,731,000)	(25,769,000)	(27,940,000)
Defined Benefit Plan, Accumulated Unfunded Benefit Obligation		$ 22,950,000	20,670,000
Pension And Other Post-retirement Benefit Plans, Gain (Loss) Amortization Threshold		10.00%
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax		$ 22,708,000	20,966,000	17,812,000
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Prior Service Cost (Credit), before Tax		83,000	101,000	118,000
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Transition Assets (Obligations), before Tax		0	0	0
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax		22,791,000	21,067,000	17,930,000
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year		1,600,000
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, before Tax		(3,322,000)	(4,990,000)	(10,062,000)
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Arising During Period, before Tax		0	0	0
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax		(16,000)	(17,000)	(17,000)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax		(1,582,000)	(1,486,000)	(689,000)
Other Comprehensive Income (Loss), Finalization of Pension and Other Postretirement Benefit Plan Valuation, before Tax		0	(350,000)	0
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, before Tax		(1,724,000)	(3,137,000)	(9,356,000)
Components of Net Periodic Benefit Costs for Both Pension Plans
Defined Benefit Plan, Service Cost		8,200,000	7,949,000	6,335,000
Defined Benefit Plan, Interest Cost		2,908,000	2,496,000	2,191,000
Defined Benefit Plan, Expected Return on Plan Assets		(2,235,000)	(2,182,000)	(1,978,000)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)		16,000	17,000	17,000
Defined Benefit Plan, Amortization of Gains (Losses)		1,582,000	1,486,000	689,000
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements		0	350,000	0
Defined Benefit Plan, Net Periodic Benefit Cost		$ 10,471,000	$ 10,116,000	$ 7,254,000
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation and Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		4.20%	4.70%	4.30%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase		6.20%	6.20%	6.20%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		4.70%	4.30%	5.00%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets	[1]	7.50%	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		$ 6,532,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Two		3,256,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Three		4,480,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Four		4,778,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Five		5,772,000
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter		38,708,000
Qualified Plan [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan Plan Assets Returned		0
Non Qualified Plan [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets Beginning of Year		0	$ 0
Defined Benefit Plan, Fair Value of Plan Assets End of Year		0	0	$ 0
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets [Abstract]
Defined Benefit Plan, Fair Value of Plan Assets Beginning 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 Long-term Return on Assets			0.00%	0.00%
[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.

Pension Benefits Fair Value of

Pension Benefits Fair Value of Plan Assets in Heirarchy (Details) - USD ($)		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets	[1]	7.50%	7.50%	7.50%
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities		100.00%
Defined Benefit Plan, Asset Allocation		100.00%	100.00%
Defined Benefit Plan, Fair Value of Plan Assets		$ 31,731,000	$ 25,769,000	$ 27,940,000
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value		5,214,000	5,045,000	$ 4,864,000
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases		561,000	0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings		54,000	165,000
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Other Comprehensive Income (Loss)		115,000	16,000
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales		(561,000)
Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Fair Value of Plan Assets		19,481,000	17,754,000
Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Fair Value of Plan Assets		7,036,000	2,970,000
Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan, Fair Value of Plan Assets		$ 5,214,000	$ 5,045,000
Cash and Cash Equivalents [Member]
Defined Benefit Plan, Asset Allocation		0.00%	0.00%
Defined Benefit Plan, Fair Value of Plan Assets		$ 0	$ 0
Cash and Cash Equivalents [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Cash and Cash Equivalents [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Cash and Cash Equivalents [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan, Fair Value of Plan Assets		$ 0	$ 0
Domestic Equity Securities [Member]
Defined Benefit Plan, Asset Allocation	[2]	18.70%	26.10%
Defined Benefit Plan, Fair Value of Plan Assets	[2]	$ 5,945,000	$ 6,729,000
Domestic Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Fair Value of Plan Assets	[2]	4,471,000	4,943,000
Domestic Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Fair Value of Plan Assets	[2]	1,474,000	1,786,000
Domestic Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan, Fair Value of Plan Assets	[2]	$ 0	$ 0
International Equity Securities [Member]
Defined Benefit Plan, Asset Allocation	[3]	10.10%	13.00%
Defined Benefit Plan, Fair Value of Plan Assets	[3]	$ 3,192,000	$ 3,353,000
International Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Fair Value of Plan Assets	[3]	3,192,000	3,353,000
International Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Fair Value of Plan Assets	[3]	0	0
International Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan, Fair Value of Plan Assets	[3]	$ 0	$ 0
Equity Securities [Member]
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities		35.00%
Defined Benefit Plan, Asset Allocation		28.80%	39.10%
Defined Benefit Plan, Fair Value of Plan Assets		$ 9,137,000	$ 10,082,000
Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Fair Value of Plan Assets		7,663,000	8,296,000
Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Fair Value of Plan Assets		1,474,000	1,786,000
Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan, Fair Value of Plan Assets		$ 0	$ 0
High-yield Bonds [Member]
Defined Benefit Plan, Asset Allocation	[4]	2.60%	2.80%
Defined Benefit Plan, Fair Value of Plan Assets	[4]	$ 822,000	$ 722,000
High-yield Bonds [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Fair Value of Plan Assets	[4]	822,000	722,000
High-yield Bonds [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Fair Value of Plan Assets	[4]	0	0
High-yield Bonds [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan, Fair Value of Plan Assets	[4]	$ 0	$ 0
Fixed Income Investments [Member]
Defined Benefit Plan, Asset Allocation	[5]	25.00%	22.50%
Defined Benefit Plan, Fair Value of Plan Assets	[5]	$ 7,923,000	$ 5,789,000
Fixed Income Investments [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Fair Value of Plan Assets	[5]	7,923,000	5,789,000
Fixed Income Investments [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Fair Value of Plan Assets	[5]	0	0
Fixed Income Investments [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan, Fair Value of Plan Assets	[5]	$ 0	$ 0
Floating Rate Corporate Debt [Member]
Defined Benefit Plan, Asset Allocation	[6]	7.90%	8.70%
Defined Benefit Plan, Fair Value of Plan Assets	[6]	$ 2,495,000	$ 2,247,000
Floating Rate Corporate Debt [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Fair Value of Plan Assets	[6]	2,495,000	2,247,000
Floating Rate Corporate Debt [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Fair Value of Plan Assets	[6]	0	0
Floating Rate Corporate Debt [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan, Fair Value of Plan Assets	[6]	$ 0	$ 0
Fixed Income Securities [Member]
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities		43.00%
Defined Benefit Plan, Asset Allocation		35.50%	34.00%
Defined Benefit Plan, Fair Value of Plan Assets		$ 11,240,000	$ 8,758,000
Fixed Income Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Fair Value of Plan Assets		11,240,000	8,758,000
Fixed Income Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Fixed Income Securities [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan, Fair Value of Plan Assets		$ 0	$ 0
Commodity Contract [Member]
Defined Benefit Plan, Asset Allocation	[7]	1.80%	2.70%
Defined Benefit Plan, Fair Value of Plan Assets	[7]	$ 578,000	$ 700,000
Commodity Contract [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Fair Value of Plan Assets	[7]	578,000	700,000
Commodity Contract [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Fair Value of Plan Assets	[7]	0	0
Commodity Contract [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan, Fair Value of Plan Assets	[7]	$ 0	$ 0
Real Estate [Member]
Defined Benefit Plan, Asset Allocation	[8]	5.10%	5.80%
Defined Benefit Plan, Fair Value of Plan Assets	[8]	$ 1,629,000	$ 1,499,000
Real Estate [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Fair Value of Plan Assets	[8]	0	0
Real Estate [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Fair Value of Plan Assets	[8]	0	0
Real Estate [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan, Fair Value of Plan Assets	[8]	$ 1,629,000	$ 1,499,000
Hedge Funds [Member]
Defined Benefit Plan, Asset Allocation	[9]	11.30%	13.80%
Defined Benefit Plan, Fair Value of Plan Assets	[9]	$ 3,585,000	$ 3,546,000
Hedge Funds [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Fair Value of Plan Assets	[9]	0	0
Hedge Funds [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Fair Value of Plan Assets	[9]	0	0
Hedge Funds [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan, Fair Value of Plan Assets	[9]	$ 3,585,000	$ 3,546,000
Collective Investment Trust [Member]
Defined Benefit Plan, Asset Allocation	[10]	17.50%	4.60%
Defined Benefit Plan, Fair Value of Plan Assets	[10]	$ 5,562,000	$ 1,184,000
Collective Investment Trust [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Fair Value of Plan Assets	[10]	0	0
Collective Investment Trust [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Fair Value of Plan Assets	[10]	5,562,000	1,184,000
Collective Investment Trust [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan, Fair Value of Plan Assets	[10]	$ 0	$ 0
Other Securities [Member]
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities		22.00%
Defined Benefit Plan, Asset Allocation		35.70%	26.90%
Defined Benefit Plan, Fair Value of Plan Assets		$ 11,354,000	$ 6,929,000
Other Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Fair Value of Plan Assets		578,000	700,000
Other Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Fair Value of Plan Assets		5,562,000	1,184,000
Other Securities [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan, Fair Value of Plan Assets		5,214,000	$ 5,045,000
Non Qualified Plan [Member]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on 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]	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]	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.
[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.

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016		Dec. 31, 2015
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligation: Beginning of Year		$ 140,874	[1],[2]	$ 122,124
Asset Retirement Obligation, Liabilities Incurred	[3]	21,293		14,471
Asset Retirement Obligation, Liabilities Settled	[4]	(57,100)		(24,781)
Asset Retirement Obligation, Accretion Expense		7,795		5,091
Asset Retirement Obligation, Revision of Estimate		10,445		23,969
Asset Retirement Obligation: End of Year	[1],[2]	123,307		140,874
Asset Retirement Obligations Assets Held-for-sale Noncurrent		26,241		241
Asset Retirement Obligation, Current		$ 932		$ 3,300
[1]	Balance as of December 31, 2016, included $26.2 million of asset retirement obligations associated with oil and gas properties held for sale, specifically the Company’s outside-operated Eagle Ford shale assets. There were no material asset retirement obligations related to assets held for sale as of December 31, 2015.
[2]	Balances as of December 31, 2016, and 2015, included $932,000 and $3.3 million, 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 Instrume55

Derivative Financial Instruments (Details)		Dec. 31, 2016MMBTU$ / EnergyContent$ / Barrelsbbl	Feb. 15, 2017$ / Barrelsbbl
NYMEX Oil Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl		11,300,000
NGL Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl		13,400,000
NYMEX Oil Swap Contract First Quarter 2017 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		46.41
Derivative, Nonmonetary Notional Amount, Volume | bbl		1,574,000
NYMEX Oil Swap Contract Second Quarter 2017 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		46.44
Derivative, Nonmonetary Notional Amount, Volume | bbl		1,444,000
NYMEX Oil Swap Contract Third Quarter 2017 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		46.66
Derivative, Nonmonetary Notional Amount, Volume | bbl		1,340,000
NYMEX Oil Swap Contract Fourth Quarter 2017 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		46.35
Derivative, Nonmonetary Notional Amount, Volume | bbl		1,254,000
NYMEX Oil Swap Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl		5,612,000
NYMEX Oil Collar Contract First Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Floor Price		45
Derivative, Cap Price		54.17
Derivative, Nonmonetary Notional Amount, Volume | bbl		704,000
NYMEX Oil Collar Contract Second Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Floor Price		45
Derivative, Cap Price		54.10
Derivative, Nonmonetary Notional Amount, Volume | bbl		636,000
NYMEX Oil Collar Contract Third Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Floor Price		45
Derivative, Cap Price		54.05
Derivative, Nonmonetary Notional Amount, Volume | bbl		583,000
NYMEX Oil Collar Contract Fourth Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Floor Price		45
Derivative, Cap Price		54.01
Derivative, Nonmonetary Notional Amount, Volume | bbl		540,000
NYMEX Oil Collar Contract 2018 [Member]
Derivative Financial Instruments
Derivative, Floor Price		50
Derivative, Cap Price		59.24
Derivative, Nonmonetary Notional Amount, Volume | bbl		2,312,000
NYMEX Oil Collar Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Floor Price		50
Derivative, Cap Price		61.15
Derivative, Nonmonetary Notional Amount, Volume | bbl		943,000
NYMEX Oil Collar Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl		5,718,000
Gas Swaps Contract First Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU		29,420,000
Weighted- Average Contract Price | $ / EnergyContent		3.76
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | MMBTU	[1]	0
Derivative, Swap Type, Average Fixed Price, Purchased Volumes | $ / EnergyContent		0
Derivative, Nonmonetary Notional Amount, Energy Measure, Net of Purchased Volumes | MMBTU		29,420,000
Gas Swaps Contract Second Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU		26,205,000
Weighted- Average Contract Price | $ / EnergyContent		3.98
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | MMBTU	[1]	0
Derivative, Swap Type, Average Fixed Price, Purchased Volumes | $ / EnergyContent		0
Derivative, Nonmonetary Notional Amount, Energy Measure, Net of Purchased Volumes | MMBTU		26,205,000
Gas Swaps Contract Third Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU		23,657,000
Weighted- Average Contract Price | $ / EnergyContent		4.01
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | MMBTU	[1]	0
Derivative, Swap Type, Average Fixed Price, Purchased Volumes | $ / EnergyContent		0
Derivative, Nonmonetary Notional Amount, Energy Measure, Net of Purchased Volumes | MMBTU		23,657,000
Gas Swaps Contract Fourth Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU		22,001,000
Weighted- Average Contract Price | $ / EnergyContent		3.98
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | MMBTU	[1]	0
Derivative, Swap Type, Average Fixed Price, Purchased Volumes | $ / EnergyContent		0
Derivative, Nonmonetary Notional Amount, Energy Measure, Net of Purchased Volumes | MMBTU		22,001,000
Gas Swaps Contract 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU		63,166,000
Weighted- Average Contract Price | $ / EnergyContent		3.68
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | MMBTU	[1]	(30,606,000)
Derivative, Swap Type, Average Fixed Price, Purchased Volumes | $ / EnergyContent		4.27
Derivative, Nonmonetary Notional Amount, Energy Measure, Net of Purchased Volumes | MMBTU		32,560,000
Gas Swaps Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU		27,743,000
Weighted- Average Contract Price | $ / EnergyContent		4.20
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | MMBTU	[1]	(24,415,000)
Derivative, Swap Type, Average Fixed Price, Purchased Volumes | $ / EnergyContent		4.34
Derivative, Nonmonetary Notional Amount, Energy Measure, Net of Purchased Volumes | MMBTU		3,328,000
Gas Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	[2]	192,192,000
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | MMBTU	[1],[2]	(55,021,000)
Derivative, Nonmonetary Notional Amount, Energy Measure, Net of Purchased Volumes | MMBTU	[2]	137,171,000
Gas Swaps Contract 2017 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price | $ / EnergyContent		4.43
Derivative, Nonmonetary Notional Amount, Energy Measure, Sold Volumes | MMBTU		38,600,000
IF El Paso Permian [Member]
Derivative Financial Instruments
Index percent of natural gas fixed swaps		3.00%
IF HSC [Member]
Derivative Financial Instruments
Index percent of natural gas fixed swaps		94.00%
IF NNG Ventura [Member]
Derivative Financial Instruments
Index percent of natural gas fixed swaps		3.00%
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract First Quarter 2017 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		8.63
Derivative, Nonmonetary Notional Amount, Volume | bbl		847,000
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract Second Quarter 2017 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		8.86
Derivative, Nonmonetary Notional Amount, Volume | bbl		787,000
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract Third Quarter 2017 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		9.14
Derivative, Nonmonetary Notional Amount, Volume | bbl		736,000
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract Fourth Quarter 2017 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		9.10
Derivative, Nonmonetary Notional Amount, Volume | bbl		692,000
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract 2018 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		10.18
Derivative, Nonmonetary Notional Amount, Volume | bbl		2,434,000
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract 2019 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		11.95
Derivative, Nonmonetary Notional Amount, Volume | bbl		2,176,000
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract 2020 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		11.13
Derivative, Nonmonetary Notional Amount, Volume | bbl		539,000
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl		8,211,000
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract First Quarter 2017 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		21.90
Derivative, Nonmonetary Notional Amount, Volume | bbl		692,000
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Second Quarter 2017 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		21.90
Derivative, Nonmonetary Notional Amount, Volume | bbl		634,000
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter 2017 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		21.91
Derivative, Nonmonetary Notional Amount, Volume | bbl		588,000
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2017 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		21.91
Derivative, Nonmonetary Notional Amount, Volume | bbl		550,000
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2018 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		22.86
Derivative, Nonmonetary Notional Amount, Volume | bbl		1,442,000
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2019 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		0
Derivative, Nonmonetary Notional Amount, Volume | bbl		0
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2020 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		0
Derivative, Nonmonetary Notional Amount, Volume | bbl		0
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl		3,906,000
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract First Quarter 2017 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		30.69
Derivative, Nonmonetary Notional Amount, Volume | bbl		122,000
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Second Quarter 2017 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		30.69
Derivative, Nonmonetary Notional Amount, Volume | bbl		112,000
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter 2017 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		30.70
Derivative, Nonmonetary Notional Amount, Volume | bbl		104,000
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2017 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		30.70
Derivative, Nonmonetary Notional Amount, Volume | bbl		98,000
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2018 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		0
Derivative, Nonmonetary Notional Amount, Volume | bbl		0
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2019 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		0
Derivative, Nonmonetary Notional Amount, Volume | bbl		0
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2020 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		0
Derivative, Nonmonetary Notional Amount, Volume | bbl		0
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl		436,000
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract First Quarter 2017 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		31.12
Derivative, Nonmonetary Notional Amount, Volume | bbl		94,000
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Second Quarter 2017 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		31.12
Derivative, Nonmonetary Notional Amount, Volume | bbl		86,000
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter 2017 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		31.12
Derivative, Nonmonetary Notional Amount, Volume | bbl		80,000
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2017 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		31.12
Derivative, Nonmonetary Notional Amount, Volume | bbl		74,000
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2018 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		0
Derivative, Nonmonetary Notional Amount, Volume | bbl		0
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2019 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		0
Derivative, Nonmonetary Notional Amount, Volume | bbl		0
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2020 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		0
Derivative, Nonmonetary Notional Amount, Volume | bbl		0
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl		334,000
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract First Quarter 2017 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		47.54
Derivative, Nonmonetary Notional Amount, Volume | bbl		156,000
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract Second Quarter 2017 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		47.56
Derivative, Nonmonetary Notional Amount, Volume | bbl		143,000
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter 2017 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		47.59
Derivative, Nonmonetary Notional Amount, Volume | bbl		133,000
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2017 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		47.61
Derivative, Nonmonetary Notional Amount, Volume | bbl		124,000
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2018 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		0
Derivative, Nonmonetary Notional Amount, Volume | bbl		0
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2019 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		0
Derivative, Nonmonetary Notional Amount, Volume | bbl		0
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2020 [Member]
Derivative Financial Instruments
Weighted- Average Contract Price		0
Derivative, Nonmonetary Notional Amount, Volume | bbl		0
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl		556,000
Subsequent Event [Member] | NYMEX Oil Collar Contracts [Member]
Derivative Financial Instruments
Derivative, Floor Price			50
Derivative, Nonmonetary Notional Amount, Volume | bbl			2,700,000
Subsequent Event [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			1,100,000
Subsequent Event [Member] | Oil Basis Swap [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			3,700,000
Minimum [Member] | Subsequent Event [Member] | NYMEX Oil Collar Contracts [Member]
Derivative Financial Instruments
Derivative, Cap Price			57
Minimum [Member] | Subsequent Event [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Swap Type, Fixed Price			35.07
Minimum [Member] | Subsequent Event [Member] | Oil Basis Swap [Member]
Derivative Financial Instruments
Weighted Average Differential to WTI			(1.23)
Maximum [Member] | Subsequent Event [Member] | NYMEX Oil Collar Contracts [Member]
Derivative Financial Instruments
Derivative, Cap Price			58.40
Maximum [Member] | Subsequent Event [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Swap Type, Fixed Price			49.88
Maximum [Member] | Subsequent Event [Member] | Oil Basis Swap [Member]
Derivative Financial Instruments
Weighted Average Differential to WTI			(1.45)
[1]	During 2016, the Company restructured certain of its gas derivative contracts by buying fixed price volumes to offset existing 2018 and 2019 fixed price swap contracts totaling 55.0 million MMBtu. The Company then entered into new 2017 fixed price swap contracts totaling 38.6 million MMBtu with a contract price of $4.43 per MMBtu. No cash or other consideration was included as part of the restructuring.
[2]	Total net volumes of natural gas swaps are comprised of IF El Paso Permian (3%), IF HSC (94%), and IF NNG Ventura (3%).

Derivative Financial Instrume56

Derivative Financial Instruments Fair Value (Details) - USD ($) $ in Thousands	Dec. 31, 2016		Dec. 31, 2015
Fair value of derivative assets and liabilities
Derivative, Fair Value, Net	$ (91,708)		$ 488,403
Derivative Assets, Current	54,521		367,710
Derivative Liabilities, Current	115,464		8
Derivative Assets, Noncurrent	67,575		120,701
Derivative Liabilities, Noncurrent	98,340		0
Derivative Asset, Fair Value, Gross Asset	122,096		488,411
Derivative Liability, Fair Value, Gross Liability	213,804		8
Derivative Asset, Not Offset, Policy Election Deduction	(118,080)		(8)
Derivative Liability, Not Offset, Policy Election Deduction	118,080		8
Derivative Asset, Fair Value, Amount Offset Against Collateral, Net	4,016		488,403
Derivative Liability, Fair Value, Amount Offset Against Collateral, Net	(95,724)		0
Not Designated as Hedging Instrument [Member]
Fair value of derivative assets and liabilities
Derivative Assets, Current	54,521		367,710
Derivative Liabilities, Current	115,464		8
Derivative Assets, Noncurrent	67,575		120,701
Derivative Liabilities, Noncurrent	98,340		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair value of derivative assets and liabilities
Derivative Asset, Fair Value, Gross Asset	122,096	[1]	488,411	[2]
Derivative Liability, Fair Value, Gross Liability	213,804	[1]	8	[2]
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	122,096		488,411
Derivative Liability, Fair Value, Gross Liability	$ 213,804		$ 8
[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 Instrume57

Derivative Financial Instruments Gains and Losses (Details) $ in Thousands		12 Months Ended
		Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Derivative, (Gain) Loss on Derivative, Net [Abstract]
Derivative Settlement (Gain) Loss		$ (329,478)	$ (512,566)	$ (12,615)
Derivative Instruments Not Designated as Hedging Instruments, (Gain) Loss, Net		250,633	(408,831)	(583,264)
NYMEX Oil Contracts [Member]
Derivative, (Gain) Loss on Derivative, Net [Abstract]
Derivative Settlement (Gain) Loss		(243,102)	(362,219)	(28,410)
Derivative Instruments Not Designated as Hedging Instruments, (Gain) Loss, Net		85,370	(191,165)	(457,082)
Gas Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain on Early Settlement of Derivatives			15,300	5,600
Derivative, (Gain) Loss on Derivative, Net [Abstract]
Derivative Settlement (Gain) Loss	[1]	(94,936)	(123,180)	26,706
Derivative Instruments Not Designated as Hedging Instruments, (Gain) Loss, Net		81,060	(189,734)	(93,267)
NGL Contracts [Member]
Derivative, (Gain) Loss on Derivative, Net [Abstract]
Derivative Settlement (Gain) Loss		8,560	(27,167)	(10,911)
Derivative Instruments Not Designated as Hedging Instruments, (Gain) Loss, Net		$ 84,203	$ (27,932)	$ (32,915)
Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Number of Instruments Held		0	0	0
[1]	Natural gas derivative settlements for the years ended December 31, 2015, and 2014, include $15.3 million and $5.6 million, respectively, of early settlements of futures contracts as a result of divesting assets in the Company’s Mid-Continent region.

Derivative Financial Instrume58

Derivative Financial Instruments Credit Facility and Derivative Counterparties (Details)	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Percentage of Proved Oil and Gas Properties Secured for Credit Facility Borrowing	90.00%

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2016		Dec. 31, 2015
Assets:
Derivatives	$ 122,096		$ 488,411
Property, Plant and Equipment, Other, Net	137,753		153,100
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	213,804		8
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Assets:
Derivatives	0	[1]	0	[2]
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	[1]	0	[2]
Net Profits Plan Liability Noncurrent	0	[1]	0	[2]
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Assets:
Derivatives	122,096	[1]	488,411	[2]
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	213,804	[1]	8	[2]
Net Profits Plan Liability Noncurrent	0	[1]	0	[2]
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Assets:
Derivatives	0	[1]	0	[2]
Liabilities [Abstract]
Derivative Liability, Fair Value, Gross Liability	0	[1]	0	[2]
Net Profits Plan Liability Noncurrent	411	[1]	7,611	[2]
Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 1 [Member]
Assets:
Property, Plant and Equipment, Other, Net	0	[3]	0	[4]
Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 2 [Member]
Assets:
Property, Plant and Equipment, Other, Net	0	[3]	0	[4]
Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member]
Assets:
Property, Plant and Equipment, Other, Net	$ 88,205	[3]	$ 124,813	[4]
[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.
[4]	This represents a non-financial asset that is measured at fair value on a nonrecurring basis.

Fair Value Measurements (Deta60

Fair Value Measurements (Details 2) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Sep. 12, 2016	Aug. 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		$ 354,614	$ 468,679	$ 84,480
Abandonment and impairment of unproved properties		80,367	78,643	75,638
Impairment of other property and equipment		$ 0	49,369	0
Oil and Gas Properties [Member]
Proved Oil and Gas Properties
Period of New York Mercantile Exchange Strip Pricing Used for Price Forecast		5 years
Fair Value, Inputs, Level 3 [Member] | Fair Value, Measurements, Nonrecurring [Member] | Net Profit Plan liability [Member]
Fair Value, NPP Reconciliation, Calculation [Roll Forward]
Net Profits Plan Liability: Beginning Balance		$ 7,611	27,136	56,985
Net increase (decrease) in liability	[1]	23,757	(12,238)	(12,492)
Net settlements	[1],[2]	(30,957)	(7,287)	(17,357)
Transfers in (out) of Level 3		0	0	0
Net Profits Plan Liability: Ending balance		$ 411	7,611	$ 27,136
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]
Debt Instrument, Face Amount		$ 2,803,736	2,350,000
Senior Notes [Member] | 6.50% Senior Notes Due 2021 [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Debt Instrument, Interest Rate, Stated Percentage		6.50%									6.50%
Debt Instrument, Face Amount		$ 346,955	350,000								$ 350,000
Long-term Debt, Fair Value		$ 354,546	262,938
Senior Notes [Member] | 6.125% Senior Notes Due 2022 [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Debt Instrument, Interest Rate, Stated Percentage		6.125%						6.125%
Debt Instrument, Face Amount		$ 561,796	600,000					$ 600,000
Long-term Debt, Fair Value		$ 570,925	440,250
Senior Notes [Member] | 6.50% Senior Notes Due 2023 [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Debt Instrument, Interest Rate, Stated Percentage		6.50%								6.50%
Debt Instrument, Face Amount		$ 394,985	400,000							$ 400,000
Long-term Debt, Fair Value		$ 403,134	296,000
Senior Notes [Member] | 5% Senior Notes Due 2024 [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Debt Instrument, Interest Rate, Stated Percentage		5.00%							5.00%
Debt Instrument, Face Amount		$ 500,000	500,000						$ 500,000
Long-term Debt, Fair Value		$ 475,975	334,065
Senior Notes [Member] | 5.625% Senior Notes Due 2025 [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Debt Instrument, Interest Rate, Stated Percentage		5.625%					5.625%
Debt Instrument, Face Amount		$ 500,000	500,000				$ 500,000
Long-term Debt, Fair Value		$ 485,000	326,875
Senior Notes [Member] | 6.75% Senior Notes Due 2026 [Member]
Debt Instrument, Fair Value Disclosure [Abstract]
Debt Instrument, Interest Rate, Stated Percentage		6.75%			6.75%
Debt Instrument, Face Amount		$ 500,000	0		$ 500,000
Long-term Debt, Fair Value		$ 516,565	0
Convertible Debt [Member] | 1.50% Senior Convertible Notes Due 2021 [Domain]
Debt Instrument, Fair Value Disclosure [Abstract]
Debt Instrument, Interest Rate, Stated Percentage		1.50%				1.50%
Debt Instrument, Face Amount		$ 172,500	0			$ 172,500
Long-term Debt, Fair Value		$ 202,189	$ 0
[1]	Net changes in the Company’s Net Profits Plan liability are shown in the change in Net Profits Plan liability line item of the accompanying statements of operations.
[2]	Settlements represent cash payments made or accrued under the Net Profits Plan and are recognized as compensation expense or a reduction to the net gain on divestiture activity line in the accompanying statements of operations, as discussed in Note 7 – Compensation Plans.

Acquisition and Development A61

Acquisition and Development Agreement and Carry and Earning Agreement (Details) - Mitsui E&P Texas LP $ in Millions	Jun. 30, 2011USD ($)
Acquisition and Development Agreement [Abstract]
Percentage of Working Interests Transferred to Acquirer Entity	12.50%
Acreage of Working Interests Transferred to Acquirer Entity	39,000
Percentage of the entity's costs and expenses during the first three years following the closing of the transaction, borne by the acquirer entity (as a percent)	90.00%
Costs and expenses incurred by acquiree entity on behalf of entity that the acquirer entity has agreed to pay	$ 680
Portion of Drilling and Completion Costs Not Carried by Acquirer	10.00%

Suspended Well Costs Suspende62

Suspended Well Costs Suspended Well Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Capitalized Exploratory Well Costs Beginning Balance	$ 11,952	$ 43,589	$ 34,527
Capitalized Exploratory Well Cost, Additions Pending Determination of Proved Reserves	19,846	11,952	43,589
Capitalized Exploratory Well Cost, Divestitures	0	(809)	0
Reclassification to Well, Facilities, and Equipment Based on Determination of Proved Reserves	(11,952)	(18,485)	(33,340)
Capitalized Exploratory Well Cost Charged to Expense	0	(24,295)	(1,187)
Capitalized Exploratory Well Costs Ending Balance	19,846	$ 11,952	$ 43,589
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year	$ 0

Exit and Disposal Costs (Detail

Exit and Disposal Costs (Details) - USD ($) $ in Thousands		12 Months Ended		18 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Jun. 30, 2017
Restructuring Cost and Reserve [Line Items]
Business Exit Costs		$ 5,100
Contractual Obligation	[1]	1,058,103
Scenario, Forecast [Member]
Restructuring Cost and Reserve [Line Items]
Business Exit Costs				$ 7,600
Office Space Leases [Member]
Restructuring Cost and Reserve [Line Items]
Gain (Loss) on Contract Termination		3,200
Contractual Obligation		50,100
Mid Continent Divestiture 2015 [Member]
Restructuring Cost and Reserve [Line Items]
Business Exit Costs			$ 9,300
Mid Continent Divestiture 2015 [Member] | Office Space Leases [Member]
Restructuring Cost and Reserve [Line Items]
Contractual Obligation		$ 3,800
[1]	During the third quarter of 2015, the Company closed its office in Tulsa, Oklahoma. These amounts include lease payments for the Tulsa office, net of sublease income. The Company expects to receive $2.7 million of total sublease income through 2019.

Equity (Details)

Equity (Details) - USD ($) $ / shares in Units, $ in Thousands, shares in Millions		Dec. 21, 2016	Dec. 07, 2016	Aug. 12, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Class of Stock [Line Items]
Proceeds from Issuance of Common Stock					$ 938,268	$ 4,844	$ 4,877
Value of common stock from issuance of private placement for an asset acquisition	[1]				$ 437,194	$ 0	$ 0
August Issuance [Member]
Class of Stock [Line Items]
Stock Issued During Period, Shares, New Issues				18.4
Sale of Stock, Price Per Share				$ 30
Proceeds from Issuance of Common Stock				$ 530,900
December Issuance [Member]
Class of Stock [Line Items]
Stock Issued During Period, Shares, New Issues			10.9
Sale of Stock, Price Per Share			$ 38.25
Proceeds from Issuance of Common Stock			$ 403,200
QStar Acquisition 2016 [Member]
Class of Stock [Line Items]
Private Issuance Of Common Stock For An Acquisition		13.4
Value of common stock from issuance of private placement for an asset acquisition	[2]	$ 437,194
[1]	Refer to Note 3 - Acquisitions, Divestitures, and Assets Held for Sale and Note 15 - Equity for additional discussion.
[2]	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 prohibits the sale of such stock until no earlier than the 90th day after issuance.