SM Energy (SM) 10-Q 4 May 17 2017 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information Document - shares	3 Months Ended
	Mar. 31, 2017	Apr. 26, 2017
Entity Information [Line Items]
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-Q
Document Period End Date	Mar. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding		111,258,225
Entity Current Reporting Status	Yes

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) (in thousands, except share amounts) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Assets
Cash and cash equivalents	$ 659,147	$ 9,372
Accounts receivable	108,368	151,950
Derivative asset	73,978	54,521
Prepaid expenses and other	8,053	8,799
Total current assets	849,546	224,642
Proved oil and gas properties	4,803,068	5,700,418
Less - accumulated depletion, depreciation, and amortization	(2,589,204)	(2,836,532)
Unproved oil and gas properties	2,483,601	2,471,947
Wells in progress	186,707	235,147
Oil and gas properties held for sale, net	455,943	372,621
Other property and equipment, net of accumulated depreciation of $44,662 and $42,882, respectively	110,005	137,753
Total property and equipment, net	5,450,120	6,081,354
Derivative asset	84,195	67,575
Other noncurrent assets	15,847	19,940
Total other noncurrent assets	100,042	87,515
Total Assets	6,399,708	6,393,511
Liabilities
Accounts payable and accrued expenses	299,676	299,708
Derivative liability	53,809	115,464
Total current liabilities	353,485	415,172
Revolving credit facility	0	0
Senior Notes, net of unamortized deferred financing costs	2,765,714	2,766,719
Senior Convertible Notes, net of unamortized discount and deferred financing costs	132,889	130,856
Asset retirement obligation	83,160	96,134
Asset retirement obligation associated with oil and gas properties held for sale	16,056	26,241
Deferred income taxes	304,331	315,672
Derivative liability	81,306	98,340
Other noncurrent liabilities	47,252	47,244
Total noncurrent liabilities	3,430,708	3,481,206
Commitments and contingencies (note 6)
Stockholders' equity:
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding; 111,258,225 and 111,257,500 shares, respectively	1,113	1,113
Additional paid-in-capital	1,723,010	1,716,556
Retained earnings	906,515	794,020
Accumulated other comprehensive loss	(15,123)	(14,556)
Total stockholders' equity	2,615,515	2,497,133
Total Liabilities and Stockholders' Equity	$ 6,399,708	$ 6,393,511

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets Parenthetical - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Property, Plant and Equipment, Other, Accumulated Depreciation	$ 44,662	$ 42,882
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	111,258,225	111,257,500
Common Stock, Shares, Outstanding	111,258,225	111,257,500

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED) (in thousands, except per share amounts) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Operating revenues:
Oil, gas, and NGL production revenue	$ 333,198	$ 211,823
Net gain (loss) on divestiture activity	37,463	(69,021)
Other operating revenues	2,077	274
Total operating revenues and other income	372,738	143,076
Operating expenses:
Oil, gas, and NGL production expense	138,046	144,543
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	137,812	214,207
Exploration	11,978	15,273
Impairment of proved properties	0	269,785
Abandonment and impairment of unproved properties	0	2,311
General and administrative	29,224	32,238
Net derivative gain	(114,774)	(14,228)
Other operating expenses	4,859	5,672
Total operating expenses	207,145	669,801
Income (loss) from operations	165,593	(526,725)
Non-operating income (expense):
Interest expense	(46,953)	(31,088)
Gain (loss) on extinguishment of debt	(35)	15,722
Other, net	335	6
Income (loss) before income taxes	118,940	(542,085)
Income tax (expense) benefit	(44,506)	194,875
Net income (loss)	$ 74,434	$ (347,210)
Basic weighted-average common shares outstanding	111,258	68,077
Diluted weighted-average common shares outstanding	111,329	68,077
Basic net income (loss) per common share	$ 0.67	$ (5.10)
Diluted net income (loss) per common share	0.67	(5.10)
Dividends per common share	$ 0.05	$ 0.05

CONDENSED CONSOLIDATED STATEME5

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED) (in thousands) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 74,434	$ (347,210)
Pension liability adjustment	(567)	(236)
Total other comprehensive loss, net of tax	(567)	(236)
Total comprehensive income (loss)	$ 73,867	$ (347,446)

CONDENSED CONSOLIDATED STATEME6

CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (UNAUDITED) (in thousands, except share amounts) - 3 months ended Mar. 31, 2017 - USD ($) $ in Thousands		Total	Common Stock	Additional Paid-in Capital	Retained Earnings	Accumulated Other Comprehensive Loss
Common Stock, Dividends, Per Share, Declared		$ 0.05
Balances, Common Shares, Beginning at Dec. 31, 2016		111,257,500	111,257,500
Balances, Beginning at Dec. 31, 2016		$ 2,497,133	$ 1,113	$ 1,716,556	$ 794,020	$ (14,556)
Increase (Decrease) in Stockholders' Equity
Net income		74,434			74,434
Other Comprehensive Loss		(567)				(567)
Dividends declared, $0.05 per share		(5,563)			(5,563)
Issuance of common stock upon vesting of restricted stock units, net of shares used for tax withholdings (in shares)			725
Issuance of common stock upon vesting of restricted stock units, net of shares used for tax withholdings		(11)		(11)
Stock-based compensation expense		5,455		5,455
Cumulative effect of accounting change	[1]	44,732		1,108	43,624
Other Adjustments to Additional Paid in Capital		$ (98)		(98)
Balances, Common Shares, Ending at Mar. 31, 2017		111,258,225	111,258,225
Balances, Ending at Mar. 31, 2017		$ 2,615,515	$ 1,113	$ 1,723,010	$ 906,515	$ (15,123)
[1]	Refer to Note 2 - Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards.

CONDENSED CONSOLIDATED STATEME7

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (in thousands) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Cash flows from operating activities:
Net income (loss)	$ 74,434	$ (347,210)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net (gain) loss on divestiture activity	(37,463)	69,021
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	137,812	214,207
Impairment of proved properties	0	269,785
Abandonment and impairment of unproved properties	0	2,311
Stock-based compensation expense	5,455	6,868
Net derivative gain	(114,774)	(14,228)
Derivative settlement gain	7	147,028
Amortization of discount and deferred financing costs	4,946	(920)
Non-cash (gain) loss on extinguishment of debt, net	22	(15,722)
Deferred income taxes	33,225	(195,039)
Plugging and abandonment	(1,191)	(604)
Other, net	4,567	(1,151)
Changes in current assets and liabilities:
Accounts receivable	30,407	26,922
Prepaid expenses and other	178	4,984
Accounts payable and accrued expenses	(5,497)	(52,294)
Accrued derivative settlements	2,838	4,318
Net cash provided by operating activities	134,966	118,276
Cash flows from investing activities:
Net proceeds from the sale of oil and gas properties	744,333	1,206
Capital expenditures	(154,401)	(176,370)
Acquisition of proved and unproved oil and gas properties	(75,105)	(15,044)
Other, net	2,486	885
Net cash provided by (used in) investing activities	517,313	(189,323)
Cash flows from financing activities:
Proceeds from credit facility	397,500	317,000
Repayment of credit facility	(397,500)	(226,000)
Cash paid to repurchase Senior Notes	2,344	19,917
Other, net	(160)	(3)
Net cash provided by (used in) financing activities	(2,504)	71,080
Net change in cash and cash equivalents	649,775	33
Cash and cash equivalents at beginning of period	9,372	18
Cash and cash equivalents at end of period	659,147	51
Supplemental schedule of additional cash flow information and non-cash activities:
Cash paid for interest, net of capitalized interest	(42,872)	(24,453)
Net cash refunded for income taxes	15	4,689
Changes in capital expenditure accruals and other	27,214	20,643
Fair value of properties exchanged	24,544	733
Dividends declared, but not paid	$ 5,563	$ 3,404

The Company and Business

The Company and Business	3 Months Ended
	Mar. 31, 2017
Company and Business Disclosure [Abstract]
The Company and Business	Note 1 - The Company and Business SM Energy Company, together with its consolidated subsidiaries (“SM Energy” or the “Company”), is an independent energy company engaged in the acquisition, exploration, development, and production of crude oil and condensate, natural gas, and natural gas liquids (also respectively referred to as “oil,” “gas,” and “NGLs” throughout this report) in onshore North America.

Basis of Presentation, Signific

Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards	3 Months Ended
	Mar. 31, 2017
Basis of Presentation and Significant Accounting Policies [Abstract]
Basis of Presentation and Significant Accounting Policies [Text Block]	Note 2 - Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards Basis of Presentation The accompanying unaudited condensed consolidated financial statements include the accounts of SM Energy and its wholly-owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and the instructions to Quarterly Report on Form 10-Q and Regulation S-X. These financial statements do not include all information and notes required by GAAP for annual financial statements. However, except as disclosed herein, there has been no material change in the information disclosed in the notes to consolidated financial statements included in SM Energy’s Annual Report on Form 10-K for the year ended December 31, 2016 (the “ 2016 Form 10-K”). In the opinion of management, all adjustments, consisting of normal recurring adjustments considered necessary for a fair presentation of interim financial information, have been included. Operating results for the periods presented are not necessarily indicative of expected results for the full year. In connection with the preparation of the Company’s unaudited condensed consolidated financial statements, the Company evaluated events subsequent to the balance sheet date of March 31, 2017 , and through the filing of this report. Certain prior period amounts have been reclassified to conform to the current presentation on the accompanying condensed consolidated financial statements. Significant Accounting Policies The significant accounting policies followed by the Company are set forth in Note 1 to the Company’s consolidated financial statements in its 2016 Form 10-K, and are supplemented by the notes to the unaudited condensed consolidated financial statements in this report. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes included in the 2016 Form 10-K. Recently Issued Accounting Standards Effective January 1, 2017, the Company adopted, using various transition methods, Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). ASU 2016-09 is meant to simplify certain aspects of accounting for share-based payment arrangements, including income tax effects, accounting for forfeitures, and net share settlements. The Company adopted the various applicable amendments as summarized below: • ASU 2016-09 requires all future excess tax benefits and deficiencies related to share-based payment arrangements to be recognized as income tax benefit or expense as discrete events in the period in which they occur. The Company adopted this amendment under a modified retrospective transition method, which resulted in a $44.3 million cumulative-effect adjustment to retained earnings as of January 1, 2017, with a corresponding deferred tax asset recorded for previously unrecognized excess tax benefits. Consequentially, the Company’s diluted share count calculation changed prospectively beginning in the period ended March 31, 2017. Any future excess tax benefits and deficiencies are now being excluded from the assumed proceeds calculated under the treasury stock method for share-based payment arrangements. Lastly, this amendment requires companies to present excess tax benefits as an operating activity on the statement of cash flows rather than as a financing activity, which the Company applied prospectively beginning in the period ended March 31, 2017. There are no periods presented that would require reclassification of cash flows had the Company elected to apply this amendment retrospectively. • ASU 2016-09 allows entities to elect whether to account for forfeitures of share-based payment awards by recognizing forfeitures of awards as they occur or by estimating the number of awards expected to be forfeited. This amendment is to be applied using a modified retrospective transition method. Upon adopting ASU 2016-09, the Company elected to change its policy to account for forfeitures of share-based payment awards as they occur effective January 1, 2017. This change in accounting policy resulted in a net $0.7 million cumulative-effect adjustment to retained earnings as of January 1, 2017, to adjust for actual forfeitures versus the previously estimated forfeiture rate. The corresponding impacts were an increase in additional paid-in capital and a decrease in deferred tax assets. • ASU 2016-09 allows entities to withhold an amount up to the employees’ maximum individual tax rate in the relevant jurisdiction, without triggering liability classification of the award; however, the Company does not plan on changing its current withholding process as outlined in its share-based award agreements. Related to this amendment, ASU 2016-09 requires entities to present cash payments made to tax authorities on the employees’ behalf for withheld tax shares as a financing activity on the statement of cash flows retrospectively. However, this presentation is already consistent with the Company’s historical and current cash flow presentation of net share settlement from issuance of stock awards, and therefore, there was no impact from this amendment. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) for the recognition of revenue from contracts with customers. Several additional related ASUs have been issued. 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. The Company is currently establishing a cross-functional implementation team to analyze the impact of the standard on the Company’s contract portfolio by reviewing current accounting policies and practices to identify potential differences that would result from applying the requirements of the new standard. In addition, the Company is working to identify appropriate changes to the Company’s business processes, systems, and controls to support recognition and disclosure under the new standard. The Company currently plans to adopt the guidance on the effective date of January 1, 2019. In March 2017, the FASB issued ASU No. 2017-07, Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (“ASU 2017-07”). This ASU is intended to improve the presentation of net periodic pension cost and net periodic postretirement benefit cost by providing additional guidance on the presentation of net benefit cost on the income statement and on the components eligible for capitalization in assets. As outlined in ASU 2017-07, certain amendments are to be applied using a retrospective method while others are required to be applied using a prospective 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 outlined in ASU 2017-07. The Company is currently evaluating the provisions of this guidance and assessing the potential impact on the Company’s financial statements and disclosures and does not intend to early adopt this guidance. Other than as disclosed above or in the 2016 Form 10-K, there are no other accounting standards applicable to the Company that would have a material effect on the Company’s financial statements and related disclosures that have been issued but not yet adopted by the Company as of March 31, 2017 , and through the filing of this report.

Divestitures, Assets Held for S

Divestitures, Assets Held for Sale, and Acquisitions	3 Months Ended
	Mar. 31, 2017
Divestitures, Assets Held for Sale, and Acquisitions [Abstract]
Divestitures, Assets Held for Sale, and Acquisitions	Note 3 – Divestitures, Assets Held for Sale, and Acquisitions Divestitures On March 10, 2017 , the Company divested its outside-operated Eagle Ford shale assets, including ownership interest in related midstream assets, for total cash received at closing, net of commissions (referred to throughout this report as “net divestiture proceeds”), of $747.4 million , subject to post-closing adjustments, and recorded a net estimated gain of $398.1 million for the three months ended March 31, 2017 . These assets were classified as held for sale as of December 31, 2016 . The following table presents income (loss) before income taxes of the outside-operated Eagle Ford shale assets sold for the three months ended March 31, 2017 , and 2016 . This divestiture is considered a disposal of a significant asset group. For the Three Months Ended March 31, 2017 2016 (in thousands) Income (loss) before income taxes (1) $ 24,324 $ (286,399 ) ____________________________________________ (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 included impairment of proved properties expense of approximately $269.6 million for the three months ended March 31, 2016. 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 estimated 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 (loss) on divestiture activity line item in the accompanying condensed consolidated statements of operations (“accompanying statements of operations”). As of March 31, 2017 , the accompanying condensed consolidated balance sheets (“accompanying balance sheets”) present $455.9 million of assets held for sale, net of accumulated depletion, depreciation, and amortization expense, which consisted primarily of the Company’s remaining Williston Basin assets in Divide County, North Dakota (referred to as “Divide County” throughout this report). A corresponding asset retirement obligation liability of $16.1 million was separately presented. The Company expects to close the divestiture of these assets during the second quarter of 2017. These assets were written down by $359.6 million to reflect fair value less estimated costs to sell upon classification as held for sale during the three months ended March 31, 2017 . The following table presents loss before income taxes of the Company’s Divide County assets held for sale for the three months ended March 31, 2017 , and 2016 : For the Three Months Ended March 31, 2017 2016 (in thousands) Loss before income taxes (1) $ (335,561 ) $ (16,813 ) ____________________________________________ (1) 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, loss before income taxes for the three months ended March 31, 2017, included the $359.6 million write-down on these assets held for sale as discussed above, and loss before income taxes for the three months ended March 31, 2016, included $1.6 million of unproved property impairments. Acquisitions During the first quarter of 2017, the Company acquired approximately 2,900 net acres of proved and unproved properties in the Midland Basin for $59.6 million , subject to post-closing adjustments. Under authoritative accounting guidance, this 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 finalized the 2016 acquisition of Midland Basin properties from Rock Oil Holdings, LLC (referred to as the “Rock Oil Acquisition”) during the first quarter of 2017 by paying an additional $7.4 million of cash consideration, resulting in total consideration of $998.4 million paid after final closing adjustments. There were no material changes to the recorded basis of the proved and unproved properties acquired as a result of the final settlement. Also, during the first quarter of 2017, and subsequent to March 31, 2017, the Company completed trades of properties, primarily unproved, in Howard and Martin Counties, Texas resulting in the Company acquiring approximately 3,020 net acres in exchange for 2,310 net acres. There was no cash consideration for the trade that was completed during the three months ended March 31, 2017, and this trade was recorded at the fair value of the assets surrendered with no gain or loss recognized.

Income Taxes

Income Taxes	3 Months Ended
	Mar. 31, 2017
Income Tax Disclosure [Abstract]
Income Taxes	Note 4 - Income Taxes The income tax (expense) benefit recorded for the three months ended March 31, 2017 , and 2016 , differs from the amounts that would be provided by applying the statutory United States federal income tax rate to income or loss before income taxes primarily due to the effect of state income taxes, changes in valuation allowances, excess tax benefits and deficiencies from share-based payment awards, and accumulated impacts of other smaller permanent differences. The quarterly rate can also be affected by the proportional impacts of forecasted net income or loss as of each period end presented. The provision for income taxes for the three months ended March 31, 2017, and 2016, consisted of the following: For the Three Months Ended March 31, 2017 2016 (in thousands) Current portion of income tax (expense) benefit: Federal $ (7,439 ) $ — State (3,842 ) (164 ) Deferred portion of income tax (expense) benefit (33,225 ) 195,039 Income tax (expense) benefit $ (44,506 ) $ 194,875 Effective tax rate 37.4 % 35.9 % On a year-to-date basis, a change in the Company’s effective tax rate between reported periods will generally reflect differences in its estimated highest marginal state tax rate due to changes in the composition of income or loss from Company activities among multiple state tax jurisdictions. Cumulative effects of state tax rate changes are reflected in the period that legislation is enacted. As a result of adopting ASU 2016-09, excess tax benefits and deficiencies from share-based payment awards are expected to impact the Company’s effective tax rate between periods. Please refer to Note 2 - Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards . The change in the current portion of income tax expense relates to the effect of anticipated utilization of carryover net operating losses, deferred expenses, and carryover tax credits. The Company is generally no longer subject to United States federal or state income tax examinations by tax authorities for years before 2013, with the exception of its 2003 tax year.

Long-Term Debt

Long-Term Debt	3 Months Ended
	Mar. 31, 2017
Debt Disclosure [Abstract]
Long-term Debt [Text Block]	Note 5 - Long-Term Debt Credit Facility The Company’s Fifth Amended and Restated Credit Agreement, as amended (the “Credit Agreement”), provides for a maximum loan amount of $2.5 billion and has a maturity date of December 10, 2019 . On March 31, 2017 , the Company entered into a Ninth Amendment to the Credit Agreement (the “Ninth Amendment”) with its lenders. Pursuant to the Ninth Amendment, and as part of the regular, semi-annual borrowing base redetermination process, the borrowing base and aggregate lender commitments were reduced to $925 million . This expected reduction was primarily due to the sale of the Company’s outside-operated Eagle Ford shale assets in the first quarter of 2017 and the decrease in the value of the Company’s proved reserves at 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. Additionally, the Ninth Amendment modified the Credit Agreement to allow the Company to enter into derivative contracts for an increased percentage of projected production volumes. As a result of the reduction to the Company’s borrowing base and aggregate lender commitments, the Company recorded approximately $1.1 million of expense related to the acceleration of unamortized deferred financing costs for the three months ended March 31, 2017 . The next scheduled redetermination date is October 1, 2017 . 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 March 31, 2017 , and through the filing of this report. Interest and commitment fees are accrued based on a borrowing base utilization grid set forth in the Credit Agreement and presented in Note 5 – Long-Term Debt to the Company’s consolidated financial statements in its 2016 Form 10-K. Eurodollar loans accrue interest at the London Interbank Offered Rate plus the applicable margin from the utilization table, and Alternate Base Rate and swingline loans accrue interest at the prime rate, plus the applicable margin from the utilization table. 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 following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Credit Agreement as of April 26, 2017 , March 31, 2017 , and December 31, 2016 : As of April 26, 2017 As of March 31, 2017 As of December 31, 2016 (in thousands) Credit facility balance (1) $ — $ — $ — Letters of credit (2) 200 200 200 Available borrowing capacity 924,800 924,800 1,164,800 Total aggregate lender commitment amount $ 925,000 $ 925,000 $ 1,165,000 ____________________________________________ (1) Unamortized deferred financing costs attributable to the credit facility are presented as a component of other noncurrent assets on the accompanying balance sheets and totaled $4.3 million and $5.9 million as of March 31, 2017 , and December 31, 2016 , respectively. (2) Letters of credit outstanding reduce the amount available under the credit facility on a dollar-for-dollar basis. Senior Notes The Company’s Senior Notes consist of 6.50% Senior Notes due 2021, 6.125% Senior Notes due 2022, 6.50% Senior Notes due 2023, 5.0% Senior Notes due 2024, 5.625% Senior Notes due 2025, and 6.75% Senior Notes due 2026 (collectively referred to as “Senior Notes”). The Senior Notes, net of unamortized deferred financing costs line on the accompanying balance sheets as of March 31, 2017 , and December 31, 2016 , consisted of the following: As of March 31, 2017 As of December 31, 2016 Principal Amount Unamortized Deferred Financing Costs Senior Notes, Net of Unamortized Deferred Financing Costs Principal Amount Unamortized Deferred Financing Costs Senior Notes, Net of Unamortized Deferred Financing Costs (in thousands) 6.50% Senior Notes due 2021 (1) (2) $ 344,611 $ 3,176 $ 341,435 $ 346,955 $ 3,372 $ 343,583 6.125% Senior Notes due 2022 (2) 561,796 6,684 555,112 561,796 6,979 554,817 6.50% Senior Notes due 2023 (2) 394,985 4,254 390,731 394,985 4,436 390,549 5.0% Senior Notes due 2024 500,000 6,302 493,698 500,000 6,533 493,467 5.625% Senior Notes due 2025 500,000 7,393 492,607 500,000 7,619 492,381 6.75% Senior Notes due 2026 500,000 7,869 492,131 500,000 8,078 491,922 Total $ 2,801,392 $ 35,678 $ 2,765,714 $ 2,803,736 $ 37,017 $ 2,766,719 ____________________________________________ (1) During the first quarter of 2017, the Company repurchased a total of $2.3 million in aggregate principal amount of 6.50% Senior Notes due 2021 in open market transactions at a slight premium. The Company canceled all of these repurchased Senior Notes upon cash settlement. (2) During the first quarter of 2016, the Company repurchased a total of $46.3 million in aggregate principal amount of certain of its Senior Notes in open market transactions for a settlement amount of $29.9 million , excluding interest, of which $19.9 million was paid during the three months ended March 31, 2016, with the remaining $10.0 million settlement amount being accrued at March 31, 2016, and paid in the second quarter of 2016. The Company recorded a net gain on extinguishment of debt of approximately $15.7 million for the three months ended March 31, 2016. This amount includes a gain of approximately $16.4 million associated with the discount realized upon repurchase, which was partially offset by approximately $0.7 million related to the acceleration of unamortized deferred financing costs. The Company canceled all of these repurchased Senior Notes upon cash settlement. 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 and was in compliance with all covenants as of March 31, 2017 , and through the filing of this report. 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. Senior Convertible Notes On August 12, 2016 , the Company issued $172.5 million in aggregate principal amount of 1.50% Senior Convertible Notes due July 1, 2021 (the “Senior Convertible Notes”). The Senior Convertible Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt, and are senior in right of payment to any future subordinated debt. The Senior Convertible Notes mature on July 1, 2021 , unless earlier converted. Holders may convert their Senior Convertible Notes at their option at any time prior to January 1, 2021, only under certain circumstances as outlined in the indenture governing the Senior Convertible Notes and in Note 5 – Long-Term Debt to the Company’s consolidated financial statements in its 2016 Form 10-K. On or after January 1, 2021, until the maturity date, holders may convert their Senior Convertible Notes at any time. The Company may not redeem the Senior Convertible Notes prior to the maturity date. Upon conversion, the Senior Convertible Notes may be settled, at the Company’s election, in shares of the Company’s common stock, cash, or a combination of cash and common stock. Holders may convert their notes based on a conversion rate of 24.6914 shares of the Company’s common stock per $1,000 principal amount of the Senior Convertible Notes, which is equal to an initial conversion price of approximately $40.50 per share, subject to adjustment. The Company has initially elected a net-settlement method to satisfy its conversion obligation. Under the net-settlement method, upon conversion, the Senior Convertible Notes will 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 Senior Convertible Notes were not convertible at the option of holders as of March 31, 2017 , or through the filing of this report. Notwithstanding the inability to convert, the if-converted value of the Senior Convertible Notes as of March 31, 2017 , did not exceed the principal amount. At issuance, the Company recorded $132.3 million as the initial carrying amount of the debt component, which approximated its fair value at issuance, and was estimated by using an interest rate for nonconvertible debt with terms similar to the Senior Convertible Notes. The effective interest rate used was 7.25 percent . The $40.2 million excess of the principal amount of the Senior Convertible Notes over the fair value of the debt component was recorded as a debt discount and a corresponding increase in additional paid-in capital. The 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. Interest expense recognized on the Senior Convertible Notes related to the stated interest rate and amortization of the debt discount totaled $2.4 million for the three months ended March 31, 2017 . The net carrying amount of the liability component of the Senior Convertible Notes, as reflected on the accompanying balance sheets as of March 31, 2017 , and December 31, 2016 , consisted of the following: As of March 31, 2017 As of December 31, 2016 (in thousands) Principal amount of Senior Convertible Notes $ 172,500 $ 172,500 Unamortized debt discount (35,713 ) (37,513 ) Unamortized deferred financing costs (3,898 ) (4,131 ) Net carrying amount $ 132,889 $ 130,856 The Company is subject to certain covenants under the indenture governing the Senior Convertible Notes and was in compliance with all covenants as of March 31, 2017 , and through the filing of this report. Capped Call Transactions In connection with the issuance of the Senior Convertible Notes, the Company entered into capped call transactions with affiliates of the underwriters of such issuance. The capped call transactions are generally expected to reduce the potential dilution upon conversion of the Senior Convertible Notes and/or partially offset any cash payments the Company is required to make in excess of the principal amount of converted Senior Convertible Notes in the event that the market price per share of the Company’s common stock is greater than the strike price of the capped call transactions, which initially corresponds to the approximate $40.50 per share conversion price of the Senior Convertible Notes. The cap price of the capped call transactions is initially $60.00 per share. If the market price per share exceeds the cap price of the capped call transactions, there could be dilution or there would not be an offset of such potential cash payments.

Commitments and Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 6 - Commitments and Contingencies Commitments During the first quarter of 2017, the Company completed the divestiture of its outside-operated Eagle Ford shale assets. Upon closing of the sale, the Company is no longer subject to gathering, processing, and 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 as of December 31, 2016. As of March 31, 2017 , the Company had total gathering, processing, and transportation throughput commitments with various third parties that require delivery of a minimum amount of 915 Bcf of natural gas, 17 MMBbl of crude oil, and 25 MMBbl of water through 2028. If the Company delivers no product, the aggregate undiscounted deficiency payments total approximately $458.8 million . As of the filing of this report, the Company does not expect to incur any material shortfalls with regard to its remaining gathering, processing, and transportation throughput commitments. Additionally, the Company entered into drilling rig contracts during the first quarter of 2017, and subsequent to March 31, 2017. As of the filing of this report, the Company’s total drilling rig commitment was $30.1 million ; however, if the Company terminated these rig contracts early, penalties of $19.0 million would be incurred instead. There were no other material changes in commitments during the first quarter of 2017 . Please refer to Note 6 - Commitments and Contingencies in the Company’s 2016 Form 10-K for additional discussion of the Company’s commitments. 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 expected results of any 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	3 Months Ended
	Mar. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Compensation Plans	Note 7 - Compensation Plans Performance Share Units Under the Equity Incentive Compensation Plan The Company grants performance share units (“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 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. For the three months ended March 31, 2017 , and 2016 , total compensation expense recorded for PSUs was $2.5 million and $2.9 million , respectively, within general and administrative and exploration expense. As of March 31, 2017 , there was $14.2 million of total unrecognized compensation expense related to unvested PSU awards, which is being amortized through 2019 . There have been no material changes to the outstanding and non-vested PSUs during the three months ended March 31, 2017 . Restricted Stock Units Under the Equity Incentive Compensation Plan The Company grants restricted stock units (“RSUs”) as part of its long-term equity 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. For the three months ended March 31, 2017 , and 2016 , total compensation expense recorded for RSUs was $2.5 million and $3.2 million , respectively, within general and administrative expense and exploration expense. As of March 31, 2017 , there was $12.9 million of total unrecognized compensation expense related to unvested RSU awards, which is being amortized through 2019 . There have been no material changes to the outstanding and non-vested RSUs during the three months ended March 31, 2017 .

Pension Benefits

Pension Benefits	3 Months Ended
	Mar. 31, 2017
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]
Pension Benefits	Note 8 - Pension Benefits Pension Plans The Company has a non-contributory defined benefit pension plan covering substantially all of its employees who joined the Company prior to January 1, 2015, and 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, continue to earn benefits. Components of Net Periodic Benefit Cost for the Pension Plans The following table presents the components of the net periodic benefit cost for the Pension Plans: For the Three Months Ended March 31, 2017 2016 (in thousands) Service cost $ 2,050 $ 1,987 Interest cost 727 624 Expected return on plan assets that reduces periodic pension cost (559 ) (545 ) Amortization of prior service cost 4 4 Amortization of net actuarial loss 396 372 Net periodic benefit cost $ 2,618 $ 2,442 Prior service costs are amortized on a straight-line basis over the average remaining service period of active participants. Gains and losses in excess of 10 percent of the greater of the benefit obligation or the market-related value of assets are amortized over the average remaining service period of active participants. Contributions The Company contributed $3.0 million to the Qualified Pension Plan during the three months ended March 31, 2017 .

Earnings per Share

Earnings per Share	3 Months Ended
	Mar. 31, 2017
Earnings Per Share [Abstract]
Earnings per Share	Note 9 - Earnings Per Share Basic net income or loss per common share is calculated by dividing net income or loss available to common stockholders by the basic weighted-average number of common shares outstanding for the respective period. Diluted net income or loss per common share is calculated by dividing adjusted net income or loss by the diluted weighted-average number of common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist of unvested RSUs, contingent PSUs, and shares into which the Senior Convertible Notes are convertible, which are measured using the treasury stock method. PSUs represent the right to receive, upon settlement of the PSUs after the completion of the three -year performance period, a number of shares of the Company’s common stock that may range from zero to two times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, that 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. 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 has not made this a formal legal irrevocable election and thereby 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 three months ended March 31, 2017 , and therefore, had no dilutive impact. In connection with the offering of the Senior Convertible Notes, the Company entered into capped call transactions with affiliates of the underwriters that would effectively prevent dilution upon settlement up to the $60.00 cap price. The capped call transactions 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. When the Company recognizes a loss from continuing operations, as was the case for three months ended March 31, 2016 , all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted net loss per common share. The following table details the weighted-average dilutive and anti-dilutive securities for the periods presented: For the Three Months Ended March 31, 2017 2016 (in thousands) Dilutive 71 — Anti-dilutive — 49 The following table sets forth the calculations of basic and diluted earnings per share: For the Three Months Ended March 31, 2017 2016 (in thousands, except per share amounts) Net income (loss) $ 74,434 $ (347,210 ) Basic weighted-average common shares outstanding 111,258 68,077 Add: dilutive effect of unvested RSUs and contingent PSUs 71 — Add: dilutive effect of 1.50% Senior Convertible Notes — — Diluted weighted-average common shares outstanding 111,329 68,077 Basic net income (loss) per common share $ 0.67 $ (5.10 ) Diluted net income (loss) per common share $ 0.67 $ (5.10 )

Derivative Financial Instrument

Derivative Financial Instruments	3 Months Ended
	Mar. 31, 2017
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Derivative Financial Instruments	Note 10 - Derivative Financial Instruments Summary of Oil, Gas, and NGL Derivative Contracts in Place The Company has entered into various commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in commodity prices and the associated impact on cash flows. As of March 31, 2017 , all derivative counterparties were members of the Company’s credit facility lender group and all contracts were entered into for other-than-trading purposes. The Company’s 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 March 31, 2017 , the Company had commodity derivative contracts outstanding as summarized in the tables below. Oil Swaps Contract Period NYMEX WTI Volumes Weighted-Average Contract Price (MBbls) (per Bbl) Second quarter 2017 1,444 $ 46.44 Third quarter 2017 1,340 $ 46.66 Fourth quarter 2017 1,254 $ 46.35 Total 4,038 Oil Collars Contract Period NYMEX WTI Volumes Weighted- Average Floor Price Weighted- Average Ceiling Price (MBbls) (per Bbl) (per Bbl) 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 3,343 $ 50.00 $ 58.55 2019 2,660 $ 50.00 $ 59.31 Total 7,762 Oil Basis Swaps Contract Period Midland-Cushing Volumes Weighted-Average Contract Price (1) (MBbls) (per Bbl) 2018 2,080 $ (1.27 ) 2019 1,588 $ (1.45 ) Total 3,668 ____________________________________________ (1) Represents the price differential between WTI prices at Midland, Texas and WTI prices at Cushing, Oklahoma. 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) 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 75,778 $ 3.54 (30,606 ) $ 4.27 45,172 2019 32,016 $ 4.02 (24,415 ) $ 4.34 7,601 Total (2) 179,657 (55,021 ) 124,636 ____________________________________________ (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 other 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 ( 2% ), IF HSC ( 95% ), 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) Second quarter 2017 787 $ 8.86 634 $ 21.90 182 $ 32.53 157 $ 33.38 249 $ 48.47 Third quarter 2017 736 $ 9.14 588 $ 21.91 163 $ 32.42 140 $ 33.28 222 $ 48.43 Fourth quarter 2017 692 $ 9.10 550 $ 21.91 149 $ 32.34 128 $ 33.23 203 $ 48.41 2018 2,434 $ 10.18 1,442 $ 22.86 138 $ 35.41 119 $ 35.44 189 $ 49.40 2019 2,176 $ 11.95 — $ — — $ — — $ — — $ — 2020 539 $ 11.13 — $ — — $ — — $ — — $ — Total 7,364 3,214 632 544 863 Summary of Oil, Gas, and NGL Derivative Contracts Entered Into Subsequent to March 31, 2017 Subsequent to March 31, 2017 , and through April 26, 2017, the Company entered into various derivative commodity contracts as summarized in the tables below. Oil Collars Contract Period NYMEX WTI Volumes Weighted- Average Floor Price Weighted- Average Ceiling Price (MBbls) (per Bbl) (per Bbl) Fourth quarter 2017 546 $ 50.00 $ 58.08 2018 1,687 $ 50.00 $ 57.12 2019 468 $ 50.00 $ 56.20 Total 2,701 Oil Basis Swaps Contract Period Midland-Cushing Volumes Weighted-Average Contract Price (1) (MBbls) (per Bbl) Third quarter 2017 566 $ (1.62 ) Fourth quarter 2017 1,403 $ (1.55 ) 2018 3,584 $ (1.50 ) 2019 2,375 $ (1.45 ) Total 7,928 ____________________________________________ (1) Represents the price differential between WTI prices at Midland, Texas and WTI prices at Cushing, Oklahoma. Natural Gas Swaps Contract Period IF HSC Volumes Weighted-Average Contract Price (BBtu) (per MMBtu) 2018 17,236 $ 2.87 2019 9,378 $ 2.88 Total 26,614 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) Second quarter 2017 105 $ 10.97 — $ — — $ — — $ — — $ — Third quarter 2017 170 $ 10.98 — $ — — $ — — $ — — $ — Fourth quarter 2017 274 $ 11.04 — $ — — $ — — $ — — $ — 2018 1,157 $ 12.23 345 $ 26.04 87 $ 31.71 69 $ 30.35 116 $ 47.36 Total 1,706 345 87 69 116 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 asset of $23.1 million as of March 31, 2017 , and a net liability of $91.7 million as of December 31, 2016 . The following tables detail the fair value of derivatives recorded in the accompanying balance sheets, by category: As of March 31, 2017 Derivative Assets Derivative Liabilities Balance Sheet Classification Fair Value Balance Sheet Classification Fair Value (in thousands) Commodity contracts Current assets $ 73,978 Current liabilities $ 53,809 Commodity contracts Noncurrent assets 84,195 Noncurrent liabilities 81,306 Derivatives not designated as hedging instruments $ 158,173 $ 135,115 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 Offsetting of Derivative Assets and Liabilities As of March 31, 2017 , and December 31, 2016 , all derivative instruments held by the Company were subject to master netting arrangements with various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between it and the counterparty, at the election of both parties, for transactions that settle on the same date and in the same currency. The Company’s agreements also provide that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to not offset these positions in its accompanying balance sheets. The following table provides a reconciliation between the gross assets and liabilities reflected on the accompanying balance sheets and the potential effects of master netting arrangements on the fair value of the Company’s derivative contracts: Derivative Assets Derivative Liabilities As of As of Offsetting of Derivative Assets and Liabilities March 31, 2017 December 31, 2016 March 31, 2017 December 31, 2016 (in thousands) Gross amounts presented in the accompanying balance sheets $ 158,173 $ 122,096 $ (135,115 ) $ (213,804 ) Amounts not offset in the accompanying balance sheets (88,952 ) (118,080 ) 88,952 118,080 Net amounts $ 69,221 $ 4,016 $ (46,163 ) $ (95,724 ) The following table summarizes the components of the net derivative gain presented in the accompanying statements of operations: For the Three Months Ended March 31, 2017 2016 (in thousands) Derivative settlement (gain) loss: Oil contracts $ 9,084 $ (99,992 ) Gas contracts (17,506 ) (41,053 ) NGL contracts 8,415 (5,983 ) Total derivative settlement gain $ (7 ) $ (147,028 ) Total net derivative (gain) loss: Oil contracts $ (49,590 ) $ (10,432 ) Gas contracts (44,468 ) (24,023 ) NGL contracts (20,716 ) 20,227 Total net derivative gain $ (114,774 ) $ (14,228 ) Credit Related Contingent Features As of March 31, 2017 , and through the filing of this report, all of the Company’s derivative counterparties were members of the Company’s credit facility lender group. Under the Credit Agreement and derivative contracts, the Company is required to secure 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	3 Months Ended
	Mar. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Disclosures [Text Block]	Note 11 - Fair Value Measurements The Company follows fair value measurement accounting guidance for all assets and liabilities measured at fair value. This guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The fair value hierarchy for grouping these assets and liabilities is based on the significance level of the following inputs: • Level 1 – quoted prices in active markets for identical assets or liabilities • Level 2 – quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable • Level 3 – significant inputs to the valuation model are unobservable The following table summarizes 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 March 31, 2017 : Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 158,173 $ — Total property and equipment, net (2) $ — $ — $ 443,772 Liabilities: Derivatives (1) $ — $ 135,115 $ — ____________________________________________ (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 summarizes the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they were classified within the fair value hierarchy as of December 31, 2016 : Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 122,096 $ — Total property and equipment, net (2) $ — $ — $ 88,205 Liabilities: Derivatives (1) $ — $ 213,804 $ — ____________________________________________ (1) This represents a financial asset or liability that is measured at fair value on a recurring basis. (2) This represents a non-financial asset that is measured at fair value on a nonrecurring basis. Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The following is a description of the valuation methodologies used by the Company as well as the general classification of such instruments pursuant to the above fair value hierarchy. Derivatives The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivatives. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration forward commodity price curves, counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit-price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The 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 Property and equipment, net measured at fair value within the accompanying balance sheets totaled $443.8 million as of March 31, 2017 , and related to assets held for sale as further discussed below. Property and equipment, net measured at fair value totaled $88.2 million as of December 31, 2016 , and related primarily to downward performance reserve revisions on the Company’s Powder River Basin assets at year-end. 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 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 are 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 March 31, 2017 , and December 31, 2016 . The Company believes the discount rates are representative of current market conditions and consider estimates of future cash payments, reserve categories, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The prices for oil and gas are forecast based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLs are forecast using OPIS 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. There were no impairments on proved properties during the three months ended March 31, 2017 . For the three months ended March 31, 2016, the Company recorded $269.8 million of proved property impairments related primarily to the Company’s outside-operated Eagle Ford shale assets and the decline in expected reserve cash flows driven by commodity price declines during the first quarter of 2016. Unproved oil and gas properties. Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. To measure the fair value of unproved properties, the Company uses a market approach, which takes into account the following significant assumptions: remaining lease terms, future development plans, risk weighted potential resource recovery, estimated reserve values, and estimated acreage value based on price(s) received for similar, recent acreage transactions by the Company or other market participants. There were no material abandonments or impairments of unproved properties during the three months ended March 31, 2017 , or 2016. Oil and gas properties held for sale. Proved and unproved properties and other property and equipment 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, or by recent, comparable market transactions. If an estimated selling price is not available, the Company utilizes the various income valuation techniques discussed above. Any initial write-down and subsequent changes to the fair value less estimated cost to sell is included within the net gain (loss) on divestiture activity line item in the accompanying statements of operations. For the three months ended March 31, 2017, write-downs to fair value less estimated costs to sell on the Divide County assets held for sale totaled $359.6 million . For the three months ended March 31, 2016, write-downs to fair value less estimated costs to sell on certain assets held for sale totaled $68.3 million . Certain of these assets were subsequently sold in the third quarter of 2016 for a small net gain due to successful marketing efforts. Please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions for additional discussion . Long-Term Debt The following table reflects the fair value of the Senior Notes and Senior Convertible Notes measured using Level 1 inputs based on quoted secondary market trading prices. These notes were not presented at fair value on the accompanying balance sheets as of March 31, 2017 , or December 31, 2016 , as they were recorded at carrying value, net of any unamortized discounts and deferred financing costs. Please refer to Note 5 - Long-Term Debt for additional discussion. As of March 31, 2017 As of December 31, 2016 Principal Amount Fair Value Principal Amount Fair Value (in thousands) 6.50% Senior Notes due 2021 $ 344,611 $ 353,657 $ 346,955 $ 354,546 6.125% Senior Notes due 2022 $ 561,796 $ 572,330 $ 561,796 $ 570,925 6.50% Senior Notes due 2023 $ 394,985 $ 403,378 $ 394,985 $ 403,134 5.0% Senior Notes due 2024 $ 500,000 $ 472,500 $ 500,000 $ 475,975 5.625% Senior Notes due 2025 $ 500,000 $ 479,550 $ 500,000 $ 485,000 6.75% Senior Notes due 2026 $ 500,000 $ 503,750 $ 500,000 $ 516,565 1.50% Senior Convertible Notes due 2021 $ 172,500 $ 171,355 $ 172,500 $ 202,189 The carrying value of the Company’s credit facility approximates its fair value, as the applicable interest rates are floating and based on prevailing market rates.

Basis of Presentation, Signif19

Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards (Policies)	3 Months Ended
	Mar. 31, 2017
Basis of Presentation and Significant Accounting Policies [Abstract]
Consolidation, Policy [Policy Text Block]	Basis of Presentation The accompanying unaudited condensed consolidated financial statements include the accounts of SM Energy and its wholly-owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and the instructions to Quarterly Report on Form 10-Q and Regulation S-X. These financial statements do not include all information and notes required by GAAP for annual financial statements. However, except as disclosed herein, there has been no material change in the information disclosed in the notes to consolidated financial statements included in SM Energy’s Annual Report on Form 10-K for the year ended December 31, 2016 (the “ 2016 Form 10-K”). In the opinion of management, all adjustments, consisting of normal recurring adjustments considered necessary for a fair presentation of interim financial information, have been included. Operating results for the periods presented are not necessarily indicative of expected results for the full year. In connection with the preparation of the Company’s unaudited condensed consolidated financial statements, the Company evaluated events subsequent to the balance sheet date of March 31, 2017 , and through the filing of this report. Certain prior period amounts have been reclassified to conform to the current presentation on the accompanying condensed consolidated financial statements.
New Accounting Pronouncements, Policy [Policy Text Block]	Recently Issued Accounting Standards Effective January 1, 2017, the Company adopted, using various transition methods, Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). ASU 2016-09 is meant to simplify certain aspects of accounting for share-based payment arrangements, including income tax effects, accounting for forfeitures, and net share settlements. The Company adopted the various applicable amendments as summarized below: • ASU 2016-09 requires all future excess tax benefits and deficiencies related to share-based payment arrangements to be recognized as income tax benefit or expense as discrete events in the period in which they occur. The Company adopted this amendment under a modified retrospective transition method, which resulted in a $44.3 million cumulative-effect adjustment to retained earnings as of January 1, 2017, with a corresponding deferred tax asset recorded for previously unrecognized excess tax benefits. Consequentially, the Company’s diluted share count calculation changed prospectively beginning in the period ended March 31, 2017. Any future excess tax benefits and deficiencies are now being excluded from the assumed proceeds calculated under the treasury stock method for share-based payment arrangements. Lastly, this amendment requires companies to present excess tax benefits as an operating activity on the statement of cash flows rather than as a financing activity, which the Company applied prospectively beginning in the period ended March 31, 2017. There are no periods presented that would require reclassification of cash flows had the Company elected to apply this amendment retrospectively. • ASU 2016-09 allows entities to elect whether to account for forfeitures of share-based payment awards by recognizing forfeitures of awards as they occur or by estimating the number of awards expected to be forfeited. This amendment is to be applied using a modified retrospective transition method. Upon adopting ASU 2016-09, the Company elected to change its policy to account for forfeitures of share-based payment awards as they occur effective January 1, 2017. This change in accounting policy resulted in a net $0.7 million cumulative-effect adjustment to retained earnings as of January 1, 2017, to adjust for actual forfeitures versus the previously estimated forfeiture rate. The corresponding impacts were an increase in additional paid-in capital and a decrease in deferred tax assets. • ASU 2016-09 allows entities to withhold an amount up to the employees’ maximum individual tax rate in the relevant jurisdiction, without triggering liability classification of the award; however, the Company does not plan on changing its current withholding process as outlined in its share-based award agreements. Related to this amendment, ASU 2016-09 requires entities to present cash payments made to tax authorities on the employees’ behalf for withheld tax shares as a financing activity on the statement of cash flows retrospectively. However, this presentation is already consistent with the Company’s historical and current cash flow presentation of net share settlement from issuance of stock awards, and therefore, there was no impact from this amendment. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) for the recognition of revenue from contracts with customers. Several additional related ASUs have been issued. 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. The Company is currently establishing a cross-functional implementation team to analyze the impact of the standard on the Company’s contract portfolio by reviewing current accounting policies and practices to identify potential differences that would result from applying the requirements of the new standard. In addition, the Company is working to identify appropriate changes to the Company’s business processes, systems, and controls to support recognition and disclosure under the new standard. The Company currently plans to adopt the guidance on the effective date of January 1, 2019. In March 2017, the FASB issued ASU No. 2017-07, Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (“ASU 2017-07”). This ASU is intended to improve the presentation of net periodic pension cost and net periodic postretirement benefit cost by providing additional guidance on the presentation of net benefit cost on the income statement and on the components eligible for capitalization in assets. As outlined in ASU 2017-07, certain amendments are to be applied using a retrospective method while others are required to be applied using a prospective 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 outlined in ASU 2017-07. The Company is currently evaluating the provisions of this guidance and assessing the potential impact on the Company’s financial statements and disclosures and does not intend to early adopt this guidance. Other than as disclosed above or in the 2016 Form 10-K, there are no other accounting standards applicable to the Company that would have a material effect on the Company’s financial statements and related disclosures that have been issued but not yet adopted by the Company as of March 31, 2017 , and through the filing of this report.
Fair Value of Financial Instruments, Policy [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. 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.
Property, Plant and Equipment, Impairment [Policy Text Block]	Proved and Unproved Oil and Gas Properties and Other Property and Equipment Property and equipment, net measured at fair value within the accompanying balance sheets totaled $443.8 million as of March 31, 2017 , and related to assets held for sale as further discussed below. Property and equipment, net measured at fair value totaled $88.2 million as of December 31, 2016 , and related primarily to downward performance reserve revisions on the Company’s Powder River Basin assets at year-end. 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 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 are 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 March 31, 2017 , and December 31, 2016 . The Company believes the discount rates are representative of current market conditions and consider estimates of future cash payments, reserve categories, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The prices for oil and gas are forecast based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLs are forecast using OPIS 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. There were no impairments on proved properties during the three months ended March 31, 2017 . For the three months ended March 31, 2016, the Company recorded $269.8 million of proved property impairments related primarily to the Company’s outside-operated Eagle Ford shale assets and the decline in expected reserve cash flows driven by commodity price declines during the first quarter of 2016. Unproved oil and gas properties. Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. To measure the fair value of unproved properties, the Company uses a market approach, which takes into account the following significant assumptions: remaining lease terms, future development plans, risk weighted potential resource recovery, estimated reserve values, and estimated acreage value based on price(s) received for similar, recent acreage transactions by the Company or other market participants. There were no material abandonments or impairments of unproved properties during the three months ended March 31, 2017 , or 2016. Oil and gas properties held for sale. Proved and unproved properties and other property and equipment 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, or by recent, comparable market transactions. If an estimated selling price is not available, the Company utilizes the various income valuation techniques discussed above. Any initial write-down and subsequent changes to the fair value less estimated cost to sell is included within the net gain (loss) on divestiture activity line item in the accompanying statements of operations. For the three months ended March 31, 2017, write-downs to fair value less estimated costs to sell on the Divide County assets held for sale totaled $359.6 million . For the three months ended March 31, 2016, write-downs to fair value less estimated costs to sell on certain assets held for sale totaled $68.3 million . Certain of these assets were subsequently sold in the third quarter of 2016 for a small net gain due to successful marketing efforts. Please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions for additional discussion .

Divestitures, Assets Held for20

Divestitures, Assets Held for Sale, and Acquisitions (Tables)	3 Months Ended
	Mar. 31, 2017
Non-Operated Eagle Ford Divestiture 2017 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Groups, Including Discontinued Operations [Table Text Block]	The following table presents income (loss) before income taxes of the outside-operated Eagle Ford shale assets sold for the three months ended March 31, 2017 , and 2016 . This divestiture is considered a disposal of a significant asset group. For the Three Months Ended March 31, 2017 2016 (in thousands) Income (loss) before income taxes (1) $ 24,324 $ (286,399 ) ____________________________________________ (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 included impairment of proved properties expense of approximately $269.6 million for the three months ended March 31, 2016.
Divide County Divestiture 2017 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Groups, Including Discontinued Operations [Table Text Block]	The following table presents loss before income taxes of the Company’s Divide County assets held for sale for the three months ended March 31, 2017 , and 2016 : For the Three Months Ended March 31, 2017 2016 (in thousands) Loss before income taxes (1) $ (335,561 ) $ (16,813 ) ____________________________________________ (1) 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, loss before income taxes for the three months ended March 31, 2017, included the $359.6 million write-down on these assets held for sale as discussed above, and loss before income taxes for the three months ended March 31, 2016, included $1.6 million of unproved property impairments.

Income Taxes (Tables)

Income Taxes (Tables)	3 Months Ended
	Mar. 31, 2017
Income Tax Disclosure [Abstract]
Schedule of provision for income taxes	The provision for income taxes for the three months ended March 31, 2017, and 2016, consisted of the following: For the Three Months Ended March 31, 2017 2016 (in thousands) Current portion of income tax (expense) benefit: Federal $ (7,439 ) $ — State (3,842 ) (164 ) Deferred portion of income tax (expense) benefit (33,225 ) 195,039 Income tax (expense) benefit $ (44,506 ) $ 194,875 Effective tax rate 37.4 % 35.9 %

Long-Term Debt (Tables)

Long-Term Debt (Tables)	3 Months Ended
	Mar. 31, 2017
Debt Disclosure [Abstract]
Schedule of Line of Credit Facilities [Table Text Block]	The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Credit Agreement as of April 26, 2017 , March 31, 2017 , and December 31, 2016 : As of April 26, 2017 As of March 31, 2017 As of December 31, 2016 (in thousands) Credit facility balance (1) $ — $ — $ — Letters of credit (2) 200 200 200 Available borrowing capacity 924,800 924,800 1,164,800 Total aggregate lender commitment amount $ 925,000 $ 925,000 $ 1,165,000 ____________________________________________ (1) Unamortized deferred financing costs attributable to the credit facility are presented as a component of other noncurrent assets on the accompanying balance sheets and totaled $4.3 million and $5.9 million as of March 31, 2017 , and December 31, 2016 , respectively. (2) Letters of credit outstanding 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 March 31, 2017 , and December 31, 2016 , consisted of the following: As of March 31, 2017 As of December 31, 2016 Principal Amount Unamortized Deferred Financing Costs Senior Notes, Net of Unamortized Deferred Financing Costs Principal Amount Unamortized Deferred Financing Costs Senior Notes, Net of Unamortized Deferred Financing Costs (in thousands) 6.50% Senior Notes due 2021 (1) (2) $ 344,611 $ 3,176 $ 341,435 $ 346,955 $ 3,372 $ 343,583 6.125% Senior Notes due 2022 (2) 561,796 6,684 555,112 561,796 6,979 554,817 6.50% Senior Notes due 2023 (2) 394,985 4,254 390,731 394,985 4,436 390,549 5.0% Senior Notes due 2024 500,000 6,302 493,698 500,000 6,533 493,467 5.625% Senior Notes due 2025 500,000 7,393 492,607 500,000 7,619 492,381 6.75% Senior Notes due 2026 500,000 7,869 492,131 500,000 8,078 491,922 Total $ 2,801,392 $ 35,678 $ 2,765,714 $ 2,803,736 $ 37,017 $ 2,766,719 ____________________________________________ (1) During the first quarter of 2017, the Company repurchased a total of $2.3 million in aggregate principal amount of 6.50% Senior Notes due 2021 in open market transactions at a slight premium. The Company canceled all of these repurchased Senior Notes upon cash settlement. (2) During the first quarter of 2016, the Company repurchased a total of $46.3 million in aggregate principal amount of certain of its Senior Notes in open market transactions for a settlement amount of $29.9 million , excluding interest, of which $19.9 million was paid during the three months ended March 31, 2016, with the remaining $10.0 million settlement amount being accrued at March 31, 2016, and paid in the second quarter of 2016. The Company recorded a net gain on extinguishment of debt of approximately $15.7 million for the three months ended March 31, 2016. This amount includes a gain of approximately $16.4 million associated with the discount realized upon repurchase, which was partially offset by approximately $0.7 million related to the acceleration of unamortized deferred financing costs. The Company canceled all of these repurchased Senior Notes upon cash settlement.
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 as of March 31, 2017 , and December 31, 2016 , consisted of the following: As of March 31, 2017 As of December 31, 2016 (in thousands) Principal amount of Senior Convertible Notes $ 172,500 $ 172,500 Unamortized debt discount (35,713 ) (37,513 ) Unamortized deferred financing costs (3,898 ) (4,131 ) Net carrying amount $ 132,889 $ 130,856

Pension Benefits (Tables)

Pension Benefits (Tables)	3 Months Ended
	Mar. 31, 2017
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]
Components of the net periodic benefit cost for both the Qualified and the Nonqualified Pension Plan	The following table presents the components of the net periodic benefit cost for the Pension Plans: For the Three Months Ended March 31, 2017 2016 (in thousands) Service cost $ 2,050 $ 1,987 Interest cost 727 624 Expected return on plan assets that reduces periodic pension cost (559 ) (545 ) Amortization of prior service cost 4 4 Amortization of net actuarial loss 396 372 Net periodic benefit cost $ 2,618 $ 2,442

Earnings per Share (Tables)

Earnings per Share (Tables)	3 Months Ended
	Mar. 31, 2017
Earnings Per Share [Abstract]
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share [Table Text Block]	The following table details the weighted-average dilutive and anti-dilutive securities for the periods presented: For the Three Months Ended March 31, 2017 2016 (in thousands) Dilutive 71 — Anti-dilutive — 49
Schedule of calculation of basic and diluted earnings per share	The following table sets forth the calculations of basic and diluted earnings per share: For the Three Months Ended March 31, 2017 2016 (in thousands, except per share amounts) Net income (loss) $ 74,434 $ (347,210 ) Basic weighted-average common shares outstanding 111,258 68,077 Add: dilutive effect of unvested RSUs and contingent PSUs 71 — Add: dilutive effect of 1.50% Senior Convertible Notes — — Diluted weighted-average common shares outstanding 111,329 68,077 Basic net income (loss) per common share $ 0.67 $ (5.10 ) Diluted net income (loss) per common share $ 0.67 $ (5.10 )

Derivative Financial Instrume25

Derivative Financial Instruments (Tables)	3 Months Ended
	Mar. 31, 2017
Subsequent Event [Line Items]
Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block]	As of March 31, 2017 , the Company had commodity derivative contracts outstanding as summarized in the tables below. Oil Swaps Contract Period NYMEX WTI Volumes Weighted-Average Contract Price (MBbls) (per Bbl) Second quarter 2017 1,444 $ 46.44 Third quarter 2017 1,340 $ 46.66 Fourth quarter 2017 1,254 $ 46.35 Total 4,038 Oil Collars Contract Period NYMEX WTI Volumes Weighted- Average Floor Price Weighted- Average Ceiling Price (MBbls) (per Bbl) (per Bbl) 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 3,343 $ 50.00 $ 58.55 2019 2,660 $ 50.00 $ 59.31 Total 7,762 Oil Basis Swaps Contract Period Midland-Cushing Volumes Weighted-Average Contract Price (1) (MBbls) (per Bbl) 2018 2,080 $ (1.27 ) 2019 1,588 $ (1.45 ) Total 3,668 ____________________________________________ (1) Represents the price differential between WTI prices at Midland, Texas and WTI prices at Cushing, Oklahoma. 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) 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 75,778 $ 3.54 (30,606 ) $ 4.27 45,172 2019 32,016 $ 4.02 (24,415 ) $ 4.34 7,601 Total (2) 179,657 (55,021 ) 124,636 ____________________________________________ (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 other 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 ( 2% ), IF HSC ( 95% ), 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) Second quarter 2017 787 $ 8.86 634 $ 21.90 182 $ 32.53 157 $ 33.38 249 $ 48.47 Third quarter 2017 736 $ 9.14 588 $ 21.91 163 $ 32.42 140 $ 33.28 222 $ 48.43 Fourth quarter 2017 692 $ 9.10 550 $ 21.91 149 $ 32.34 128 $ 33.23 203 $ 48.41 2018 2,434 $ 10.18 1,442 $ 22.86 138 $ 35.41 119 $ 35.44 189 $ 49.40 2019 2,176 $ 11.95 — $ — — $ — — $ — — $ — 2020 539 $ 11.13 — $ — — $ — — $ — — $ — Total 7,364 3,214 632 544 863 Summary of Oil, Gas, and NGL Derivative Contracts Entered Into Subsequent to March 31, 2017 Subsequent to March 31, 2017 , and through April 26, 2017, the Company entered into various derivative commodity contracts as summarized in the tables below. Oil Collars Contract Period NYMEX WTI Volumes Weighted- Average Floor Price Weighted- Average Ceiling Price (MBbls) (per Bbl) (per Bbl) Fourth quarter 2017 546 $ 50.00 $ 58.08 2018 1,687 $ 50.00 $ 57.12 2019 468 $ 50.00 $ 56.20 Total 2,701 Oil Basis Swaps Contract Period Midland-Cushing Volumes Weighted-Average Contract Price (1) (MBbls) (per Bbl) Third quarter 2017 566 $ (1.62 ) Fourth quarter 2017 1,403 $ (1.55 ) 2018 3,584 $ (1.50 ) 2019 2,375 $ (1.45 ) Total 7,928 ____________________________________________ (1) Represents the price differential between WTI prices at Midland, Texas and WTI prices at Cushing, Oklahoma. Natural Gas Swaps Contract Period IF HSC Volumes Weighted-Average Contract Price (BBtu) (per MMBtu) 2018 17,236 $ 2.87 2019 9,378 $ 2.88 Total 26,614 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) Second quarter 2017 105 $ 10.97 — $ — — $ — — $ — — $ — Third quarter 2017 170 $ 10.98 — $ — — $ — — $ — — $ — Fourth quarter 2017 274 $ 11.04 — $ — — $ — — $ — — $ — 2018 1,157 $ 12.23 345 $ 26.04 87 $ 31.71 69 $ 30.35 116 $ 47.36 Total 1,706 345 87 69 116
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 March 31, 2017 Derivative Assets Derivative Liabilities Balance Sheet Classification Fair Value Balance Sheet Classification Fair Value (in thousands) Commodity contracts Current assets $ 73,978 Current liabilities $ 53,809 Commodity contracts Noncurrent assets 84,195 Noncurrent liabilities 81,306 Derivatives not designated as hedging instruments $ 158,173 $ 135,115 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
Schedule of the potential effects of master netting arrangements [Table Text Block]	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 As of Offsetting of Derivative Assets and Liabilities March 31, 2017 December 31, 2016 March 31, 2017 December 31, 2016 (in thousands) Gross amounts presented in the accompanying balance sheets $ 158,173 $ 122,096 $ (135,115 ) $ (213,804 ) Amounts not offset in the accompanying balance sheets (88,952 ) (118,080 ) 88,952 118,080 Net amounts $ 69,221 $ 4,016 $ (46,163 ) $ (95,724 )
Schedule of derivative (gain) loss	The following table summarizes the components of the net derivative gain presented in the accompanying statements of operations: For the Three Months Ended March 31, 2017 2016 (in thousands) Derivative settlement (gain) loss: Oil contracts $ 9,084 $ (99,992 ) Gas contracts (17,506 ) (41,053 ) NGL contracts 8,415 (5,983 ) Total derivative settlement gain $ (7 ) $ (147,028 ) Total net derivative (gain) loss: Oil contracts $ (49,590 ) $ (10,432 ) Gas contracts (44,468 ) (24,023 ) NGL contracts (20,716 ) 20,227 Total net derivative gain $ (114,774 ) $ (14,228 )

Fair Value Measurements Fair Va

Fair Value Measurements Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements, Recurring and Nonrecurring [Table Text Block]	The following table summarizes 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 March 31, 2017 : Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 158,173 $ — Total property and equipment, net (2) $ — $ — $ 443,772 Liabilities: Derivatives (1) $ — $ 135,115 $ — ____________________________________________ (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 summarizes the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they were classified within the fair value hierarchy as of December 31, 2016 : Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 122,096 $ — Total property and equipment, net (2) $ — $ — $ 88,205 Liabilities: Derivatives (1) $ — $ 213,804 $ — ____________________________________________ (1) This represents a financial asset or liability that is measured at fair value on a recurring basis. (2) This represents a non-financial asset that is measured at fair value on a nonrecurring basis.
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 March 31, 2017 , or December 31, 2016 , as they were recorded at carrying value, net of any unamortized discounts and deferred financing costs. Please refer to Note 5 - Long-Term Debt for additional discussion. As of March 31, 2017 As of December 31, 2016 Principal Amount Fair Value Principal Amount Fair Value (in thousands) 6.50% Senior Notes due 2021 $ 344,611 $ 353,657 $ 346,955 $ 354,546 6.125% Senior Notes due 2022 $ 561,796 $ 572,330 $ 561,796 $ 570,925 6.50% Senior Notes due 2023 $ 394,985 $ 403,378 $ 394,985 $ 403,134 5.0% Senior Notes due 2024 $ 500,000 $ 472,500 $ 500,000 $ 475,975 5.625% Senior Notes due 2025 $ 500,000 $ 479,550 $ 500,000 $ 485,000 6.75% Senior Notes due 2026 $ 500,000 $ 503,750 $ 500,000 $ 516,565 1.50% Senior Convertible Notes due 2021 $ 172,500 $ 171,355 $ 172,500 $ 202,189

Basis of Presentation, Signif27

Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards Recently Issued Accounting Standards (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Retained earnings	$ 906,515	$ 794,020
ASU 2016-09 Cumulative Effect Adjustment for Timing of Recognition of Excess Tax Benefits [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Retained earnings	44,300
ASU 2016-09 Cumulative Effect of Actual Forfeiture Rate [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Retained earnings	$ (700)

Divestitures, Assets Held for28

Divestitures, Assets Held for Sale, and Acquisitions Divestitures and Assets Held for Sale (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net proceeds from the sale of oil and gas properties		$ 744,333	$ 1,206
Net gain (loss) on divestiture activity		37,463	(69,021)
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest		118,940	(542,085)
Impairment of Proved Oil and Gas Properties		$ 0	269,785
Assets Held-for-sale Reasonably Certain Period for Sale		1 year
Disposal Group, Including Discontinued Operation, Assets, Current		$ 455,943		$ 372,621
Asset retirement obligation associated with oil and gas properties held for sale		16,056		$ 26,241
Abandonment and impairment of unproved properties		0	2,311
Non-Operated Eagle Ford Divestiture 2017 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net proceeds from the sale of oil and gas properties		747,400
Net gain (loss) on divestiture activity		398,100
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	[1]	24,324	(286,399)
Impairment of Proved Oil and Gas Properties			269,600
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]
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	[2]	(335,561)	(16,813)
Impairment of Proved Oil and Gas Properties		$ 359,600
Abandonment and impairment of unproved properties			$ 1,600
[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 included impairment of proved properties expense of approximately $269.6 million for the three months ended March 31, 2016.
[2]	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, loss before income taxes for the three months ended March 31, 2017, included the $359.6 million write-down on these assets held for sale as discussed above, and loss before income taxes for the three months ended March 31, 2016, included $1.6 million of unproved property impairments.

Divestitures, Assets Held for29

Divestitures, Assets Held for Sale, and Acquisitions Acquisitions (Details) $ in Thousands	3 Months Ended		4 Months Ended	6 Months Ended
	Mar. 31, 2017USD ($)a	Mar. 31, 2016USD ($)	Apr. 26, 2017a	Mar. 31, 2017USD ($)
Business Acquisition [Line Items]
Payments to Acquire Oil and Gas Property and Equipment | $	$ 75,105	$ 15,044
Subsequent Event [Member] | Other Howard County Trades [Member]
Business Acquisition [Line Items]
Non-monetary Trade, Acreage Acquired | a			3,020
Non-monetary Trade, Acreage Exchanged | a			2,310
Rock Oil Acquisition 2016 [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross | $	$ 7,400			$ 998,400
Other Midland Basin Acquisition 2017 [Member]
Business Acquisition [Line Items]
Net Acres Acquired | a	2,900
Payments to Acquire Oil and Gas Property and Equipment | $	$ 59,600

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Components of the provision for income taxes
Federal	$ (7,439)	$ 0
State	(3,842)	(164)
Deferred portion of income tax (expense) benefit	(33,225)	195,039
Income tax (expense) benefit	$ (44,506)	$ 194,875
Effective tax rate	37.40%	35.90%

Long-Term Debt Revolving Credit

Long-Term Debt Revolving Credit Facility (Details) $ in Thousands		3 Months Ended
		Mar. 31, 2017USD ($)	Apr. 26, 2017USD ($)	Dec. 31, 2016USD ($)
Line of Credit Facility [Line Items]
Long-term Line of Credit, Noncurrent		$ 0		$ 0
Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		2,500,000
Accelerated Amortization of Debt Issuance Costs Related To Borrowing Base And Lender Commitment Revisions		1,100
Long-term Line of Credit, Noncurrent	[1]	0		0
Letters of Credit Outstanding, Amount	[2]	200		200
Line of Credit Facility, Remaining Borrowing Capacity		924,800		1,164,800
Line of Credit Facility, Current Borrowing Capacity		925,000		1,165,000
Unamortized Debt Issuance Expense		$ 4,300		$ 5,900
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
Subsequent Event [Member] | Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Long-term Line of Credit, Noncurrent	[1]		$ 0
Letters of Credit Outstanding, Amount	[2]		200
Line of Credit Facility, Remaining Borrowing Capacity			924,800
Line of Credit Facility, Current Borrowing Capacity			$ 925,000
[1]	Unamortized deferred financing costs attributable to the credit facility are presented as a component of other noncurrent assets on the accompanying balance sheets and totaled $4.3 million and $5.9 million as of March 31, 2017, and December 31, 2016, respectively.
[2]	Letters of credit outstanding reduce the amount available under the credit facility on a dollar-for-dollar basis.

Long-Term Debt Senior Notes (De

Long-Term Debt Senior Notes (Details) - USD ($)	3 Months Ended
	Mar. 31, 2017		Mar. 31, 2016	Dec. 31, 2016		Aug. 12, 2016
Debt Instrument [Line Items]
Senior Notes, Noncurrent	$ 2,765,714,000			$ 2,766,719,000
Early Repayment of Senior Debt	2,344,000		$ 19,917,000
Gain (Loss) on Extinguishment of Debt	(35,000)		15,722,000
Gains (losses) on extinguishment of debt, noncash portion	(22,000)		15,722,000
Convertible Debt, Noncurrent	$ 132,889,000			130,856,000
Capped Call, Cap Price	$ 60
6.50% Senior Notes Due 2021 [Member]
Debt Instrument [Line Items]
Unamortized Debt Issuance Expense	$ 3,176,000	[1]		3,372,000	[2]
Senior Notes, Noncurrent	341,435,000	[1]		343,583,000	[2]
Debt Instrument, Repurchased Face Amount	2,300,000
6.125% Senior Notes Due 2022 [Member]
Debt Instrument [Line Items]
Unamortized Debt Issuance Expense	6,684,000			6,979,000	[2]
Senior Notes, Noncurrent	555,112,000			554,817,000	[2]
6.50% Senior Notes Due 2023 [Member]
Debt Instrument [Line Items]
Unamortized Debt Issuance Expense	4,254,000			4,436,000	[2]
Senior Notes, Noncurrent	390,731,000			390,549,000	[2]
5% Senior Notes Due 2024 [Member]
Debt Instrument [Line Items]
Unamortized Debt Issuance Expense	6,302,000			6,533,000
Senior Notes, Noncurrent	493,698,000			493,467,000
5.625% Senior Notes Due 2025 [Member]
Debt Instrument [Line Items]
Unamortized Debt Issuance Expense	7,393,000			7,619,000
Senior Notes, Noncurrent	492,607,000			492,381,000
6.75% Senior Notes Due 2026 [Domain]
Debt Instrument [Line Items]
Unamortized Debt Issuance Expense	7,869,000			8,078,000
Senior Notes, Noncurrent	492,131,000			491,922,000
Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	2,801,392,000			2,803,736,000
Unamortized Debt Issuance Expense	35,678,000			37,017,000
Senior Notes, Noncurrent	$ 2,765,714,000			2,766,719,000
Debt Instrument, Repurchased Face Amount			46,300,000
Debt Instrument, Repurchased Settlement Amount			29,900,000
Early Repayment of Senior Debt			19,917,000
Early Repayment of Senior Debt, Accrued			10,000,000
Gain (Loss) on Extinguishment of Debt			15,700,000
Debt Instrument, Repurchase Discount			16,400,000
Gains (losses) on extinguishment of debt, noncash portion			$ (700,000)
Senior Notes [Member] | 6.50% Senior Notes Due 2021 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Debt Instrument, Face Amount	$ 344,611,000			346,955,000
Senior Notes [Member] | 6.125% Senior Notes Due 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.125%
Debt Instrument, Face Amount	$ 561,796,000			561,796,000
Senior Notes [Member] | 6.50% Senior Notes Due 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Debt Instrument, Face Amount	$ 394,985,000			394,985,000
Senior Notes [Member] | 5% Senior Notes Due 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.00%
Debt Instrument, Face Amount	$ 500,000,000			500,000,000
Senior Notes [Member] | 5.625% Senior Notes Due 2025 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.625%
Debt Instrument, Face Amount	$ 500,000,000			500,000,000
Senior Notes [Member] | 6.75% Senior Notes Due 2026 [Domain]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.75%
Debt Instrument, Face Amount	$ 500,000,000			500,000,000
Convertible Debt [Member] | 1.50% Senior Convertible Notes Due 2021 [Domain]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	1.50%
Debt Instrument, Face Amount	$ 172,500,000			172,500,000
Unamortized Debt Issuance Expense	$ 3,898,000			4,131,000
Debt Instrument, Convertible, Conversion Ratio	24.6914
Debt Instrument, Principal Amount of Note	$ 1,000
Debt Instrument, Convertible, Conversion Price	$ 40.50
Debt Instrument, Convertible, Initial Fair Value of Liability Component						$ 132,300,000
Debt Instrument, Convertible, Comparable Yield	7.25%
Debt Instrument, Convertible, Carrying Amount of Equity Component						$ 40,200,000
Interest Expense, Debt	$ 2,400,000
Debt Instrument, Unamortized Discount	(35,713,000)			(37,513,000)
Convertible Debt, Noncurrent	$ 132,889,000			$ 130,856,000
[1]	During the first quarter of 2017, the Company repurchased a total of $2.3 million in aggregate principal amount of 6.50% Senior Notes due 2021 in open market transactions at a slight premium. The Company canceled all of these repurchased Senior Notes upon cash settlement.
[2]	During the first quarter of 2016, the Company repurchased a total of $46.3 million in aggregate principal amount of certain of its Senior Notes in open market transactions for a settlement amount of $29.9 million, excluding interest, of which $19.9 million was paid during the three months ended March 31, 2016, with the remaining $10.0 million settlement amount being accrued at March 31, 2016, and paid in the second quarter of 2016. The Company recorded a net gain on extinguishment of debt of approximately $15.7 million for the three months ended March 31, 2016. This amount includes a gain of approximately $16.4 million associated with the discount realized upon repurchase, which was partially offset by approximately $0.7 million related to the acceleration of unamortized deferred financing costs. The Company canceled all of these repurchased Senior Notes upon cash settlement.

Commitments and Contingencies (

Commitments and Contingencies (Details) MMcf in Thousands, $ in Millions	May 03, 2017USD ($)	Mar. 31, 2017USD ($)MMcfMMBbls	Dec. 31, 2016USD ($)MMcfMMBbls
Gas gathering and Oil and Gas Through-put Commitments [Member]
Other Commitments [Line Items]
Contractual Obligation | $		$ 458.8
Water Disposal Agreement [Member]
Other Commitments [Line Items]
Water Delivery Commitments and Contracts, Remaining Contractual Volume | MMBbls		25.4
Natural Gas Transportation Commitment [Member]
Other Commitments [Line Items]
Oil and Gas Delivery Commitments and Contracts, Remaining Contractual Volume | MMcf		915
Crude Oil Transportation Commitment [Member]
Other Commitments [Line Items]
Oil and Gas Delivery Commitments and Contracts, Remaining Contractual Volume | MMBbls		17
Subsequent Event [Member] | Drilling Rig Leasing Contracts [Member]
Other Commitments [Line Items]
Contractual Obligation | $	$ 30.1
Scenario, Forecast [Member] | Subsequent Event [Member] | Drilling Rig Leasing Contracts [Member]
Other Commitments [Line Items]
Early Termination Penalty for Rig Contract Cancellation | $	$ 19
Non-Operated Eagle Ford Divestiture 2017 [Member] | Gas gathering and Oil and Gas Through-put Commitments [Member]
Other Commitments [Line Items]
Contractual Obligation | $			$ 501.9
Non-Operated Eagle Ford Divestiture 2017 [Member] | Natural Gas Transportation Commitment [Member]
Other Commitments [Line Items]
Oil and Gas Delivery Commitments and Contracts, Remaining Contractual Volume | MMcf			514
Non-Operated Eagle Ford Divestiture 2017 [Member] | Crude Oil Transportation Commitment [Member]
Other Commitments [Line Items]
Oil and Gas Delivery Commitments and Contracts, Remaining Contractual Volume | MMBbls			52
Non-Operated Eagle Ford Divestiture 2017 [Member] | NGL Contracts [Member]
Other Commitments [Line Items]
Oil and Gas Delivery Commitments and Contracts, Remaining Contractual Volume | MMBbls			13

Compensation Plans (Details)

Compensation Plans (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2017USD ($)shares	Mar. 31, 2016USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	$ 5,455	$ 6,868
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Stock-based compensation expense	$ 2,500	2,900
Unrecognized stock based compensation expense	$ 14,200
Performance Shares [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Multiplier Applied to PSU Awards at Settlement	0
Performance Shares [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Multiplier Applied to PSU Awards at Settlement	2
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	$ 2,500	$ 3,200
Unrecognized stock based compensation expense	$ 12,900
Number of Shares Represented by Each RSU | shares	1

Pension Benefits (Details)

Pension Benefits (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Components of Net Periodic Benefit Costs for Both Pension Plans
Service cost	$ 2,050	$ 1,987
Interest cost	727	624
Expected return on plan assets that reduces periodic pension costs	(559)	(545)
Amortization of prior service costs	4	4
Amortization of net actuarial loss	396	372
Net periodic benefit cost	$ 2,618	$ 2,442

Pension Benefits Pension Narrat

Pension Benefits Pension Narrative (Details) $ in Millions	3 Months Ended
	Mar. 31, 2017USD ($)
Pension Narrative [Abstract]
Pension And Other Post-retirement Benefit Plans, Gain (Loss) Amortization Threshold	10.00%
Pension and Other Postretirement Benefit Contributions	$ 3

Earnings per Share (Details)

Earnings per Share (Details) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2017USD ($)$ / sharesshares	Mar. 31, 2016USD ($)$ / sharesshares	Dec. 31, 2016USD ($)
Earnings per share
Capped Call, Cap Price | $ / shares	$ 60
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	0	49
Calculation of basic and diluted earnings per share
Net income (loss) | $	$ 74,434	$ (347,210)
Basic weighted-average common shares outstanding	111,258	68,077
Add: dilutive effect of stock options, unvested RSU's, and contingent PSU's	71	0
Incremental Common Shares Attributable to Dilutive Effect of Conversion of Debt Securities	0	0
Diluted weighted-average common shares outstanding	111,329	68,077
Basic net income (loss) per common share | $ / shares	$ 0.67	$ (5.10)
Diluted net income (loss) per common share | $ / shares	$ 0.67	$ (5.10)
Performance Shares [Member]
Earnings per share
Share-based Compensation, Awards Other Than Options, Performance Measurement Period	3 years
Minimum [Member] | Performance Shares [Member]
Earnings per share
Multiplier Applied to PSU Awards at Settlement	0
Maximum [Member] | Performance Shares [Member]
Earnings per share
Multiplier Applied to PSU Awards at Settlement	2
Convertible Debt [Member] | 1.50% Senior Convertible Notes Due 2021 [Domain]
Earnings per share
Debt Instrument, Face Amount | $	$ 172,500		$ 172,500
Debt Instrument, Convertible, Conversion Price | $ / shares	$ 40.50

Derivative Financial Instrume38

Derivative Financial Instruments (Details) bbl in Thousands		Mar. 31, 2017MMBTU$ / EnergyContent$ / Barrelsbbl		Apr. 26, 2017MMBTU$ / EnergyContent$ / Barrelsbbl	Dec. 31, 2016MMBTU$ / EnergyContent
Derivative Financial Instruments
Percentage of Proved Property Secured for Credit Facility Borrowing		90.00%
NYMEX Oil Swap Contract Second Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		1,444
Derivative, Swap Type, Average Fixed Price | $ / Barrels		46.44
NYMEX Oil Swap Contract Third Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		1,340
Derivative, Swap Type, Average Fixed Price | $ / Barrels		46.66
NYMEX Oil Swap Contract Fourth Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		1,254
Derivative, Swap Type, Average Fixed Price | $ / Barrels		46.35
NYMEX Oil Swap Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		4,038
NYMEX Oil Collar Contract Second Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		636
Derivative, Floor Price | $ / Barrels		45
Derivative, Cap Price | $ / Barrels		54.10
NYMEX Oil Collar Contract Third Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		583
Derivative, Floor Price | $ / Barrels		45
Derivative, Cap Price | $ / Barrels		54.05
NYMEX Oil Collar Contract Fourth Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		540
Derivative, Floor Price | $ / Barrels		45
Derivative, Cap Price | $ / Barrels		54.01
NYMEX Oil Collar Contract 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		3,343
Derivative, Floor Price | $ / Barrels		50
Derivative, Cap Price | $ / Barrels		58.55
NYMEX Oil Collar Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		2,660
Derivative, Floor Price | $ / Barrels		50
Derivative, Cap Price | $ / Barrels		59.31
NYMEX Oil Collar Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		7,762
Oil Basis Swap Contract 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		2,080
Derivative, Swap Type, Average Fixed Price | $ / Barrels	[1]	(1.27)
Oil Basis Swap Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		1,588
Derivative, Swap Type, Average Fixed Price | $ / Barrels	[1]	(1.45)
Oil Basis Swap [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		3,668
Gas Swaps Contract Second Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent		3.98
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU		26,205,000
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | MMBTU	[2]	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, Swap Type, Average Fixed Price | $ / EnergyContent		4.01
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU		23,657,000
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | MMBTU	[2]	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, Swap Type, Average Fixed Price | $ / EnergyContent		3.98
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU		22,001,000
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | MMBTU	[2]	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, Swap Type, Average Fixed Price | $ / EnergyContent		3.54
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU		75,778,000
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | MMBTU	[2]	(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		45,172,000
Gas Swaps Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent		4.02
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU		32,016,000
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | MMBTU	[2]	(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		7,601,000
Gas Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	[3]	179,657,000
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | MMBTU		(55,021,000)	[2],[3]		(55,021,000)
Derivative, Nonmonetary Notional Amount, Energy Measure, Net of Purchased Volumes | MMBTU	[3]	124,636,000
Gas Swaps Contract 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU					38,600,000
Derivative, Swap Type, Average Fixed Price, Purchased Volumes | $ / EnergyContent					4.43
IF El Paso Permian [Member]
Derivative Financial Instruments
Index percent of natural gas fixed swaps		2.00%
IF HSC [Member]
Derivative Financial Instruments
Index percent of natural gas fixed swaps		95.00%
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 Second Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		787
Derivative, Swap Type, Average Fixed Price | $ / Barrels		8.86
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract Third Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		736
Derivative, Swap Type, Average Fixed Price | $ / Barrels		9.14
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract Fourth Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		692
Derivative, Swap Type, Average Fixed Price | $ / Barrels		9.10
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		2,434
Derivative, Swap Type, Average Fixed Price | $ / Barrels		10.18
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		2,176
Derivative, Swap Type, Average Fixed Price | $ / Barrels		11.95
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		539
Derivative, Swap Type, Average Fixed Price | $ / Barrels		11.13
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		7,364
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Second Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		634
Derivative, Swap Type, Average Fixed Price | $ / Barrels		21.90
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		588
Derivative, Swap Type, Average Fixed Price | $ / Barrels		21.91
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		550
Derivative, Swap Type, Average Fixed Price | $ / Barrels		21.91
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		1,442
Derivative, Swap Type, Average Fixed Price | $ / Barrels		22.86
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		0
Derivative, Swap Type, Average Fixed Price | $ / Barrels		0
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		0
Derivative, Swap Type, Average Fixed Price | $ / Barrels		0
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		3,214
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Second Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		182
Derivative, Swap Type, Average Fixed Price | $ / Barrels		32.53
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		163
Derivative, Swap Type, Average Fixed Price | $ / Barrels		32.42
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		149
Derivative, Swap Type, Average Fixed Price | $ / Barrels		32.34
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		138
Derivative, Swap Type, Average Fixed Price | $ / Barrels		35.41
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		0
Derivative, Swap Type, Average Fixed Price | $ / Barrels		0
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		0
Derivative, Swap Type, Average Fixed Price | $ / Barrels		0
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		632
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Second Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		157
Derivative, Swap Type, Average Fixed Price | $ / Barrels		33.38
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		140
Derivative, Swap Type, Average Fixed Price | $ / Barrels		33.28
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		128
Derivative, Swap Type, Average Fixed Price | $ / Barrels		33.23
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		119
Derivative, Swap Type, Average Fixed Price | $ / Barrels		35.44
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		0
Derivative, Swap Type, Average Fixed Price | $ / Barrels		0
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		0
Derivative, Swap Type, Average Fixed Price | $ / Barrels		0
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		544
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract Second Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		249
Derivative, Swap Type, Average Fixed Price | $ / Barrels		48.47
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		222
Derivative, Swap Type, Average Fixed Price | $ / Barrels		48.43
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		203
Derivative, Swap Type, Average Fixed Price | $ / Barrels		48.41
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		189
Derivative, Swap Type, Average Fixed Price | $ / Barrels		49.40
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		0
Derivative, Swap Type, Average Fixed Price | $ / Barrels		0
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		0
Derivative, Swap Type, Average Fixed Price | $ / Barrels		0
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		863
Subsequent Event [Member] | NYMEX Oil Collar Contract Fourth Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume				546
Derivative, Floor Price | $ / Barrels				50
Derivative, Cap Price | $ / Barrels				58.08
Subsequent Event [Member] | NYMEX Oil Collar Contract 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume				1,687
Derivative, Floor Price | $ / Barrels				50
Derivative, Cap Price | $ / Barrels				57.12
Subsequent Event [Member] | NYMEX Oil Collar Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume				468
Derivative, Floor Price | $ / Barrels				50
Derivative, Cap Price | $ / Barrels				56.20
Subsequent Event [Member] | NYMEX Oil Collar Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume				2,701
Subsequent Event [Member] | Oil Basis Swap Contract Third Quarter 2017 [Domain]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume				566
Derivative, Swap Type, Average Fixed Price | $ / Barrels	[4]			(1.62)
Subsequent Event [Member] | Oil Basis Swap Contract Fourth Quarter 2017 [Domain]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume				1,403
Derivative, Swap Type, Average Fixed Price | $ / Barrels	[4]			(1.55)
Subsequent Event [Member] | Oil Basis Swap Contract 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume				3,584
Derivative, Swap Type, Average Fixed Price | $ / Barrels	[4]			(1.50)
Subsequent Event [Member] | Oil Basis Swap Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume				2,375
Derivative, Swap Type, Average Fixed Price | $ / Barrels	[4]			(1.45)
Subsequent Event [Member] | Oil Basis Swap [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume				7,928
Subsequent Event [Member] | Gas Swaps Contract 2018 [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent				2.87
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU				17,236,000
Subsequent Event [Member] | Gas Swaps Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent				2.88
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU				9,378,000
Subsequent Event [Member] | Gas Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	[3]			26,614,000
Subsequent Event [Member] | OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract Second Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume				105
Derivative, Swap Type, Average Fixed Price | $ / Barrels				10.97
Subsequent Event [Member] | OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract Third Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume				170
Derivative, Swap Type, Average Fixed Price | $ / Barrels				10.98
Subsequent Event [Member] | OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract Fourth Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume				274
Derivative, Swap Type, Average Fixed Price | $ / Barrels				11.04
Subsequent Event [Member] | OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume				1,157
Derivative, Swap Type, Average Fixed Price | $ / Barrels				12.23
Subsequent Event [Member] | OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume				1,706
Subsequent Event [Member] | OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Second Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume				0
Derivative, Swap Type, Average Fixed Price | $ / Barrels				0
Subsequent Event [Member] | OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume				0
Derivative, Swap Type, Average Fixed Price | $ / Barrels				0
Subsequent Event [Member] | OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume				0
Derivative, Swap Type, Average Fixed Price | $ / Barrels				0
Subsequent Event [Member] | OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume				345
Derivative, Swap Type, Average Fixed Price | $ / Barrels				26.04
Subsequent Event [Member] | OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume				345
Subsequent Event [Member] | OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Second Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume				0
Derivative, Swap Type, Average Fixed Price | $ / Barrels				0
Subsequent Event [Member] | OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume				0
Derivative, Swap Type, Average Fixed Price | $ / Barrels				0
Subsequent Event [Member] | OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume				0
Derivative, Swap Type, Average Fixed Price | $ / Barrels				0
Subsequent Event [Member] | OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume				87
Derivative, Swap Type, Average Fixed Price | $ / Barrels				31.71
Subsequent Event [Member] | OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume				87
Subsequent Event [Member] | OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Second Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume				0
Derivative, Swap Type, Average Fixed Price | $ / Barrels				0
Subsequent Event [Member] | OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume				0
Derivative, Swap Type, Average Fixed Price | $ / Barrels				0
Subsequent Event [Member] | OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume				0
Derivative, Swap Type, Average Fixed Price | $ / Barrels				0
Subsequent Event [Member] | OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume				69
Derivative, Swap Type, Average Fixed Price | $ / Barrels				30.35
Subsequent Event [Member] | OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume				69
Subsequent Event [Member] | OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract Second Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume				0
Derivative, Swap Type, Average Fixed Price | $ / Barrels				0
Subsequent Event [Member] | OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume				0
Derivative, Swap Type, Average Fixed Price | $ / Barrels				0
Subsequent Event [Member] | OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume				0
Derivative, Swap Type, Average Fixed Price | $ / Barrels				0
Subsequent Event [Member] | OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume				116
Derivative, Swap Type, Average Fixed Price | $ / Barrels				47.36
Subsequent Event [Member] | OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume				116
[1]	Represents the price differential between WTI prices at Midland, Texas and WTI prices at Cushing, Oklahoma.
[2]	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 other cash or other consideration was included as part of the restructuring.
[3]	Total net volumes of natural gas swaps are comprised of IF El Paso Permian (2%), IF HSC (95%), and IF NNG Ventura (3%).
[4]	Represents the price differential between WTI prices at Midland, Texas and WTI prices at Cushing, Oklahoma.

Derivative Financial Instrume39

Derivative Financial Instruments Fair Value (Details) - USD ($) $ in Thousands	Mar. 31, 2017		Dec. 31, 2016
Fair value of derivative assets and liabilities
Derivative, Fair Value, Net	$ 23,058		$ (91,708)
Derivative asset current	73,978		54,521
Derivative asset noncurrent	84,195		67,575
Derivative Asset, Fair Value, Gross Asset	158,173		122,096
Derivative liability	53,809		115,464
Derivatives liability noncurrent	81,306		98,340
Derivative Liability, Fair Value, Gross Liability	135,115		213,804
Derivatives not designated as hedging instruments
Fair value of derivative assets and liabilities
Derivative asset current	73,978		54,521
Derivative asset noncurrent	84,195		67,575
Derivative liability	53,809		115,464
Derivatives liability noncurrent	81,306		98,340
Fair Value, Inputs, Level 2 [Member] | Derivatives not designated as hedging instruments | Fair Value, Measurements, Recurring [Member]
Fair value of derivative assets and liabilities
Derivative Asset, Fair Value, Gross Asset	158,173	[1]	122,096	[2]
Derivative Liability, Fair Value, Gross Liability	$ 135,115	[1]	$ 213,804	[2]
[1]	This represents a financial asset or liability that is measured at fair value on a recurring basis.
[2]	This represents a financial asset or liability that is measured at fair value on a recurring basis.

Derivative Financial Instrume40

Derivative Financial Instruments Offsetting of Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Offsetting of Derivative Assets and Liabilities [Abstract]
Derivative Asset, Fair Value, Gross Asset	$ 158,173	$ 122,096
Derivative Liability, Fair Value, Gross Liability	(135,115)	(213,804)
Derivative Asset, Not Offset, Policy Election Deduction	(88,952)	(118,080)
Derivative Liability, Not Offset, Policy Election Deduction	88,952	118,080
Derivative Asset, Fair Value, Offset Against Collateral, Net of Not Subject to Master Netting Arrangement, Policy Election	69,221	4,016
Derivative Liability, Fair Value, Offset Against Collateral, Net of Not Subject to Master Netting Arrangement, Policy Election	$ (46,163)	$ (95,724)

Derivative Financial Instrume41

Derivative Financial Instruments Gains and Losses (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Gain and loss from derivative cash settlements and changes in fair value of derivative contracts
Derivative settlement (gain) loss	$ (7)	$ (147,028)
Gain (Loss) on Derivative Instruments, Net, Pretax	114,774	14,228
NYMEX Oil Contracts [Member]
Gain and loss from derivative cash settlements and changes in fair value of derivative contracts
Derivative settlement (gain) loss	9,084	(99,992)
Gain (Loss) on Derivative Instruments, Net, Pretax	49,590	10,432
Gas Contracts [Member]
Gain and loss from derivative cash settlements and changes in fair value of derivative contracts
Derivative settlement (gain) loss	(17,506)	(41,053)
Gain (Loss) on Derivative Instruments, Net, Pretax	44,468	24,023
NGL Contracts [Member]
Gain and loss from derivative cash settlements and changes in fair value of derivative contracts
Derivative settlement (gain) loss	8,415	(5,983)
Gain (Loss) on Derivative Instruments, Net, Pretax	$ 20,716	$ (20,227)

Derivative Financial Instrume42

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

Fair Value Measurements Fair 43

Fair Value Measurements Fair Value (Details) - USD ($)	Mar. 31, 2017		Dec. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 158,173,000		$ 122,096,000
Property, Plant and Equipment, Net	5,450,120,000		6,081,354,000
Derivative Liability, Fair Value, Gross Liability	135,115,000		213,804,000
Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant and Equipment, Net	0	[1]	0	[2]
Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant and Equipment, Net	0	[1]	0	[2]
Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant and Equipment, Net	443,772,000	[1]	88,205,000	[2]
Derivatives not designated as hedging instruments | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	[3]	0	[4]
Derivative Liability, Fair Value, Gross Liability	0	[3]	0	[4]
Derivatives not designated as hedging instruments | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	158,173,000	[3]	122,096,000	[4]
Derivative Liability, Fair Value, Gross Liability	135,115,000	[3]	213,804,000	[4]
Derivatives not designated as hedging instruments | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	[3]	0	[4]
Derivative Liability, Fair Value, Gross Liability	$ 0	[3]	$ 0	[4]
[1]	This represents a non-financial asset that is measured at fair value on a nonrecurring basis.
[2]	This represents a non-financial asset that is measured at fair value on a nonrecurring basis.
[3]	This represents a financial asset or liability that is measured at fair value on a recurring basis.
[4]	This represents a financial asset or liability that is measured at fair value on a recurring basis.

Fair Value Measurements Long-te

Fair Value Measurements Long-term Debt (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Senior Notes [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Face Amount	$ 2,801,392	$ 2,803,736
Senior Notes [Member] | 6.50% Senior Notes Due 2021 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Debt Instrument, Face Amount	$ 344,611	346,955
Long-term Debt, Fair Value	$ 353,657	354,546
Senior Notes [Member] | 6.125% Senior Notes Due 2022 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.125%
Debt Instrument, Face Amount	$ 561,796	561,796
Long-term Debt, Fair Value	$ 572,330	570,925
Senior Notes [Member] | 6.50% Senior Notes Due 2023 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Debt Instrument, Face Amount	$ 394,985	394,985
Long-term Debt, Fair Value	$ 403,378	403,134
Senior Notes [Member] | 5% Senior Notes Due 2024 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.00%
Debt Instrument, Face Amount	$ 500,000	500,000
Long-term Debt, Fair Value	$ 472,500	475,975
Senior Notes [Member] | 5.625% Senior Notes Due 2025 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.625%
Debt Instrument, Face Amount	$ 500,000	500,000
Long-term Debt, Fair Value	$ 479,550	485,000
Senior Notes [Member] | 6.75% Senior Notes Due 2026 [Domain]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.75%
Debt Instrument, Face Amount	$ 500,000	500,000
Long-term Debt, Fair Value	$ 503,750	516,565
Convertible Debt [Member] | 1.50% Senior Convertible Notes Due 2021 [Domain]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	1.50%
Debt Instrument, Face Amount	$ 172,500	172,500
Long-term Debt, Fair Value	$ 171,355	$ 202,189

Fair Value Measurements Proved

Fair Value Measurements Proved and Unproved Oil and Gas Properties (Details) - USD ($) $ in Thousands	3 Months Ended			12 Months Ended
	Mar. 31, 2017		Mar. 31, 2016	Dec. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant and Equipment, Net	$ 5,450,120			$ 6,081,354
Period of New York Mercantile Exchange Strip Pricing Used for Price Forecast	5 years
Impairment of Proved Oil and Gas Properties	$ 0		$ 269,785
Abandonment and impairment of unproved properties	0		2,311
Disposal Group, Not Discontinued Operation, Loss (Gain) on Write-down			68,300
Fair Value, Measurements, Nonrecurring [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant and Equipment, Net	$ 443,772	[1]		$ 88,205	[2]
Oil and Gas Properties [Member] | Minimum [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Discount Rate	10.00%			10.00%
Oil and Gas Properties [Member] | Maximum [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Discount Rate	15.00%			15.00%
Divide County Divestiture 2017 [Member] | Disposal Group, Held-for-sale, Not Discontinued Operations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of Proved Oil and Gas Properties	$ 359,600
Abandonment and impairment of unproved properties			$ 1,600
[1]	This represents a non-financial asset that is measured at fair value on a nonrecurring basis.
[2]	This represents a non-financial asset that is measured at fair value on a nonrecurring basis.