SM Energy (SM) 10-Q 3 Aug 16 2016 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information Document - shares	6 Months Ended
	Jun. 30, 2016	Jul. 27, 2016
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	Jun. 30, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Common Stock, Shares Outstanding		68,466,823
Entity Current Reporting Status	Yes

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) (in thousands, except share amounts) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Assets
Cash and cash equivalents	$ 18	$ 18
Accounts receivable	143,979	134,124
Derivative asset	145,576	367,710
Prepaid expenses and other	14,901	17,137
Total current assets	304,474	518,989
Proved oil and gas properties	7,249,808	7,606,405
Less - accumulated depletion, depreciation, and amortization	(3,606,829)	(3,481,836)
Unproved oil and gas properties	222,967	284,538
Wells in progress	415,973	387,432
Oil and gas properties held for sale, net	173,001	641
Other property and equipment, net of accumulated depreciation of $38,175 and $32,956, respectively	146,412	153,100
Total property and equipment, net	4,601,332	4,950,280
Derivative asset	113,119	120,701
Other noncurrent assets	25,550	31,673
Total other noncurrent assets	138,669	152,374
Total Assets	5,044,475	5,621,643
Liabilities
Accounts payable and accrued expenses	257,349	302,517
Derivative liability	63,492	8
Total current liabilities	320,841	302,525
Revolving credit facility	330,500	202,000
Senior Notes, net of unamortized deferred financing costs (note 5)	2,272,580	2,315,970
Asset retirement obligation	108,331	137,284
Asset retirement obligation associated with oil and gas properties held for sale	32,055	241
Net Profits Plan liability	9,476	7,611
Deferred income taxes	472,355	758,279
Derivative liability	104,660	0
Other noncurrent liabilities	44,841	45,332
Total noncurrent liabilities	3,374,798	3,466,717
Commitments and contingencies (note 6)
Stockholders' equity:
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding; 68,274,551 and 68,075,700, respectively	683	681
Additional paid-in-capital	321,841	305,607
Retained earnings	1,040,219	1,559,515
Accumulated other comprehensive loss	(13,907)	(13,402)
Total stockholders' equity	1,348,836	1,852,401
Total Liabilities and Stockholders' Equity	$ 5,044,475	$ 5,621,643

Balance Sheet Parenthetical (Pa

Balance Sheet Parenthetical (Parentheticals) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Property, Plant and Equipment, Other, Accumulated Depreciation	$ 38,175	$ 32,956
Common Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Common Stock, Shares Authorized	200,000,000	200,000,000
Common Stock, Shares, Issued	68,274,551	68,075,700
Common Stock, Shares, Outstanding	68,274,551	68,075,700

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED) (in thousands, except per share amounts) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Operating revenues:
Oil, gas, and NGL production revenue	$ 291,142	$ 441,256	$ 502,965	$ 834,571
Net gain (loss) on divestiture activity (note 3)	50,046	71,884	(18,975)	36,082
Other operating revenues	626	3,006	900	11,427
Total operating revenues and other income	341,814	516,146	484,890	882,080
Operating expenses:
Oil, gas, and NGL production expense	148,591	173,685	293,134	369,836
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	211,020	219,704	425,227	437,105
Exploration	13,187	25,541	28,460	62,948
Impairment of proved properties	0	12,914	269,785	68,440
Abandonment and impairment of unproved properties	38	5,819	2,349	17,446
General and administrative	28,200	42,605	60,438	86,244
Change in Net Profits Plan liability	3,125	(4,476)	1,865	(8,810)
Derivative (gain) loss	163,351	80,929	149,123	(73,238)
Other operating expenses	4,851	10,304	11,783	27,423
Total operating expenses	572,363	567,025	1,242,164	987,394
Loss from operations	(230,549)	(50,879)	(757,274)	(105,314)
Non-operating income (expense):
Interest income	5	25	11	596
Interest expense	(34,035)	(30,779)	(65,123)	(63,426)
Gain (loss) on extinguishment of debt	0	(16,578)	15,722	(16,578)
Loss before income taxes	(264,579)	(98,211)	(806,664)	(184,722)
Income tax benefit	95,898	40,703	290,773	74,156
Net loss	$ (168,681)	$ (57,508)	$ (515,891)	$ (110,566)
Basic weighted-average common shares outstanding	68,102	67,483	68,090	67,473
Diluted weighted-average common shares outstanding	68,102	67,483	68,090	67,473
Basic net loss per common share	$ (2.48)	$ (0.85)	$ (7.58)	$ (1.64)
Diluted net loss per common share	(2.48)	(0.85)	(7.58)	(1.64)
Dividends per common share	$ 0	$ 0	$ 0.05	$ 0.05

CONDENSED CONSOLIDATED STATEME5

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Statement of Comprehensive Income [Abstract]
Net loss	$ (168,681)	$ (57,508)	$ (515,891)	$ (110,566)
Pension liability adjustment	(269)	(576)	(505)	(752)
Total other comprehensive loss, net of tax	(269)	(576)	(505)	(752)
Total comprehensive loss	$ (168,950)	$ (58,084)	$ (516,396)	$ (111,318)

CONDENSED CONSOLIDATED STATEME6

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Statement of Cash Flows [Abstract]
Net loss	$ (515,891)	$ (110,566)
Adjustments to reconcile net loss to net cash provided by operating activities:
Net (gain) loss on divestiture activity	18,975	(36,082)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	425,227	437,105
Exploratory dry hole expense	(24)	22,896
Impairment of proved properties	269,785	68,440
Abandonment and impairment of unproved properties	2,349	17,446
Stock-based compensation expense	13,915	13,215
Change in Net Profits Plan liability	1,865	(8,810)
Derivative gain (loss)	149,123	(73,238)
Derivative settlement gain	248,738	274,024
Amortization of deferred financing costs	1,930	3,892
Non-cash (gain) loss on extinguishment of debt, net	(15,722)	4,123
Deferred income taxes	(291,014)	(84,556)
Plugging and abandonment	(2,716)	(3,386)
Other, net	676	(434)
Changes in current assets and liabilities:
Accounts receivable	(11,220)	38,951
Prepaid expenses and other	8,487	2,933
Accounts payable and accrued expenses	(61,727)	(34,040)
Accrued derivative settlements	14,117	17,595
Net cash provided by operating activities	256,873	549,508
Cash flows from investing activities:
Net proceeds from the sale of oil and gas properties	12,967	334,988
Capital expenditures	(345,570)	(974,130)
Acquisition of proved and unproved oil and gas properties	(17,751)	(6,588)
Other, net	(900)	(996)
Net Cash Used in Investing Activities	(351,254)	(646,726)
Cash flows from financing activities:
Proceeds from credit facility	585,000	1,230,500
Repayment of credit facility	(456,500)	(1,274,500)
Debt issuance costs related to credit facility	(3,132)	0
Net proceeds from Senior Notes	0	491,557
Cash paid to repurchase Senior Notes	(29,904)	(350,000)
Proceeds from sale of common stock	2,354	3,157
Payments of Ordinary Dividends, Common Stock	(3,404)	(3,373)
Other, net	(33)	(161)
Net Cash Provided by Financing Activities	94,381	97,180
Net change in cash and cash equivalents	0	(38)
Cash and cash equivalents at beginning of period	18	120
Cash and cash equivalents at end of period	18	82
Supplemental schedule of additional cash flow information and non-cash activities:
Cash paid for interest, net of capitalized interest	63,590	64,899
Net cash (refunded) paid for income taxes	$ (4,564)	$ 380

CONDENSED CONSOLIDATED STATEME7

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (in thousands) (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2016	Jun. 30, 2015
Accounts Payable and Accrued Liabilities [Member]
Other Significant Noncash Transactions [Line Items]
Capital Expenditures Incurred but Not yet Paid - Instant	$ 106.7	$ 164.9

The Company and Business

The Company and Business	6 Months Ended
	Jun. 30, 2016
Company and Business Disclosure [Abstract]
The Company and Business	Note 1 - The Company and Business SM Energy Company (“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	6 Months Ended
	Jun. 30, 2016
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, 2015 (the “ 2015 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 June 30, 2016 , through the filing date of this report. Certain prior period amounts have been reclassified to conform to the current period 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 2015 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 2015 Form 10-K. Recently Issued Accounting Standards Effective January 1, 2016, the Company adopted, on a retrospective basis, Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis . This ASU clarifies the consolidation reporting guidance in GAAP. There was no impact to the Company’s financial statements or disclosures from the adoption of this standard. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which changes the accounting for leases. This guidance is to be applied using a modified retrospective method and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2018. Early adoption is permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”) for the recognition of revenue from contracts with customers. Subsequent to the issuance of this ASU, the FASB has issued additional related ASUs as follows: • In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date . This ASU deferred the effective date of ASU 2014-09 by one year. • In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net) . This ASU amends the principal versus agent guidance in ASU No. 2014-09. • In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing . This ASU amends the identification of performance obligations and accounting for licenses in ASU 2014-09. • In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients. This ASU amends certain issues in ASU 2014-09 on transition, collectibility, noncash consideration, and the presentation of sales taxes and other similar taxes. ASU 2014-09 and each update have the same effective date and transition requirements. That is, the guidance under these standards is to be applied using a full retrospective method or a modified retrospective method, as outlined in ASU 2014-09, and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted only for annual periods, and interim periods within those annual periods, beginning after December 15, 2016. The Company is currently evaluating the level of effort needed to implement the standards, evaluating the provisions of each of these standards, and assessing their impact on the Company’s financial statements and disclosures, as well as determining whether to use the full retrospective method or the modified retrospective method. In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting . This ASU makes targeted amendments to the accounting for employee share-based payments. This guidance is to be applied using various transition methods, such as full retrospective, modified retrospective, and prospective, based on the criteria for the specific amendments as outlined in the guidance. The guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2016. Early adoption is permitted, as long as all of the amendments are adopted in the same period. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures. Other than as disclosed above or in the 2015 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 June 30, 2016 , and through the filing date of this report.

Assets Held for Sale and Divest

Assets Held for Sale and Divestitures	6 Months Ended
	Jun. 30, 2016
Assets held for sale and divestitures [Abstract]
Assets Held for Sale and Divestitures	Note 3 – Assets Held for Sale and Divestitures 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 June 30, 2016 , the accompanying condensed consolidated balance sheets (“accompanying balance sheets”) present $173.0 million of assets held for sale, net of accumulated depletion, depreciation, and amortization expense, which consists of certain non-core assets in each of the Company’s operating regions. A corresponding aggregate asset retirement obligation liability of $32.1 million is separately presented. Certain of these assets were written down by $68.3 million to reflect fair value less estimated costs to sell upon reclassification to assets held for sale, as of March 31, 2016. During the second quarter of 2016, the Company estimated an increase in the fair value of certain previously impaired assets held for sale due to an increase in estimated selling prices, as evidenced by recent bid prices received from third parties, resulting in a $49.5 million gain recorded for the three months ended June 30, 2016. The Company expects to close the asset sale transactions prior to December 31, 2016. There were no material assets held for sale as of December 31, 2015. Subsequent to June 30, 2016, the Company entered into separate purchase and sale agreements for the sale of certain of its Permian and Rocky Mountain assets that were classified as held for sale as of June 30, 2016. The Company expects to close these transactions prior to December 31, 2016. The closings of these transactions are subject to the satisfaction of customary closing conditions, and there can be no assurance that these transactions will close on the expected closing dates or at all. Divestitures During the second quarter of 2015, the Company divested its Mid-Continent assets in separate packages for total cash proceeds received at closing of $316.5 million and recorded an estimated net gain of $107.8 million for the six months ended June 30, 2015. These assets were classified as held for sale as of March 31, 2015, and certain of these assets were written down by $30.0 million during the three months ended March 31, 2015, to reflect their fair value less estimated costs to sell. This write-down is reflected in the total net gain of $107.8 million discussed above. In conjunction with this divestiture, the Company closed its Tulsa, Oklahoma office in 2015 and incurred $5.0 million and $8.5 million of exit and disposal costs for the three and six months ended June 30, 2015, respectively. Offsetting the net gain recorded on the divestiture of the Company’s Mid-Continent assets were write-downs recorded during the three months ended June 30, 2015, on certain other assets held for sale totaling $66.0 million . The Company determined that neither these planned nor executed asset sales qualified for discontinued operations accounting under financial statement presentation authoritative guidance.

Income Taxes

Income Taxes	6 Months Ended
	Jun. 30, 2016
Income Tax Disclosure [Abstract]
Income Taxes	Note 4 - Income Taxes The income tax benefit recorded for the three and six months ended June 30, 2016 , and 2015 , 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, research and development (“R&D”) credits, and other permanent differences. The quarterly rate can also be affected by the proportional effects of forecasted net income or loss as of each period end presented. The provision for income taxes consists of the following: For the Three Months Ended June 30, For the Six Months Ended June 30, 2016 2015 2016 2015 (in thousands) Current portion of income tax expense (benefit): Federal $ — $ — $ — $ — State 77 10,126 241 10,400 Deferred portion of income tax benefit (95,975 ) (50,829 ) (291,014 ) (84,556 ) Total income tax benefit $ (95,898 ) $ (40,703 ) $ (290,773 ) $ (74,156 ) Effective tax rate 36.2 % 41.4 % 36.0 % 40.1 % 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 various state tax jurisdictions. Cumulative effects of state rate changes are reflected in the period legislation is enacted. The Company is generally no longer subject to United States federal or state income tax examinations by tax authorities for years before 2012 . During the first quarter of 2016, the Company received an expected $4.9 million refund of tax and interest after the Company and the Internal Revenue Service (“IRS”) reached a final agreement on the examination of the Company’s 2007 - 2011 tax years. There were no material adjustments to previously reported amounts. During the quarter ended September 30, 2015, the IRS initiated an audit of the tax partnership between the Company and Mitsui E&P Texas LP for the 2013 tax year. The Company has a significant investment in the underlying assets of this tax partnership. The Company received notice during the first quarter of 2016 that the IRS concluded the audit with no adjustments.

Long-Term Debt

Long-Term Debt	6 Months Ended
	Jun. 30, 2016
Debt Disclosure [Abstract]
Long-term debt	Note 5 - Long-Term Debt Revolving Credit Facility On April 8, 2016 , the Company entered into a Sixth Amendment to the Fifth Amended and Restated Credit Agreement (the “Credit Agreement” and as amended, the “Amended Credit Agreement”) with its lenders. The Company incurred approximately $3.1 million in deferred financing costs associated with the amendment of this credit facility. The Amended Credit Agreement provides for a maximum loan amount of $2.5 billion and has a maturity date of December 10, 2019 . Pursuant to the amendment, and as part of the regular, semi-annual borrowing base redetermination process, the Company’s borrowing base was reduced to $1.25 billion . This expected reduction was primarily due to the decline in commodity prices, which had resulted in a decrease in the Company’s proved reserves as of December 31, 2015. The next scheduled redetermination date is October 1, 2016 . The borrowing base redetermination process considers the value of both the Company’s (a) proved oil and gas properties reflected in the Company’s most recent reserve report and (b) commodity derivative contracts, each as determined by the Company’s lender group. The amendment also reduced the aggregate lender commitments to $1.25 billion , and changed the required percentage of oil and gas properties subject to a mortgage to at least 90 percent of the total PV-9 of the Company’s proved oil and gas properties evaluated in the most recent reserve report. Further, the amendment revised certain of the Company’s covenants under the Credit Agreement and modified the borrowing base utilization grid, as discussed below. The Company must comply with certain financial and non-financial covenants under the terms of the Amended Credit Agreement, including covenants limiting dividend payments and requiring the Company to maintain certain financial ratios, as defined by the Amended Credit Agreement. Financial covenants under the Amended 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 Amended Credit Agreement as of June 30, 2016 , and through the filing date of this report. Interest and commitment fees are accrued based on a borrowing base utilization grid set forth in the Amended Credit Agreement. Eurodollar loans accrue interest at the London Interbank Offered Rate plus the applicable margin from the utilization table below, and Alternate Base Rate (“ABR”) and swingline loans accrue interest at prime plus the applicable margin from the utilization table below. Commitment fees are accrued on the unused portion of the aggregate commitment amount and are included in interest expense in the accompanying statements of operations. Effective as of April 8, 2016 , the revised borrowing base utilization grid under the Amended Credit Agreement is as follows: Borrowing Base Utilization Grid Borrowing Base Utilization Percentage <25% ≥25% <50% ≥50% <75% ≥75% <90% ≥90% Eurodollar Loans 1.750 % 2.000 % 2.250 % 2.500 % 2.750 % ABR Loans or Swingline Loans 0.750 % 1.000 % 1.250 % 1.500 % 1.750 % Commitment Fee Rate 0.300 % 0.300 % 0.350 % 0.375 % 0.375 % The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Amended Credit Agreement as of July 27, 2016 , and June 30, 2016 , and under the Credit Agreement as of December 31, 2015 : As of July 27, 2016 As of June 30, 2016 As of December 31, 2015 (in thousands) Credit facility balance (1) $ 330,000 $ 330,500 $ 202,000 Letters of credit (2) $ 200 $ 200 $ 200 Available borrowing capacity $ 919,800 $ 919,300 $ 1,297,800 ____________________________________________ (1) Deferred financing costs attributable to the credit facility are presented as a component of other noncurrent assets on the accompanying balance sheets and thus are not deducted from the credit facility balance. (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, and 5.625% Senior Notes due 2025 (collectively referred to as “Senior Notes”). The Senior Notes, net of unamortized deferred financing costs line on the accompanying balance sheets as of June 30, 2016 , and December 31, 2015 , consisted of the following: As of June 30, 2016 As of December 31, 2015 Senior Notes Unamortized Deferred Financing Costs Senior Notes, Net of Unamortized Deferred Financing Costs Senior Notes Unamortized Deferred Financing Costs Senior Notes, Net of Unamortized Deferred Financing Costs (in thousands) 6.50% Senior Notes due 2021 $ 346,955 $ 3,721 $ 343,234 $ 350,000 $ 4,106 $ 345,894 6.125% Senior Notes due 2022 561,796 7,569 554,227 600,000 8,714 591,286 6.50% Senior Notes due 2023 394,985 4,801 390,184 400,000 5,231 394,769 5.0% Senior Notes due 2024 500,000 6,994 493,006 500,000 7,455 492,545 5.625% Senior Notes due 2025 500,000 8,071 491,929 500,000 8,524 491,476 Total $ 2,303,736 $ 31,156 $ 2,272,580 $ 2,350,000 $ 34,030 $ 2,315,970 The Senior Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt, and are senior in right of payment to any future subordinated debt. There are no subsidiary guarantors of the Senior Notes. The Company is subject to certain covenants under the indentures governing the Senior Notes that limit the Company’s ability to incur additional indebtedness, issue preferred stock, and make restricted payments, including dividends; however, the first $6.5 million of dividends paid each year are not restricted by the restricted payment covenant. The Company was in compliance with all covenants under its Senior Notes as of June 30, 2016 , and through the filing date 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. During the first quarter of 2016, the Company repurchased in open market transactions a total of $46.3 million in aggregate principal amount of its 6.50% Senior Notes due 2021, 6.125% Senior Notes due 2022, and 6.50% Senior Notes due 2023 for a settlement amount of $29.9 million , excluding interest. Of the $29.9 million settlement amount, $10.0 million related to purchases during the first quarter of 2016, in which the related cash settlement occurred during the three months ended June 30, 2016 . The Company recorded a net gain on extinguishment of debt of approximately $15.7 million for the six months ended June 30, 2016. This amount includes a gain of $16.4 million associated with the discount realized upon repurchase, which was partially offset by approximately $700,000 related to the acceleration of unamortized deferred financing costs. The Company accounted for the repurchases under the extinguishment method of accounting. The Company canceled all repurchased notes upon cash settlement.

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 6 - Commitments and Contingencies Commitments There were no material changes in commitments during the first half of 2016 , except as discussed below. Please refer to Note 6 - Commitments and Contingencies in the Company’s 2015 Form 10-K for additional discussion. During the second quarter of 2016, the Company entered into a water disposal agreement. Under the agreement, the Company is committed to deliver 25.4 MMBbl of water for treatment through 2026. In the event that the Company does not deliver any volumes under this agreement, the Company’s aggregate undiscounted deficiency payments would be approximately $23.0 million . This commitment will not be effective until the counterparty constructs and places the associated pipeline into operation, which is expected to be by the end of 2016. During the first half of 2016, the Company renegotiated the terms of certain drilling rig contracts to provide flexibility concerning the timing of activity and payment. For the three and six months ended June 30, 2016 , the Company incurred $2.6 million and $7.6 million , respectively, of expense related to the early termination of drilling rig contracts or fees incurred for rigs placed on standby, which are recorded in the other operating expenses line item in the accompanying statements of operations. For the three and six months ended June 30, 2015 , the Company incurred drilling rig termination fees of $2.7 million and $5.9 million , respectively. During the first quarter of 2016 , the Company entered into amendments to certain oil gathering and gas gathering agreements related to its outside-operated Eagle Ford shale assets, neither of which previously had a minimum volume commitment, in order to obtain more favorable rates and terms. Under these amended agreements, as of June 30, 2016, the Company is now committed to deliver 296 Bcf of natural gas and 39 MMBbl of oil through 2034. In the event that the Company delivers no product under these amended agreements, the Company’s aggregate undiscounted deficiency payments would be approximately $342.0 million at June 30, 2016 ; however, because of the Company’s partial ownership interest in the gathering systems used to provide the services under these agreements, the Company is entitled to receive its share of operating income generated by the systems, and thus would expect to receive approximately $241.4 million if the $342.0 million shortfall payment was required. During the first quarter of 2016 , the Company entered into an amendment to a gas gathering agreement related to its operated Eagle Ford shale assets, which reduced the Company’s volume commitment amount as of December 31, 2015, by 829 Bcf, and reduced the aggregate undiscounted deficiency payments, in the event no product is delivered, by $118.2 million through 2021. As of June 30, 2016 , the Company had total gas, oil, and NGL gathering, processing, and transportation throughput commitments with various third parties that require delivery of a minimum amount of 1,590 Bcf of natural gas, 72 MMBbl of crude oil, and 14 MMBbl of natural gas liquids through 2034. If the Company delivers no product, the aggregate undiscounted deficiency payments total approximately $1.0 billion through 2034, prior to considering the $241.4 million of operating income the Company would expect to receive if certain payments were required as discussed above. As of the filing date of this report, the Company does not expect to incur any material shortfalls with regard to its gas, oil, and NGL gathering, processing, and transportation throughput 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. The Company is subject to routine severance, royalty and joint interest audits from regulatory authorities, non-operators and others, as the case may be, and records accruals for estimated exposure when a claim is deemed probable and the amount can be reasonably estimated. Additionally, the Company is subject to various possible contingencies that arise from third party interpretations of the Company’s contracts or otherwise affecting the oil and natural gas industry. Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices that royalty owners are paid for production from their leases, allowable costs under joint interest arrangements, and other matters. As of June 30, 2016 , the Company had $4.4 million accrued for estimated exposure related to potential claims for payment of royalties on certain Federal and Indian oil and gas leases. Although the Company believes that it has properly estimated its potential exposure with respect to these claims based on various contracts, laws and regulations, administrative rulings, and interpretations thereof, adjustments could be required as new interpretations and regulations arise.

Compensation Plans

Compensation Plans	6 Months Ended
	Jun. 30, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Compensation Plans	Note 7 - Compensation Plans Equity Incentive Compensation Plan As of June 30, 2016, 6.2 million shares of common stock remained available for grant under the Equity Incentive Compensation Plan. 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 the PSUs are based on a combination of the Company’s annualized Total Shareholder Return (“TSR”) for the performance period and the relative performance of the Company’s TSR compared with the annualized TSR of certain peer companies for the performance period. Compensation expense for PSUs is recognized within general and administrative and exploration expense over the vesting periods of the respective awards. Total compensation expense recorded for PSUs for the three months ended June 30, 2016 , and 2015 , was $3.0 million and $2.7 million , respectively, and $5.9 million and $5.0 million for the six months ended June 30, 2016 , and 2015 , respectively. As of June 30, 2016 , there was $12.3 million of total unrecognized compensation expense related to unvested PSU awards, which is being amortized through 2018 . There were no material changes to the outstanding and non-vested PSUs during the six months ended June 30, 2016 . Subsequent to June 30, 2016 , as part of its regular annual long-term equity compensation program, the Company granted 447,971 PSUs with a fair value of $11.9 million . These PSUs will fully vest on the third anniversary of the date of the grant. Also, subsequent to June 30, 2016 , the Company settled PSUs that were granted in 2013, which earned a 0.2 times multiplier, by issuing a net 30,061 shares of the Company’s common stock in accordance with the terms of the respective PSU awards. The Company and the majority of grant participants mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings as provided for in the plan document and award agreements. As a result, 14,809 shares were withheld to satisfy income and payroll tax withholding obligations that occurred upon delivery of the shares underlying those PSUs. 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. Compensation expense for RSUs is recognized within general and administrative expense and exploration expense over the vesting periods of the award. Total compensation expense recorded for RSUs was $3.3 million and $2.9 million for the three months ended June 30, 2016 , and 2015 , respectively, and $6.5 million and $5.8 million for the six months ended June 30, 2016 , and 2015 , respectively. As of June 30, 2016 , there was $12.0 million of total unrecognized compensation expense related to unvested RSU awards, which is being amortized through 2018 . There were no material changes to the outstanding and non-vested RSUs during the six months ended June 30, 2016 . Subsequent to June 30, 2016 , as part of its regular annual long-term equity compensation program, the Company granted 417,065 RSUs with a fair value of $11.7 million . These RSUs will vest one-third of the total grant on each of the next three anniversary dates of the grant. Also, subsequent to June 30, 2016 , the Company settled 232,258 RSUs that related to awards granted in previous years. The Company and the majority of grant participants mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings as provided for in the plan document and award agreements. As a result, the Company issued 162,211 net shares of common stock. The remaining 70,047 shares were withheld to satisfy income and payroll tax withholding obligations that occurred upon delivery of the shares underlying those RSUs. Director Shares During the first half of 2016 and 2015 , the Company issued 53,473 and 37,950 shares, respectively, of its common stock to its non-employee directors, under the Company’s Equity Incentive Compensation Plan and recorded $517,000 and $1.2 million , respectively, of compensation expense. Beginning with 2016, all shares issued to non-employee directors fully vest on December 31 st of the year granted. Employee Stock Purchase Plan Under the Company’s Employee Stock Purchase Plan (“ESPP”), eligible employees may purchase shares of the Company’s common stock through payroll deductions of up to 15 percent of eligible compensation, without accruing in excess of $25,000 in value from purchases for each calendar year. The purchase price of the stock is 85 percent of the lower of the fair market value of the stock on the first or last day of the purchase period, and shares issued under the ESPP have no restriction period. The ESPP is intended to qualify under Section 423 of the Internal Revenue Code (“IRC”). The Company had 808,854 shares available for issuance under the ESPP as of June 30, 2016 . There were 140,853 and 96,285 shares issued under the ESPP during the second quarters of 2016 , and 2015 , respectively. The fair value of ESPP grants is measured at the date of grant using the Black-Scholes option-pricing model.

Pension Benefits

Pension Benefits	6 Months Ended
	Jun. 30, 2016
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, will 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 June 30, For the Six Months Ended June 30, 2016 2015 2016 2015 (in thousands) Service cost $ 2,113 $ 2,390 $ 4,100 $ 3,974 Interest cost 830 700 1,454 1,248 Expected return on plan assets that reduces periodic pension cost (573 ) (597 ) (1,118 ) (1,091 ) Amortization of prior service cost 5 5 9 9 Amortization of net actuarial loss 419 571 791 743 Net periodic benefit cost $ 2,794 $ 3,069 $ 5,236 $ 4,883 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 and the market-related value of assets are amortized over the average remaining service period of active participants. Contributions The Company contributed $6.0 million to the Pension Plans during the six months ended June 30, 2016 .

Earnings per Share

Earnings per Share	6 Months Ended
	Jun. 30, 2016
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 common shares outstanding for the respective period. The earnings per share calculations reflect the impact of any repurchases of shares of common stock made by the Company. Diluted net income or loss per common share is calculated by dividing adjusted net income or loss by the diluted weighted-average common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist of unvested RSUs and contingent PSUs. The treasury stock method is used to measure the dilutive impact of these stock awards. 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. Please refer to Note 7 - Compensation Plans for additional discussion of the RSUs and PSUs granted subsequent to June 30, 2016 , as part of the Company’s regular annual long-term equity compensation program, in addition to the net RSUs and PSUs settled. When the Company recognizes a loss from continuing operations, as was the case for the three and six months ended June 30, 2016 , and 2015 , all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted net loss per common share. The following table details the weighted-average anti-dilutive securities related to RSUs and PSUs for the periods presented: For the Three Months Ended June 30, For the Six Months Ended June 30, 2016 2015 2016 2015 (in thousands) Anti-dilutive 155 590 70 490 The following table sets forth the calculations of basic and diluted earnings per share: For the Three Months Ended June 30, For the Six Months Ended June 30, 2016 2015 2016 2015 (in thousands, except per share amounts) Net loss $ (168,681 ) $ (57,508 ) $ (515,891 ) $ (110,566 ) Basic weighted-average common shares outstanding 68,102 67,483 68,090 67,473 Add: dilutive effect of unvested RSUs and contingent PSUs — — — — Diluted weighted-average common shares outstanding 68,102 67,483 68,090 67,473 Basic net loss per common share $ (2.48 ) $ (0.85 ) $ (7.58 ) $ (1.64 ) Diluted net loss per common share $ (2.48 ) $ (0.85 ) $ (7.58 ) $ (1.64 )

Derivative Financial Instrument

Derivative Financial Instruments	6 Months Ended
	Jun. 30, 2016
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. All contracts are 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 June 30, 2016 , the Company had commodity derivative contracts outstanding through the second quarter of 2020 as summarized in the tables below. During the three months ended March 31, 2016, the Company restructured certain of its gas derivative contracts by buying fixed price volumes to offset existing 2018 and 2019 fixed price swap contracts totaling 55.0 million MMBtu. The Company then entered into new 2017 fixed price swap contracts totaling 38.6 million MMBtu with a contract price of $4.43 per MMBtu. No cash or other consideration was included as part of the restructuring. Subsequent to June 30, 2016, the Company entered into derivative fixed price swap contracts through the first quarter of 2018 for a total of 15.6 million MMBtu of gas production at contract prices ranging from $2.90 to $3.24 per MMBtu, and derivative fixed price swap contracts through the fourth quarter of 2018 for 1.4 million Bbls of NGL production at contract prices ranging from $21.32 per Bbl to $21.79 per Bbl. Additionally, subsequent to June 30, 2016, the Company entered into a derivative collar contract through the fourth quarter of 2017 for a total of 1.4 million Bbls of crude oil production with a contract floor price of $45.00 per Bbl and a contract ceiling price of $56.25 per Bbl. The following tables summarize the approximate volumes and average contract prices of contracts the Company had in place as of June 30, 2016 : Oil Swaps Contract Period NYMEX WTI Volumes Weighted-Average Contract Price (MBbls) (per Bbl) Third quarter 2016 1,840 $ 71.80 Fourth quarter 2016 1,399 $ 67.73 2017 3,053 $ 45.61 All oil swaps 6,292 Oil Collars Contract Period NYMEX WTI Volumes Weighted- Average Floor Price Weighted- Average Ceiling Price (MBbls) (per Bbl) (per Bbl) Third quarter 2016 672 $ 40.00 $ 51.57 Fourth quarter 2016 881 $ 40.00 $ 51.52 2017 1,018 $ 45.00 $ 51.02 All oil collars 2,571 Natural Gas Swaps Contract Period Sold Volumes Weighted-Average Contract Price Purchased Volumes Weighted- Average Contract Price Net Volumes (BBtu) (per MMBtu) (BBtu) (per MMBtu) (BBtu) Third quarter 2016 25,724 $ 3.13 — $ — 25,724 Fourth quarter 2016 26,700 $ 3.34 — $ — 26,700 2017 88,894 $ 4.04 — $ — 88,894 2018 53,048 $ 3.75 (30,606 ) $ 4.27 22,442 2019 24,415 $ 4.34 (24,415 ) $ 4.34 — All gas swaps* 218,781 (55,021 ) 163,760 *Total net volumes of natural gas swaps are comprised of IF El Paso Permian ( 2% ), IF HSC ( 97% ), and IF NNG Ventura ( 1% ). NGL Swaps OPIS Purity Ethane Mont Belvieu OPIS Propane Mont Belvieu Non-TET OPIS Normal Butane Mont Belvieu Non-TET OPS Isobutane Mont Belvieu Non-TET Contract Period Volumes Weighted-Average Contract Price Volumes Weighted-Average Volumes Weighted-Average Volumes Weighted-Average (MBbls) (per Bbl) (MBbls) (per Bbl) (MBbls) (per Bbl) (MBbls) (per Bbl) Third quarter 2016 751 $ 8.70 863 $ 19.03 248 $ 22.90 200 $ 23.24 Fourth quarter 2016 687 $ 8.71 792 $ 18.53 226 $ 22.91 182 $ 23.25 2017 3,062 $ 8.92 721 $ 20.01 — $ — — $ — 2018 2,435 $ 10.18 — $ — — $ — — $ — 2019 1,200 $ 10.92 — $ — — $ — — $ — 2020 539 $ 11.13 — $ — — $ — — $ — Total NGL swaps 8,674 2,376 474 382 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 $90.5 million as of June 30, 2016 , and a net asset of $488.4 million as of December 31, 2015 . The following tables detail the fair value of derivatives recorded in the accompanying balance sheets, by category: As of June 30, 2016 Derivative Assets Derivative Liabilities Balance Sheet Classification Fair Value Balance Sheet Classification Fair Value (in thousands) Commodity contracts Current assets $ 145,576 Current liabilities $ 63,492 Commodity contracts Noncurrent assets 113,119 Noncurrent liabilities 104,660 Derivatives not designated as hedging instruments $ 258,695 $ 168,152 As of December 31, 2015 Derivative Assets Derivative Liabilities Balance Sheet Classification Fair Value Balance Sheet Classification Fair Value (in thousands) Commodity contracts Current assets $ 367,710 Current liabilities $ 8 Commodity contracts Noncurrent assets 120,701 Noncurrent liabilities — Derivatives not designated as hedging instruments $ 488,411 $ 8 Offsetting of Derivative Assets and Liabilities As of June 30, 2016 , and December 31, 2015 , 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 June 30, 2016 December 31, 2015 June 30, 2016 December 31, 2015 (in thousands) Gross amounts presented in the accompanying balance sheets $ 258,695 $ 488,411 $ (168,152 ) $ (8 ) Amounts not offset in the accompanying balance sheets (158,955 ) (8 ) 158,955 8 Net amounts $ 99,740 $ 488,403 $ (9,197 ) $ — The following table summarizes the components of the derivative (gain) loss presented in the accompanying statements of operations: For the Three Months Ended June 30, For the Six Months Ended June 30, 2016 2015 2016 2015 (in thousands) Derivative settlement (gain) loss: Oil contracts $ (72,164 ) $ (73,915 ) $ (172,156 ) $ (180,129 ) Gas contracts (1) (31,439 ) (38,880 ) (72,492 ) (73,112 ) NGL contracts 1,893 — (4,090 ) (20,783 ) Total derivative settlement (gain) loss $ (101,710 ) $ (112,795 ) $ (248,738 ) $ (274,024 ) Total derivative (gain) loss: Oil contracts $ 60,773 $ 66,749 $ 50,341 $ (7,111 ) Gas contracts 62,489 6,070 38,466 (76,269 ) NGL contracts 40,089 8,110 60,316 10,142 Total derivative (gain) loss: $ 163,351 $ 80,929 $ 149,123 $ (73,238 ) ____________________________________________ (1) Natural gas derivative settlements for the three and six months ended June 30, 2015 , include a $15.3 million gain on the early settlement of future contracts as a result of divesting our Mid-Continent assets during the second quarter of 2015. Credit Related Contingent Features As of June 30, 2016 , and through the filing date of this report, all of the Company’s derivative counterparties were members of the Company’s credit facility lender group. The Amended Credit Agreement, as discussed above, changed the required percentage of oil and gas properties subject to a mortgage to at least 90 percent of the total PV-9 of the Company’s proved oil and gas properties evaluated in the most recent reserve report.

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2016
Fair Value Disclosures [Abstract]
Fair Value Disclosures [Text Block]	Note 11 - Fair Value Measurements The Company follows fair value measurement accounting guidance for all assets and liabilities measured at fair value. This guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The fair value hierarchy for grouping these assets and liabilities is based on the significance level of the following inputs: • Level 1 – quoted prices in active markets for identical assets or liabilities • Level 2 – quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable • Level 3 – significant inputs to the valuation model are unobservable The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they are classified within the fair value hierarchy as of June 30, 2016 : Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 258,695 $ — Total property and equipment, net (2) $ — $ — $ 99,944 Liabilities: Derivatives (1) $ — $ 168,152 $ — Net Profits Plan (1) $ — $ — $ 9,476 ____________________________________________ (1) This represents a financial asset or liability that is measured at fair value on a recurring basis. (2) This represents a non-financial asset that is measured at fair value on a nonrecurring basis. The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they were classified within the fair value hierarchy as of December 31, 2015 : Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 488,411 $ — Total property and equipment, net (2) $ — $ — $ 124,813 Liabilities: Derivatives (1) $ — $ 8 $ — Net Profits Plan (1) $ — $ — $ 7,611 ____________________________________________ (1) This represents a financial asset or liability that is measured at fair value on a recurring basis. (2) This represents a non-financial asset that is measured at fair value on a nonrecurring basis. Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The following is a description of the valuation methodologies used by the Company as well as the general classification of such instruments pursuant to the above fair value hierarchy. Derivatives The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivatives. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration forward commodity price curves, counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit-price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity derivative markets are highly active. Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. However, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. The Company monitors the credit ratings of its counterparties and may require counterparties to post collateral if their ratings deteriorate. In some instances, the Company will attempt to novate the trade to a more stable counterparty. 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. All of the Company’s derivative counterparties are members of the Company’s credit facility lender group. 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. Net Profits Plan The Net Profits Plan is a standalone liability for which there is no available market price, principal market, or market participants. The inputs available for this instrument are unobservable and are therefore classified as Level 3 inputs. The Company employs the income valuation technique, which converts expected future cash flow amounts to a single present value amount. This technique uses the estimate of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk to calculate the fair value. There is a direct correlation between realized oil, gas, and NGL commodity prices driving net cash flows and the Net Profits Plan liability. Generally, higher commodity prices result in a larger Net Profits Plan liability and lower commodity prices result in a smaller Net Profits Plan liability. The Company records the estimated fair value of the long-term liability for estimated future payments under the Net Profits Plan based on the discounted value of estimated future payments associated with each individual pool. A discount rate of 10 percent was used to calculate this liability, and is intended to represent the Company’s best estimate of the present value of expected future payments under the Net Profits Plan. The Company’s estimate of its liability is highly dependent on commodity prices, cost assumptions, discount rates, and overall market conditions. The Company regularly assesses the current market environment. The Net Profits Plan liability is determined using price assumptions of five one -year strip prices with the fifth year’s pricing then carried out indefinitely. The average price is adjusted for realized price differentials and to include the effects of the forecasted production covered by derivative contracts in the relevant periods. The non-cash expense associated with this significant management estimate is highly volatile from period to period due to fluctuations that occur in the oil, gas, and NGL commodity markets. If the commodity prices used in the calculation changed by five percent , the liability recorded at June 30, 2016 , would differ by approximately $1.5 million . A one percent increase or decrease in the discount rate would result in a change of approximately $400,000 . Actual cash payments to be made to participants in future periods are dependent on realized actual production, realized commodity prices, and costs associated with the properties in each individual pool of the Net Profits Plan. Consequently, actual cash payments are inherently different from the amounts estimated. No published market quotes exist on which to base the Company’s estimate of fair value of its Net Profits Plan liability. As such, the recorded fair value is based entirely on management estimates that are described within this footnote. While some inputs to the Company’s calculation of fair value of the Net Profits Plan’s future payments are from published sources, others, such as the discount rate and the expected future cash flows, are derived from the Company’s own calculations and estimates. The following table reflects the activity for the Company’s Net Profits Plan liability measured at fair value using Level 3 inputs: For the Six Months Ended June 30, 2016 (in thousands) Beginning balance $ 7,611 Net increase in liability (1) 4,042 Net settlements (1) (2) (2,177 ) Transfers in (out) of Level 3 — Ending balance $ 9,476 ____________________________________________ (1) Net changes in the Company’s Net Profits Plan liability are shown in the Change in Net Profits Plan liability line item of the accompanying statements of operations. (2) Settlements represent cash payments made or accrued under the Net Profits Plan. Long-Term Debt The following table reflects the fair value of the Senior Notes measured using Level 1 inputs based on quoted secondary market trading prices. The Senior Notes were not presented at fair value on the accompanying balance sheets as of June 30, 2016 , or December 31, 2015 , as they were recorded at carrying value, net of unamortized deferred financing costs. Please refer to Note 5 - Long-Term Debt for discussion of the Company’s repurchase of a portion of its Senior Notes during the first quarter of 2016. As of June 30, 2016 As of December 31, 2015 Carrying Amount Fair Value Carrying Amount Fair Value (in thousands) 6.50% Senior Notes due 2021 $ 346,955 $ 328,091 $ 350,000 $ 262,938 6.125% Senior Notes due 2022 561,796 516,852 600,000 440,250 6.50% Senior Notes due 2023 394,985 366,349 400,000 296,000 5.0% Senior Notes due 2024 500,000 426,875 500,000 334,065 5.625% Senior Notes due 2025 500,000 433,125 500,000 326,875 Total Senior Notes $ 2,303,736 $ 2,071,292 $ 2,350,000 $ 1,660,128 The carrying value of the Company’s credit facility approximates its fair value, as the applicable interest rates are floating, based on prevailing market rates. Proved and Unproved Oil and Gas Properties and Other Property and Equipment Total property and equipment, net, measured at fair value within the accompanying balance sheets totaled $99.9 million and $124.8 million as of June 30, 2016 , and December 31, 2015 , respectively. 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 were estimated to be 10 percent to 15 percent based on the reservoir specific weightings of future estimated proved and unproved cash flows as of June 30, 2016 , and December 31, 2015 . The Company believes the discount rates are representative of current market conditions and take into account estimates of future cash payments, reserve categories, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The prices for oil and gas are forecast based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLs are forecast using OPIS Mont Belvieu pricing, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. The Company did not recognize any impairment on proved properties during the three months ended June 30, 2016. For the six months ended June 30, 2016, the Company recorded impairment of proved properties expense of $269.8 million due to the decline in proved and risk-adjusted probable and possible reserve expected cash flows for the Company’s outside-operated Eagle Ford assets, driven by commodity price declines during the first quarter of 2016. The Company recorded impairment of proved oil and gas properties expense of $468.7 million for the year ended December 31, 2015, due to the decline in proved and risk-adjusted probable and possible reserve expected cash flows, driven by commodity price declines. Impairments were recorded mainly in the Company’s east Texas and Powder River Basin programs with smaller impacts on other legacy and non-core assets in the Rocky Mountain region. 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: future development plans, risk weighted potential resource recovery, and estimated reserve values. The Company recorded $38,000 and $2.3 million abandonment and impairment expense on unproved properties for the three and six months ended June 30, 2016, respectively, and $78.6 million for the year ended December 31, 2015. In all periods discussed, the abandonment and impairment expense resulted from lease expirations and acreage the Company no longer intended to develop in light of changes in drilling plans in response to the decline in commodity prices. Other property and equipment costs are evaluated for impairment and reduced to fair value when there is an indication the carrying costs may not be recoverable. Fair value of other property and equipment is valued using an income valuation technique or market approach depending on the quality of information available to support management’s assumptions and the circumstances. The valuation includes consideration of the proved and unproved assets supported by the property and equipment, future cash flows associated with the assets, and fixed costs necessary to operate and maintain the assets. The Company recorded impairment of other property and equipment expense of $49.4 million for the year ended December 31, 2015 , on the Company’s gathering system assets in east Texas. These assets were impaired in conjunction with the impairment of the associated proved and unproved properties, which the Company does not intend to develop during an environment of sustained low commodity prices. Proved properties classified as held for sale, including the corresponding asset retirement obligation liability, are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties, if available. If an estimated selling price is not available, the Company utilizes the income valuation technique discussed above. Unproved properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties. If an estimated selling price is not available, the Company estimates acreage value based on the price received for similar acreage in recent transactions by the Company or other market participants in the principal market. As of June 30, 2016, certain assets held for sale are recorded at fair value totaling $99.9 million less estimated selling costs. Certain of these assets were written down during the first quarter of 2016. A subsequent increase in estimated selling prices, as evidenced by recent bid prices received from third parties, resulted in a $49.5 million gain recorded for the three months ended June 30, 2016. Please refer to Note 3 – Assets Held for Sale and Divestitures. There were no assets held for sale recorded at fair value as of December 31, 2015. The fair value measurements of assets acquired and liabilities assumed are measured on a nonrecurring basis on the acquisition date using an income valuation technique based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the valuation of acquired oil and gas properties include estimates of: (i) reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; (v) future cash flows; and (vi) a market participant-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation.

Basis of Presentation, Signif19

Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards (Policies)	6 Months Ended
	Jun. 30, 2016
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, 2015 (the “ 2015 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 June 30, 2016 , through the filing date of this report. Certain prior period amounts have been reclassified to conform to the current period presentation on the accompanying condensed consolidated financial statements.
New Accounting Pronouncements, Policy [Policy Text Block]	Recently Issued Accounting Standards Effective January 1, 2016, the Company adopted, on a retrospective basis, Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis . This ASU clarifies the consolidation reporting guidance in GAAP. There was no impact to the Company’s financial statements or disclosures from the adoption of this standard. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which changes the accounting for leases. This guidance is to be applied using a modified retrospective method and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2018. Early adoption is permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”) for the recognition of revenue from contracts with customers. Subsequent to the issuance of this ASU, the FASB has issued additional related ASUs as follows: • In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date . This ASU deferred the effective date of ASU 2014-09 by one year. • In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net) . This ASU amends the principal versus agent guidance in ASU No. 2014-09. • In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing . This ASU amends the identification of performance obligations and accounting for licenses in ASU 2014-09. • In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients. This ASU amends certain issues in ASU 2014-09 on transition, collectibility, noncash consideration, and the presentation of sales taxes and other similar taxes. ASU 2014-09 and each update have the same effective date and transition requirements. That is, the guidance under these standards is to be applied using a full retrospective method or a modified retrospective method, as outlined in ASU 2014-09, and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted only for annual periods, and interim periods within those annual periods, beginning after December 15, 2016. The Company is currently evaluating the level of effort needed to implement the standards, evaluating the provisions of each of these standards, and assessing their impact on the Company’s financial statements and disclosures, as well as determining whether to use the full retrospective method or the modified retrospective method. In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting . This ASU makes targeted amendments to the accounting for employee share-based payments. This guidance is to be applied using various transition methods, such as full retrospective, modified retrospective, and prospective, based on the criteria for the specific amendments as outlined in the guidance. The guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2016. Early adoption is permitted, as long as all of the amendments are adopted in the same period. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures. Other than as disclosed above or in the 2015 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 June 30, 2016 , and through the filing date 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. 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. All of the Company’s derivative counterparties are members of the Company’s credit facility lender group. 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.
Net Profits Plan [Policy Text Block]	Net Profits Plan The Net Profits Plan is a standalone liability for which there is no available market price, principal market, or market participants. The inputs available for this instrument are unobservable and are therefore classified as Level 3 inputs. The Company employs the income valuation technique, which converts expected future cash flow amounts to a single present value amount. This technique uses the estimate of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk to calculate the fair value. There is a direct correlation between realized oil, gas, and NGL commodity prices driving net cash flows and the Net Profits Plan liability. Generally, higher commodity prices result in a larger Net Profits Plan liability and lower commodity prices result in a smaller Net Profits Plan liability. The Company records the estimated fair value of the long-term liability for estimated future payments under the Net Profits Plan based on the discounted value of estimated future payments associated with each individual pool. A discount rate of 10 percent was used to calculate this liability, and is intended to represent the Company’s best estimate of the present value of expected future payments under the Net Profits Plan. The Company’s estimate of its liability is highly dependent on commodity prices, cost assumptions, discount rates, and overall market conditions. The Company regularly assesses the current market environment. The Net Profits Plan liability is determined using price assumptions of five one -year strip prices with the fifth year’s pricing then carried out indefinitely. The average price is adjusted for realized price differentials and to include the effects of the forecasted production covered by derivative contracts in the relevant periods. The non-cash expense associated with this significant management estimate is highly volatile from period to period due to fluctuations that occur in the oil, gas, and NGL commodity markets.
Property, Plant and Equipment, Impairment [Policy Text Block]	Proved and Unproved Oil and Gas Properties and Other Property and Equipment Total property and equipment, net, measured at fair value within the accompanying balance sheets totaled $99.9 million and $124.8 million as of June 30, 2016 , and December 31, 2015 , respectively. 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 were estimated to be 10 percent to 15 percent based on the reservoir specific weightings of future estimated proved and unproved cash flows as of June 30, 2016 , and December 31, 2015 . The Company believes the discount rates are representative of current market conditions and take into account estimates of future cash payments, reserve categories, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The prices for oil and gas are forecast based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLs are forecast using OPIS Mont Belvieu pricing, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. The Company did not recognize any impairment on proved properties during the three months ended June 30, 2016. For the six months ended June 30, 2016, the Company recorded impairment of proved properties expense of $269.8 million due to the decline in proved and risk-adjusted probable and possible reserve expected cash flows for the Company’s outside-operated Eagle Ford assets, driven by commodity price declines during the first quarter of 2016. The Company recorded impairment of proved oil and gas properties expense of $468.7 million for the year ended December 31, 2015, due to the decline in proved and risk-adjusted probable and possible reserve expected cash flows, driven by commodity price declines. Impairments were recorded mainly in the Company’s east Texas and Powder River Basin programs with smaller impacts on other legacy and non-core assets in the Rocky Mountain region. 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: future development plans, risk weighted potential resource recovery, and estimated reserve values. The Company recorded $38,000 and $2.3 million abandonment and impairment expense on unproved properties for the three and six months ended June 30, 2016, respectively, and $78.6 million for the year ended December 31, 2015. In all periods discussed, the abandonment and impairment expense resulted from lease expirations and acreage the Company no longer intended to develop in light of changes in drilling plans in response to the decline in commodity prices. Other property and equipment costs are evaluated for impairment and reduced to fair value when there is an indication the carrying costs may not be recoverable. Fair value of other property and equipment is valued using an income valuation technique or market approach depending on the quality of information available to support management’s assumptions and the circumstances. The valuation includes consideration of the proved and unproved assets supported by the property and equipment, future cash flows associated with the assets, and fixed costs necessary to operate and maintain the assets. The Company recorded impairment of other property and equipment expense of $49.4 million for the year ended December 31, 2015 , on the Company’s gathering system assets in east Texas. These assets were impaired in conjunction with the impairment of the associated proved and unproved properties, which the Company does not intend to develop during an environment of sustained low commodity prices. Proved properties classified as held for sale, including the corresponding asset retirement obligation liability, are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties, if available. If an estimated selling price is not available, the Company utilizes the income valuation technique discussed above. Unproved properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties. If an estimated selling price is not available, the Company estimates acreage value based on the price received for similar acreage in recent transactions by the Company or other market participants in the principal market. As of June 30, 2016, certain assets held for sale are recorded at fair value totaling $99.9 million less estimated selling costs. Certain of these assets were written down during the first quarter of 2016. A subsequent increase in estimated selling prices, as evidenced by recent bid prices received from third parties, resulted in a $49.5 million gain recorded for the three months ended June 30, 2016. Please refer to Note 3 – Assets Held for Sale and Divestitures. There were no assets held for sale recorded at fair value as of December 31, 2015. The fair value measurements of assets acquired and liabilities assumed are measured on a nonrecurring basis on the acquisition date using an income valuation technique based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the valuation of acquired oil and gas properties include estimates of: (i) reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; (v) future cash flows; and (vi) a market participant-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation.

Income Taxes (Tables)

Income Taxes (Tables)	6 Months Ended
	Jun. 30, 2016
Income Tax Disclosure [Abstract]
Schedule of provision for income taxes	The provision for income taxes consists of the following: For the Three Months Ended June 30, For the Six Months Ended June 30, 2016 2015 2016 2015 (in thousands) Current portion of income tax expense (benefit): Federal $ — $ — $ — $ — State 77 10,126 241 10,400 Deferred portion of income tax benefit (95,975 ) (50,829 ) (291,014 ) (84,556 ) Total income tax benefit $ (95,898 ) $ (40,703 ) $ (290,773 ) $ (74,156 ) Effective tax rate 36.2 % 41.4 % 36.0 % 40.1 %

Long-Term Debt (Tables)

Long-Term Debt (Tables)	6 Months Ended
	Jun. 30, 2016
Debt Disclosure [Abstract]
Schedule of Borrowing Base Utilization, Credit Facility [Table Text Block]	Effective as of April 8, 2016 , the revised borrowing base utilization grid under the Amended Credit Agreement is as follows: Borrowing Base Utilization Grid Borrowing Base Utilization Percentage <25% ≥25% <50% ≥50% <75% ≥75% <90% ≥90% Eurodollar Loans 1.750 % 2.000 % 2.250 % 2.500 % 2.750 % ABR Loans or Swingline Loans 0.750 % 1.000 % 1.250 % 1.500 % 1.750 % Commitment Fee Rate 0.300 % 0.300 % 0.350 % 0.375 % 0.375 %
Schedule of Line of Credit Facilities [Table Text Block]	The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Amended Credit Agreement as of July 27, 2016 , and June 30, 2016 , and under the Credit Agreement as of December 31, 2015 : As of July 27, 2016 As of June 30, 2016 As of December 31, 2015 (in thousands) Credit facility balance (1) $ 330,000 $ 330,500 $ 202,000 Letters of credit (2) $ 200 $ 200 $ 200 Available borrowing capacity $ 919,800 $ 919,300 $ 1,297,800 ____________________________________________ (1) Deferred financing costs attributable to the credit facility are presented as a component of other noncurrent assets on the accompanying balance sheets and thus are not deducted from the credit facility balance. (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 June 30, 2016 , and December 31, 2015 , consisted of the following: As of June 30, 2016 As of December 31, 2015 Senior Notes Unamortized Deferred Financing Costs Senior Notes, Net of Unamortized Deferred Financing Costs Senior Notes Unamortized Deferred Financing Costs Senior Notes, Net of Unamortized Deferred Financing Costs (in thousands) 6.50% Senior Notes due 2021 $ 346,955 $ 3,721 $ 343,234 $ 350,000 $ 4,106 $ 345,894 6.125% Senior Notes due 2022 561,796 7,569 554,227 600,000 8,714 591,286 6.50% Senior Notes due 2023 394,985 4,801 390,184 400,000 5,231 394,769 5.0% Senior Notes due 2024 500,000 6,994 493,006 500,000 7,455 492,545 5.625% Senior Notes due 2025 500,000 8,071 491,929 500,000 8,524 491,476 Total $ 2,303,736 $ 31,156 $ 2,272,580 $ 2,350,000 $ 34,030 $ 2,315,970

Pension Benefits (Tables)

Pension Benefits (Tables)	6 Months Ended
	Jun. 30, 2016
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 June 30, For the Six Months Ended June 30, 2016 2015 2016 2015 (in thousands) Service cost $ 2,113 $ 2,390 $ 4,100 $ 3,974 Interest cost 830 700 1,454 1,248 Expected return on plan assets that reduces periodic pension cost (573 ) (597 ) (1,118 ) (1,091 ) Amortization of prior service cost 5 5 9 9 Amortization of net actuarial loss 419 571 791 743 Net periodic benefit cost $ 2,794 $ 3,069 $ 5,236 $ 4,883

Earnings per Share (Tables)

Earnings per Share (Tables)	6 Months Ended
	Jun. 30, 2016
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 anti-dilutive securities related to RSUs and PSUs for the periods presented: For the Three Months Ended June 30, For the Six Months Ended June 30, 2016 2015 2016 2015 (in thousands) Anti-dilutive 155 590 70 490
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 June 30, For the Six Months Ended June 30, 2016 2015 2016 2015 (in thousands, except per share amounts) Net loss $ (168,681 ) $ (57,508 ) $ (515,891 ) $ (110,566 ) Basic weighted-average common shares outstanding 68,102 67,483 68,090 67,473 Add: dilutive effect of unvested RSUs and contingent PSUs — — — — Diluted weighted-average common shares outstanding 68,102 67,483 68,090 67,473 Basic net loss per common share $ (2.48 ) $ (0.85 ) $ (7.58 ) $ (1.64 ) Diluted net loss per common share $ (2.48 ) $ (0.85 ) $ (7.58 ) $ (1.64 )

Derivative Financial Instrume24

Derivative Financial Instruments (Tables)	6 Months Ended
	Jun. 30, 2016
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block]	The following tables summarize the approximate volumes and average contract prices of contracts the Company had in place as of June 30, 2016 : Oil Swaps Contract Period NYMEX WTI Volumes Weighted-Average Contract Price (MBbls) (per Bbl) Third quarter 2016 1,840 $ 71.80 Fourth quarter 2016 1,399 $ 67.73 2017 3,053 $ 45.61 All oil swaps 6,292 Oil Collars Contract Period NYMEX WTI Volumes Weighted- Average Floor Price Weighted- Average Ceiling Price (MBbls) (per Bbl) (per Bbl) Third quarter 2016 672 $ 40.00 $ 51.57 Fourth quarter 2016 881 $ 40.00 $ 51.52 2017 1,018 $ 45.00 $ 51.02 All oil collars 2,571 Natural Gas Swaps Contract Period Sold Volumes Weighted-Average Contract Price Purchased Volumes Weighted- Average Contract Price Net Volumes (BBtu) (per MMBtu) (BBtu) (per MMBtu) (BBtu) Third quarter 2016 25,724 $ 3.13 — $ — 25,724 Fourth quarter 2016 26,700 $ 3.34 — $ — 26,700 2017 88,894 $ 4.04 — $ — 88,894 2018 53,048 $ 3.75 (30,606 ) $ 4.27 22,442 2019 24,415 $ 4.34 (24,415 ) $ 4.34 — All gas swaps* 218,781 (55,021 ) 163,760 *Total net volumes of natural gas swaps are comprised of IF El Paso Permian ( 2% ), IF HSC ( 97% ), and IF NNG Ventura ( 1% ). NGL Swaps OPIS Purity Ethane Mont Belvieu OPIS Propane Mont Belvieu Non-TET OPIS Normal Butane Mont Belvieu Non-TET OPS Isobutane Mont Belvieu Non-TET Contract Period Volumes Weighted-Average Contract Price Volumes Weighted-Average Volumes Weighted-Average Volumes Weighted-Average (MBbls) (per Bbl) (MBbls) (per Bbl) (MBbls) (per Bbl) (MBbls) (per Bbl) Third quarter 2016 751 $ 8.70 863 $ 19.03 248 $ 22.90 200 $ 23.24 Fourth quarter 2016 687 $ 8.71 792 $ 18.53 226 $ 22.91 182 $ 23.25 2017 3,062 $ 8.92 721 $ 20.01 — $ — — $ — 2018 2,435 $ 10.18 — $ — — $ — — $ — 2019 1,200 $ 10.92 — $ — — $ — — $ — 2020 539 $ 11.13 — $ — — $ — — $ — Total NGL swaps 8,674 2,376 474 382
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 June 30, 2016 Derivative Assets Derivative Liabilities Balance Sheet Classification Fair Value Balance Sheet Classification Fair Value (in thousands) Commodity contracts Current assets $ 145,576 Current liabilities $ 63,492 Commodity contracts Noncurrent assets 113,119 Noncurrent liabilities 104,660 Derivatives not designated as hedging instruments $ 258,695 $ 168,152 As of December 31, 2015 Derivative Assets Derivative Liabilities Balance Sheet Classification Fair Value Balance Sheet Classification Fair Value (in thousands) Commodity contracts Current assets $ 367,710 Current liabilities $ 8 Commodity contracts Noncurrent assets 120,701 Noncurrent liabilities — Derivatives not designated as hedging instruments $ 488,411 $ 8
Schedule of the potential effects of master netting arrangements [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 June 30, 2016 December 31, 2015 June 30, 2016 December 31, 2015 (in thousands) Gross amounts presented in the accompanying balance sheets $ 258,695 $ 488,411 $ (168,152 ) $ (8 ) Amounts not offset in the accompanying balance sheets (158,955 ) (8 ) 158,955 8 Net amounts $ 99,740 $ 488,403 $ (9,197 ) $ —
Schedule of derivative (gain) loss	The following table summarizes the components of the derivative (gain) loss presented in the accompanying statements of operations: For the Three Months Ended June 30, For the Six Months Ended June 30, 2016 2015 2016 2015 (in thousands) Derivative settlement (gain) loss: Oil contracts $ (72,164 ) $ (73,915 ) $ (172,156 ) $ (180,129 ) Gas contracts (1) (31,439 ) (38,880 ) (72,492 ) (73,112 ) NGL contracts 1,893 — (4,090 ) (20,783 ) Total derivative settlement (gain) loss $ (101,710 ) $ (112,795 ) $ (248,738 ) $ (274,024 ) Total derivative (gain) loss: Oil contracts $ 60,773 $ 66,749 $ 50,341 $ (7,111 ) Gas contracts 62,489 6,070 38,466 (76,269 ) NGL contracts 40,089 8,110 60,316 10,142 Total derivative (gain) loss: $ 163,351 $ 80,929 $ 149,123 $ (73,238 )

Fair Value Measurements Fair Va

Fair Value Measurements Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurements, Recurring and Nonrecurring [Table Text Block]	The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they are classified within the fair value hierarchy as of June 30, 2016 : Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 258,695 $ — Total property and equipment, net (2) $ — $ — $ 99,944 Liabilities: Derivatives (1) $ — $ 168,152 $ — Net Profits Plan (1) $ — $ — $ 9,476 ____________________________________________ (1) This represents a financial asset or liability that is measured at fair value on a recurring basis. (2) This represents a non-financial asset that is measured at fair value on a nonrecurring basis. The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they were classified within the fair value hierarchy as of December 31, 2015 : Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 488,411 $ — Total property and equipment, net (2) $ — $ — $ 124,813 Liabilities: Derivatives (1) $ — $ 8 $ — Net Profits Plan (1) $ — $ — $ 7,611 ____________________________________________ (1) This represents a financial asset or liability that is measured at fair value on a recurring basis. (2) This represents a non-financial asset that is measured at fair value on a nonrecurring basis.
Net Profit Plan Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]	The following table reflects the activity for the Company’s Net Profits Plan liability measured at fair value using Level 3 inputs: For the Six Months Ended June 30, 2016 (in thousands) Beginning balance $ 7,611 Net increase in liability (1) 4,042 Net settlements (1) (2) (2,177 ) Transfers in (out) of Level 3 — Ending balance $ 9,476 ____________________________________________ (1) Net changes in the Company’s Net Profits Plan liability are shown in the Change in Net Profits Plan liability line item of the accompanying statements of operations. (2) Settlements represent cash payments made or accrued under the Net Profits Plan.
Long Term Debt Fair Value [Table Text Block]	The following table reflects the fair value of the Senior Notes measured using Level 1 inputs based on quoted secondary market trading prices. The Senior Notes were not presented at fair value on the accompanying balance sheets as of June 30, 2016 , or December 31, 2015 , as they were recorded at carrying value, net of unamortized deferred financing costs. Please refer to Note 5 - Long-Term Debt for discussion of the Company’s repurchase of a portion of its Senior Notes during the first quarter of 2016. As of June 30, 2016 As of December 31, 2015 Carrying Amount Fair Value Carrying Amount Fair Value (in thousands) 6.50% Senior Notes due 2021 $ 346,955 $ 328,091 $ 350,000 $ 262,938 6.125% Senior Notes due 2022 561,796 516,852 600,000 440,250 6.50% Senior Notes due 2023 394,985 366,349 400,000 296,000 5.0% Senior Notes due 2024 500,000 426,875 500,000 334,065 5.625% Senior Notes due 2025 500,000 433,125 500,000 326,875 Total Senior Notes $ 2,303,736 $ 2,071,292 $ 2,350,000 $ 1,660,128

Assets Held for Sale and Dive26

Assets Held for Sale and Divestitures Assets Held for Sale and Divestitures (Details) - USD ($) $ in Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Jun. 30, 2015	Mar. 31, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Not Discontinued Operation, Loss (Gain) on Write-down	$ (49,500)	$ 68,300		$ 30,000
Proceeds from Sale of Oil and Gas Property and Equipment					$ 12,967	$ 334,988
Asset retirement obligation associated with oil and gas properties held for sale	32,055				32,055		$ 241
Disposal Group, Including Discontinued Operation, Assets, Current	$ 173,001				$ 173,001		$ 641
Assets Held-for-sale Reasonably Certain Period for Sale					1 year
Mid Continent Divestiture 2015 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal						107,800
Disposal Group, Not Discontinued Operation, Loss (Gain) on Write-down			$ 66,000
Proceeds from Sale of Oil and Gas Property and Equipment						316,500
Business Exit Costs			$ 5,000			$ 8,500

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Components of the provision for income taxes
Federal	$ 0	$ 0	$ 0	$ 0
State	77	10,126	241	10,400
Deferred portion of income tax expense (benefit)	(95,975)	(50,829)	(291,014)	(84,556)
Total income tax expense (benefit)	$ (95,898)	$ (40,703)	$ (290,773)	$ (74,156)
Effective tax rate	36.20%	41.40%	36.00%	40.10%

Income Taxes Narrative (Details

Income Taxes Narrative (Details) $ in Millions	3 Months Ended
	Mar. 31, 2016USD ($)
Income Tax Narrative [Abstract]
Proceeds from Income Tax Refunds	$ 4.9

Long-Term Debt Revolving Credit

Long-Term Debt Revolving Credit Facility (Details) $ in Thousands		3 Months Ended
		Jun. 30, 2016USD ($)	Jul. 27, 2016USD ($)	Dec. 31, 2015USD ($)
Line of Credit Facility [Line Items]
Long-term Line of Credit, Noncurrent		$ 330,500		$ 202,000
Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt Issuance Costs, Gross		3,100
Line of Credit Facility, Maximum Borrowing Capacity		2,500,000
Borrowing Base, Line of Credit		1,250,000
Line of Credit Facility, Current Borrowing Capacity		$ 1,250,000
Percentage of Proved Property Secured for Credit Facility Borrowing		90.00%
Long-term Line of Credit, Noncurrent	[1]	$ 330,500		202,000
Letters of Credit Outstanding, Amount	[2]	200		200
Line of Credit Facility, Remaining Borrowing Capacity		$ 919,300		$ 1,297,800
Borrowing Base Utilization Of 25 Percent Or Less [Member] | Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage		0.30%
Borrowing Base Utilization Of 25 Percent Or Less [Member] | Eurodollar [Member] | Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.75%
Borrowing Base Utilization Of 25 Percent Or Less [Member] | Prime Rate [Member] | Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		0.75%
Borrowing Base Utilization Of More Than 25 Percent But Less Than 50 Percent [Member] | Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage		0.30%
Borrowing Base Utilization Of More Than 25 Percent But Less Than 50 Percent [Member] | Eurodollar [Member] | Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		2.00%
Borrowing Base Utilization Of More Than 25 Percent But Less Than 50 Percent [Member] | Prime Rate [Member] | Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.00%
Borrowing Base Utilization Of More Than 50 Percent But Less Than 75 Percent [Member] | Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage		0.35%
Borrowing Base Utilization Of More Than 50 Percent But Less Than 75 Percent [Member] | Eurodollar [Member] | Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		2.25%
Borrowing Base Utilization Of More Than 50 Percent But Less Than 75 Percent [Member] | Prime Rate [Member] | Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.25%
Borrowing Base Utilization Of More Than 75 Percent But Less Than 90 Percent [Member] | Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage		0.375%
Borrowing Base Utilization Of More Than 75 Percent But Less Than 90 Percent [Member] | Eurodollar [Member] | Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		2.50%
Borrowing Base Utilization Of More Than 75 Percent But Less Than 90 Percent [Member] | Prime Rate [Member] | Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.50%
Borrowing Base Utilization Of More Than 90 Percent [Member] | Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage		0.375%
Borrowing Base Utilization Of More Than 90 Percent [Member] | Eurodollar [Member] | Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		2.75%
Borrowing Base Utilization Of More Than 90 Percent [Member] | Prime Rate [Member] | Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.75%
Maximum [Member] | Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Covenant Compliance, Senior Secured Debt To Adjusted EBITDAX Ratio		2.75
Minimum [Member] | Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Covenant Compliance, Adjusted Current Ratio		1
Debt Instrument, Covenant Compliance, Adjusted EBITDAX To Interest Expense		2
Subsequent Event [Member] | Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Long-term Line of Credit	[1]		$ 330,000
Letters of Credit Outstanding, Amount	[2]		200
Line of Credit Facility, Remaining Borrowing Capacity			$ 919,800
[1]	Deferred financing costs attributable to the credit facility are presented as a component of other noncurrent assets on the accompanying balance sheets and thus are not deducted from the credit facility balance.
[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			6 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 2,303,736,000			$ 2,303,736,000		$ 2,350,000,000
Unamortized Debt Issuance Expense	31,156,000			31,156,000		34,030,000
Senior Notes, Noncurrent	2,272,580,000			2,272,580,000		2,315,970,000
Gain (Loss) on Extinguishment of Debt	0		$ (16,578,000)	15,722,000	$ (16,578,000)
6.50% Senior Notes Due 2021 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	346,955,000			346,955,000		350,000,000
Unamortized Debt Issuance Expense	3,721,000			3,721,000		4,106,000
Senior Notes, Noncurrent	343,234,000			343,234,000		345,894,000
6.125% Senior Notes Due 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	561,796,000			561,796,000		600,000,000
Unamortized Debt Issuance Expense	7,569,000			7,569,000		8,714,000
Senior Notes, Noncurrent	554,227,000			554,227,000		591,286,000
6.50% Senior Notes Due 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	394,985,000			394,985,000		400,000,000
Unamortized Debt Issuance Expense	4,801,000			4,801,000		5,231,000
Senior Notes, Noncurrent	390,184,000			390,184,000		394,769,000
5% Senior Notes Due 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	500,000,000			500,000,000		500,000,000
Unamortized Debt Issuance Expense	6,994,000			6,994,000		7,455,000
Senior Notes, Noncurrent	493,006,000			493,006,000		492,545,000
5.625% Senior Notes Due 2025 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	500,000,000			500,000,000		500,000,000
Unamortized Debt Issuance Expense	8,071,000			8,071,000		8,524,000
Senior Notes, Noncurrent	491,929,000			491,929,000		$ 491,476,000
Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Covenant Compliance, Dividends Excluded From Computation				6,500,000
Debt Instrument, Repurchased Face Amount		$ 46,300,000
Debt Instrument, Repurchased Settlement Amount		$ 29,900,000
Early Repayment of Senior Debt, Accrued	$ 10,000,000			10,000,000
Gain (Loss) on Extinguishment of Debt				15,722,000
Debt Instrument, Repurchase Discount				16,400,000
Amortization of Debt Issuance Costs Related to Repurchase of Debt Instrument				$ 700,000
Senior Notes [Member] | 6.50% Senior Notes Due 2021 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.50%			6.50%
Senior Notes [Member] | 6.125% Senior Notes Due 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.125%			6.125%
Senior Notes [Member] | 6.50% Senior Notes Due 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.50%			6.50%
Senior Notes [Member] | 5% Senior Notes Due 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.00%			5.00%
Senior Notes [Member] | 5.625% Senior Notes Due 2025 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.625%			5.625%

Commitments and Contingencies C

Commitments and Contingencies Commitments and Contingencies (Details) MMcf in Thousands, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016USD ($)MMcfMMBbls	Jun. 30, 2015USD ($)	Jun. 30, 2016USD ($)MMcfMMBbls	Jun. 30, 2015USD ($)	Dec. 31, 2015USD ($)MMcf
Water Disposal Agreement [Member]
Other Commitments [Line Items]
Water Delivery Commitments and Contracts, Remaining Contractual Volume | MMBbls	25,400,000		25,400,000
Contractual Obligation	$ 23		$ 23
Drilling Rig Leasing Contracts [Member]
Other Commitments [Line Items]
Gain (Loss) on Contract Termination	(2.6)	$ (2.7)	(7.6)	$ (5.9)
Gas gathering and Oil and Gas Through-put Commitments [Member]
Other Commitments [Line Items]
Contractual Obligation, Amended Gathering Agreements Related to Non-Operated Eagle Ford Assets	342		342
Contractual Payments Receivable, Amended Gathering Agreements Related to Non-Operated Eagle Ford Assets	241.4		241.4
Decrease in Contractual Obligation					$ 118.2
Contractual Obligation	$ 1,000		$ 1,000
Crude Oil Transportation Commitment [Member]
Other Commitments [Line Items]
Oil and Gas Delivery Commitments and Contracts, Remaining Contractual Volume on Amended Gathering Agreements Related to Non-Operated Eagle Ford Assets | MMBbls	39		39
Oil and Gas Delivery Commitments and Contracts, Remaining Contractual Volume | MMBbls	72		72
Natural Gas Transportation Commitment [Member]
Other Commitments [Line Items]
Oil and Gas Delivery Commitments and Contracts, Remaining Contractual Volume on Amended Gathering Agreements Related to Non-Operated Eagle Ford Assets | MMcf	296		296
Oil and Gas Delivery Commitments and Contracts, Decrease in Remaining Contractual Volume | MMcf					829
Oil and Gas Delivery Commitments and Contracts, Remaining Contractual Volume | MMcf	1,590		1,590
Natural Gas Liquids Transportation Commitment [Member]
Other Commitments [Line Items]
Oil and Gas Delivery Commitments and Contracts, Remaining Contractual Volume | MMBbls	14		14

Commitments and Contingencies L

Commitments and Contingencies Loss Contingency (Details) $ in Millions	Jun. 30, 2016USD ($)
Royalty Dispute [Domain]
Loss Contingencies [Line Items]
Loss Contingency Accrual	$ 4.4

Compensation Plans (Details)

Compensation Plans (Details)	1 Months Ended	3 Months Ended		6 Months Ended
	Jul. 27, 2016USD ($)shares	Jun. 30, 2016USD ($)shares	Jun. 30, 2015USD ($)shares	Jun. 30, 2016USD ($)shares	Jun. 30, 2015USD ($)shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense | $				$ 13,915,000	$ 13,215,000
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant		6,200,000		6,200,000
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 | $		$ 3,000,000	$ 2,700,000	$ 5,900,000	5,000,000
Unrecognized stock based compensation expense | $		12,300,000		12,300,000
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense | $		3,300,000	$ 2,900,000	6,500,000	5,800,000
Unrecognized stock based compensation expense | $		$ 12,000,000		$ 12,000,000
Number of Shares Represented by Each RSU				1
Shares Issued to Board of Directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense | $				$ 517,000	$ 1,200,000
Stock Issued During Period, Shares, Share-based Compensation, Gross				53,473	37,950
Minimum [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Multiplier Applied to PSU Awards at Settlement				0
Maximum [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Multiplier Applied to PSU Awards at Settlement				2
Subsequent Event [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Multiplier Applied to PSU Awards at Settlement	0
Share-based Compensation Arrangement by Share-based Payment Award, Shares Issued in Period	30,061
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	447,971
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Granted in Period, Total Fair Value | $	$ 11,900,000
Shares Paid for Tax Withholding for Share Based Compensation	14,809
Subsequent Event [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	417,065
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Granted in Period, Total Fair Value | $	$ 11,700,000
Restricted Stock, Shares Settled Gross of Shares for Tax Withholdings	232,258
Restricted Stock, Shares Issued Net of Shares for Tax Withholdings	162,211
Shares Paid for Tax Withholding for Share Based Compensation	70,047
Employee Stock Purchase Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Issued During Period, Shares, Share-based Compensation, Gross		140,853	96,285
Share-based Compensation Arrangement by Share-based Payment Award, Maximum Employee Subscription Rate		15.00%		15.00%
Share-based Compensation Arrangement by Share-based Payment Award, Maximum Employee Purchase Amount | $		$ 25,000		$ 25,000
Share-based Compensation Arrangement by Share-based Payment Award, Percent of Offering Date Price Paid		85.00%		85.00%
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant		808,854		808,854

Pension Benefits (Details)

Pension Benefits (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Components of Net Periodic Benefit Costs for Both Pension Plans
Service cost	$ 2,113	$ 2,390	$ 4,100	$ 3,974
Interest cost	830	700	1,454	1,248
Expected return on plan assets that reduces periodic pension costs	(573)	(597)	(1,118)	(1,091)
Amortization of prior service costs	5	5	9	9
Amortization of net actuarial loss	419	571	791	743
Net periodic benefit cost	$ 2,794	$ 3,069	$ 5,236	$ 4,883

Pension Benefits Pension Narrat

Pension Benefits Pension Narrative (Details) $ in Millions	6 Months Ended
	Jun. 30, 2016USD ($)
Pension Narrative [Abstract]
Pension And Other Post-retirement Benefit Plans, Gain (Loss) Amortization Threshold	10.00%
Pension and Other Postretirement Benefit Contributions	$ 6

Earnings per Share (Details)

Earnings per Share (Details) $ / shares in Units, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016USD ($)$ / sharesshares	Jun. 30, 2015USD ($)$ / sharesshares	Jun. 30, 2016USD ($)$ / sharesshares	Jun. 30, 2015USD ($)$ / sharesshares
Earnings per share
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	155,000	590,000	70,000	490,000
Calculation of basic and diluted earnings per share
Net loss | $	$ (168,681)	$ (57,508)	$ (515,891)	$ (110,566)
Basic weighted-average common shares outstanding	68,102,000	67,483,000	68,090,000	67,473,000
Add: dilutive effect of stock options, unvested RSU's, and contingent PSU's	0	0	0	0
Diluted weighted-average common shares outstanding	68,102,000	67,483,000	68,090,000	67,473,000
Basic net loss per common share | $ / shares	$ (2.48)	$ (0.85)	$ (7.58)	$ (1.64)
Diluted net loss per common share | $ / shares	$ (2.48)	$ (0.85)	$ (7.58)	$ (1.64)
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

Derivative Financial Instrume37

Derivative Financial Instruments (Details)	Jun. 30, 2016MMBTU$ / EnergyContent$ / Barrelsbbl	Jul. 27, 2016MMBTU$ / EnergyContent$ / Barrelsbbl	Mar. 31, 2016MMBTU$ / EnergyContent
NYMEX Oil Swap Contract Third Quarter 2016 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	1,840,000
Derivative, Swap Type, Average Fixed Price | $ / Barrels	71.80
NYMEX Oil Swap Contract Fourth Quarter 2016 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	1,399,000
Derivative, Swap Type, Average Fixed Price | $ / Barrels	67.73
NYMEX Oil Swap Contract 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	3,053,000
Derivative, Swap Type, Average Fixed Price | $ / Barrels	45.61
NYMEX Oil Swap Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	6,292,000
NYMEX Oil Collar Contract Third Quarter 2016 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	672,000
Derivative, Floor Price | $ / Barrels	40
Derivative, Cap Price | $ / Barrels	51.57
NYMEX Oil Collar Contract Fourth Quarter 2016 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	881,000
Derivative, Floor Price | $ / Barrels	40
Derivative, Cap Price | $ / Barrels	51.52
NYMEX Oil Collar Contract 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	1,018,000
Derivative, Floor Price | $ / Barrels	45
Derivative, Cap Price | $ / Barrels	51.02
NYMEX Oil Collar Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	2,571,000
Gas Swaps Contract Third Quarter 2016 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | MMBTU	0
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	25,724,000
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent	3.13
Derivative, Swap Type, Average Fixed Price, Purchased Volumes | $ / EnergyContent	0
Derivative, Nonmonetary Notional Amount, Energy Measure, Net of Purchased Volumes | MMBTU	25,724,000
Gas Swaps Contract Fourth Quarter 2016 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | MMBTU	0
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	26,700,000
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent	3.34
Derivative, Swap Type, Average Fixed Price, Purchased Volumes | $ / EnergyContent	0
Derivative, Nonmonetary Notional Amount, Energy Measure, Net of Purchased Volumes | MMBTU	26,700,000
Gas Swaps Contract 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | MMBTU	0
Derivative, Nonmonetary Notional Amount, Energy Measure, Sold Volumes | MMBTU			38,600,000
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	88,894,000
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent	4.04		4.43
Derivative, Swap Type, Average Fixed Price, Purchased Volumes | $ / EnergyContent	0
Derivative, Nonmonetary Notional Amount, Energy Measure, Net of Purchased Volumes | MMBTU	88,894,000
Gas Swaps Contract 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | MMBTU	(30,606,000)
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	53,048,000
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent	3.75
Derivative, Swap Type, Average Fixed Price, Purchased Volumes | $ / EnergyContent	4.27
Derivative, Nonmonetary Notional Amount, Energy Measure, Net of Purchased Volumes | MMBTU	22,442,000
Gas Swaps Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | MMBTU	(24,415,000)
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	24,415,000
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent	4.34
Derivative, Swap Type, Average Fixed Price, Purchased Volumes | $ / EnergyContent	4.34
Derivative, Nonmonetary Notional Amount, Energy Measure, Net of Purchased Volumes | MMBTU	0
Gas Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | MMBTU	(55,021,000)		(55,021,000)
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	218,781,000
Derivative, Nonmonetary Notional Amount, Energy Measure, Net of Purchased Volumes | MMBTU	163,760,000
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	97.00%
IF NNG Ventura [Member]
Derivative Financial Instruments
Index percent of natural gas fixed swaps	1.00%
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract Third Quarter 2016 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	751,000
Derivative, Swap Type, Average Fixed Price | $ / Barrels	8.70
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract Fourth Quarter 2016 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	687,000
Derivative, Swap Type, Average Fixed Price | $ / Barrels	8.71
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	3,062,000
Derivative, Swap Type, Average Fixed Price | $ / Barrels	8.92
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	2,435,000
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	1,200,000
Derivative, Swap Type, Average Fixed Price | $ / Barrels	10.92
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	539,000
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	8,674,000
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter 2016 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	863,000
Derivative, Swap Type, Average Fixed Price | $ / Barrels	19.03
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2016 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	792,000
Derivative, Swap Type, Average Fixed Price | $ / Barrels	18.53
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2017 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	721,000
Derivative, Swap Type, Average Fixed Price | $ / Barrels	20.01
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2018 [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 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	2,376,000
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter 2016 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	248,000
Derivative, Swap Type, Average Fixed Price | $ / Barrels	22.90
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2016 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	226,000
Derivative, Swap Type, Average Fixed Price | $ / Barrels	22.91
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2017 [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 2018 [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 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	474,000
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter 2016 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	200,000
Derivative, Swap Type, Average Fixed Price | $ / Barrels	23.24
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2016 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume	182,000
Derivative, Swap Type, Average Fixed Price | $ / Barrels	23.25
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2017 [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 2018 [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 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	382,000
Subsequent Event [Member] | NYMEX Oil Collar Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		1,400,000
Derivative, Floor Price | $ / Barrels		45
Derivative, Cap Price | $ / Barrels		56.25
Subsequent Event [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		1,400,000
Subsequent Event [Member] | Gas Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU		15,600,000
Minimum [Member] | Subsequent Event [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent		21.32
Minimum [Member] | Subsequent Event [Member] | Gas Contracts [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent		2.90
Maximum [Member] | Subsequent Event [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent		21.79
Maximum [Member] | Subsequent Event [Member] | Gas Contracts [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent		3.24

Derivative Financial Instrume38

Derivative Financial Instruments Fair Value (Details) - USD ($) $ in Thousands	Jun. 30, 2016		Dec. 31, 2015
Fair value of derivative assets and liabilities
Derivative, Fair Value, Net	$ 90,500		$ 488,400
Derivative asset current	145,576		367,710
Derivative asset noncurrent	113,119		120,701
Derivative Asset, Fair Value, Gross Asset	258,695		488,411
Derivative liability	63,492		8
Derivatives liability noncurrent	104,660		0
Derivative Liability, Fair Value, Gross Liability	168,152		8
Derivatives not designated as hedging instruments
Fair value of derivative assets and liabilities
Derivative asset current	145,576		367,710
Derivative asset noncurrent	113,119		120,701
Derivative liability	63,492		8
Derivatives liability noncurrent	104,660		0
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	258,695	[1]	488,411	[2]
Derivative Liability, Fair Value, Gross Liability	$ 168,152	[1]	$ 8	[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 Instrume39

Derivative Financial Instruments Gains and Losses (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Gain and loss from derivative cash settlements and changes in fair value of derivative contracts
Derivative settlement gain (loss)		$ (101,710)	$ (112,795)	$ (248,738)	$ (274,024)
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net		163,351	80,929	149,123	(73,238)
NYMEX Oil Contracts [Member]
Gain and loss from derivative cash settlements and changes in fair value of derivative contracts
Derivative settlement gain (loss)		(72,164)	(73,915)	(172,156)	(180,129)
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net		60,773	66,749	50,341	(7,111)
Gas Contracts [Member]
Gain and loss from derivative cash settlements and changes in fair value of derivative contracts
Gain on Early Settlement of Derivatives			(15,300)
Derivative settlement gain (loss)	[1]	(31,439)	(38,880)	(72,492)	(73,112)
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net		62,489	6,070	38,466	(76,269)
NGL Contracts [Member]
Gain and loss from derivative cash settlements and changes in fair value of derivative contracts
Derivative settlement gain (loss)		1,893	0	(4,090)	(20,783)
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net		$ 40,089	$ 8,110	$ 60,316	$ 10,142
[1]	Natural gas derivative settlements for the three and six months ended June 30, 2015, include a $15.3 million gain on the early settlement of future contracts as a result of divesting our Mid-Continent assets during the second quarter of 2015.

Derivative Financial Instrume40

Derivative Financial Instruments Offsetting of Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Offsetting of Derivative Assets and Liabilities [Abstract]
Derivative Asset, Fair Value, Gross Asset	$ 258,695	$ 488,411
Derivative Liability, Fair Value, Gross Liability	(168,152)	(8)
Derivative Asset, Not Offset, Policy Election Deduction	158,955	8
Derivative Liability, Not Offset, Policy Election Deduction	158,955	8
Derivative Asset, Fair Value, Offset Against Collateral, Net of Not Subject to Master Netting Arrangement, Policy Election	99,740	488,403
Derivative Liability, Fair Value, Offset Against Collateral, Net of Not Subject to Master Netting Arrangement, Policy Election	$ (9,197)	$ 0

Fair Value Measurements Fair 41

Fair Value Measurements Fair Value (Details) - USD ($) $ in Thousands	Jun. 30, 2016		Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 258,695		$ 488,411
Property, Plant and Equipment, Net	4,601,332		4,950,280
Derivative Liability, Fair Value, Gross Liability	168,152		8
Net Profits Plan Liability Noncurrent	9,476		7,611
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net Profits Plan Liability Noncurrent	0	[1]	0	[2]
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net Profits Plan Liability Noncurrent	0	[1]	0	[2]
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net Profits Plan Liability Noncurrent	9,476	[1]	7,611	[2]
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	[3]	0	[4]
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	[3]	0	[4]
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	99,900	[3]	124,800	[4]
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	[1]	0	[2]
Derivative Liability, Fair Value, Gross Liability	0	[1]	0	[2]
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	258,695	[1]	488,411	[2]
Derivative Liability, Fair Value, Gross Liability	168,152	[1]	8	[2]
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	[1]	0	[2]
Derivative Liability, Fair Value, Gross Liability	$ 0	[1]	$ 0	[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.
[3]	This represents a non-financial asset that is measured at fair value on a nonrecurring basis.
[4]	This represents a non-financial asset that is measured at fair value on a nonrecurring basis.

Fair Value Measurements Net Pro

Fair Value Measurements Net Profits Plan (Details) - USD ($)		6 Months Ended	12 Months Ended
		Jun. 30, 2016	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Period of New York Mercantile Exchange Strip Pricing Used for Price Forecast		5 years
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Net Profits Plan Liability Noncurrent		$ 7,611,000
Net Profits Plan Liability Noncurrent		$ 9,476,000	$ 7,611,000
Net Profit Plan liability [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Discount Rate		10.00%	10.00%
Period of New York Mercantile Exchange Strip Pricing Used for Price Forecast		5 years
Period Used for Price Assumptions of Strip Prices for Liabilities		1 year
Percent Change in Commodity Prices for Sensitivity Analysis		5.00%
Sensitivity Analysis Change in Liability, Due to Change in Commodity Prices		$ 1,500,000
Percent Increase and Decrease in Discount Rate for Sensitivity Analysis		1.00%
Sensitivity Analysis Change in Liability Due to Change in Discount Rate		$ 400,000
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Net Profits Plan Liability Noncurrent		7,611,000
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Period Increase (Decrease)	[1]	4,042,000
Net settlements (1) (2)	[1],[2]	(2,177,000)
Transfers in (out) of Level 3		0
Net Profits Plan Liability Noncurrent		$ 9,476,000	$ 7,611,000
[1]	Net changes in the Company’s Net Profits Plan liability are shown in the Change in Net Profits Plan liability line item of the accompanying statements of operations.
[2]	Settlements represent cash payments made or accrued under the Net Profits Plan.

Fair Value Measurements Long-te

Fair Value Measurements Long-term Debt (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Face Amount	$ 2,303,736	$ 2,350,000
Long-term Debt, Fair Value	2,071,292	1,660,128
6.50% Senior Notes Due 2021 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Face Amount	346,955	350,000
Long-term Debt, Fair Value	328,091	262,938
6.125% Senior Notes Due 2022 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Face Amount	561,796	600,000
Long-term Debt, Fair Value	516,852	440,250
6.50% Senior Notes Due 2023 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Face Amount	394,985	400,000
Long-term Debt, Fair Value	366,349	296,000
5% Senior Notes Due 2024 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Face Amount	500,000	500,000
Long-term Debt, Fair Value	426,875	334,065
5.625% Senior Notes Due 2025 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Face Amount	500,000	500,000
Long-term Debt, Fair Value	$ 433,125	$ 326,875
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%
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%
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%
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%
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%

Fair Value Measurements Proved

Fair Value Measurements Proved and Unproved Oil and Gas Properties (Details) - USD ($) $ in Thousands	3 Months Ended					6 Months Ended			12 Months Ended
	Jun. 30, 2016		Mar. 31, 2016	Jun. 30, 2015	Mar. 31, 2015	Jun. 30, 2016		Jun. 30, 2015	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant and Equipment, Net	$ 4,601,332					$ 4,601,332			$ 4,950,280
Period of New York Mercantile Exchange Strip Pricing Used for Price Forecast						5 years
Impairment of Proved Oil and Gas Properties	0			$ 12,914		$ 269,785		$ 68,440	468,700
Abandonment and impairment of unproved properties	38			$ 5,819		2,349		$ 17,446	78,600
Impairment of Long-Lived Assets Held-for-use									49,400
Disposal Group, Not Discontinued Operation, Loss (Gain) on Write-down	(49,500)		$ 68,300		$ 30,000
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	$ 99,900	[1]				$ 99,900	[1]		$ 124,800	[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%
[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.