SM Energy (SM) 10-Q 2 Nov 18 2018 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information Document - shares	9 Months Ended
	Sep. 30, 2018	Oct. 24, 2018
Document and Entity Information [Abstract]
Entity Registrant Name	SM Energy Co
Entity Central Index Key	893,538
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		112,142,751
Entity Current Reporting Status	Yes
Entity Small Business	false
Entity Emerging Growth Company	false

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) (in thousands, except share data) - USD ($) $ in Thousands	Jan. 01, 2018	Sep. 30, 2018		Dec. 31, 2017
Current assets:
Cash and cash equivalents		$ 176,806		$ 313,943
Accounts receivable		179,347		160,154
Derivative assets		81,163		64,266
Prepaid expenses and other		15,826		10,752
Total current assets		453,142		549,115
Property and equipment (successful efforts method):
Proved oil and gas properties		6,686,922		6,139,379
Accumulated depletion, depreciation, and amortization		(3,240,124)		(3,171,575)
Unproved oil and gas properties		1,892,557		2,047,203
Wells in progress		328,808		321,347
Properties held for sale, net		5,040		111,700
Other property and equipment, net of accumulated depreciation of $56,067 and $49,985, respectively		102,984		106,738
Total property and equipment, net		5,776,187		5,554,792
Noncurrent assets:
Derivative assets		8,853		40,362
Other noncurrent assets		35,539		32,507
Total noncurrent assets		44,392		72,869
Total assets		6,273,721		6,176,776
Current liabilities:
Accounts payable and accrued expenses		429,698		386,630
Derivative liabilities		304,159		172,582
Total current liabilities		733,857		559,212
Noncurrent liabilities:
Revolving credit facility		0		0
Senior Notes, net of unamortized deferred financing costs		2,447,290		2,769,663
Senior Convertible Notes, net of unamortized discount and deferred financing costs		145,662		139,107
Asset retirement obligations		88,149		103,026
Asset retirement obligations associated with oil and gas properties held for sale		0		11,369
Deferred income taxes		140,949		79,989
Derivative liabilities		72,605		71,402
Other noncurrent liabilities		45,810		48,400
Total noncurrent liabilities		2,940,465		3,222,956
Commitments and contingencies (note 6)
Stockholders’ equity:
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 112,137,582 and 111,687,016 shares, respectively		1,121		1,117
Additional paid-in capital		1,758,205		1,741,623
Retained earnings		856,111	[1]	665,657
Accumulated other comprehensive loss		(16,038)	[1]	(13,789)
Total stockholders’ equity		2,599,399		2,394,608
Total liabilities and stockholders’ equity		$ 6,273,721		$ 6,176,776
Accounting Standards Update 2018-02 [Member]
Cumulative Effect on Retained Earnings, Net of Tax	$ 3,000
[1]	(1) The Company reclassified $3.0 million of tax effects stranded in accumulated other comprehensive loss to retained earnings as of January 1, 2018. Please refer to Note 1 - Summary of Significant Accounting Policies for further detail.

Condensed Consolidated Balanc_2

Condensed Consolidated Balance Sheets Parenthetical - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Other property and equipment, accumulated depreciation	$ 56,067	$ 49,985
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	112,137,582	111,687,016
Common Stock, Shares, Outstanding	112,137,582	111,687,016

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED) (in thousands, except per share data) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Operating revenues and other income:
Oil, gas, and NGL production revenue	$ 458,382	$ 294,459	$ 1,243,826	$ 912,596
Net gain (loss) on divestiture activity	786	(1,895)	425,656	(131,565)
Other operating revenues	201	2,815	3,398	7,807
Total operating revenues and other income	459,369	295,379	1,672,880	788,838
Operating expenses:
Oil, gas, and NGL production expense	127,638	122,651	365,917	385,073
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	201,105	134,599	483,343	425,643
Exploration	13,061	14,119	40,844	38,919
Abandonment and impairment of unproved properties	9,055	0	26,615	157
General and administrative	29,464	27,564	86,066	84,618
Net derivative (gain) loss	178,026	80,599	249,304	(89,364)
Other operating expenses, net	9,664	999	14,219	10,109
Total operating expenses	568,013	380,531	1,266,308	855,155
Income (loss) from operations	(108,644)	(85,152)	406,572	(66,317)
Interest expense	(38,111)	(44,091)	(122,850)	(135,639)
Loss on extinguishment of debt	(26,722)	0	(26,722)	(35)
Other non-operating income, net	806	861	3,017	1,581
Income (loss) before income taxes	(172,671)	(128,382)	260,017	(200,410)
Income tax (expense) benefit	36,748	39,270	(61,342)	65,825
Net income (loss)	$ (135,923)	$ (89,112)	$ 198,675	$ (134,585)
Basic weighted-average common shares outstanding	112,107	111,575	111,836	111,366
Diluted weighted-average common shares outstanding	112,107	111,575	113,600	111,366
Basic net income (loss) per common share	$ (1.21)	$ (0.80)	$ 1.78	$ (1.21)
Diluted net income (loss) per common share	(1.21)	(0.80)	1.75	(1.21)
Dividends per common share	$ 0.05	$ 0.05	$ 0.10	$ 0.10

CONDENSED CONSOLIDATED STATEM_2

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED) (in thousands) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ (135,923)	$ (89,112)	$ 198,675	$ (134,585)
Other comprehensive income (loss), net of tax:
Pension liability adjustment	263	(208)	721	(651)
Total other comprehensive income (loss), net of tax	263	(208)	721	(651)
Total comprehensive income (loss)	$ (135,660)	$ (89,320)	$ 199,396	$ (135,236)

CONDENSED CONSOLIDATED STATEM_3

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (in thousands) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Cash flows from operating activities:
Net income (loss)		$ (135,923)	$ (89,112)	$ 198,675	$ (134,585)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net (gain) loss on divestiture activity		(786)	1,895	(425,656)	131,565
Depletion, depreciation, amortization, and asset retirement obligation liability accretion		201,105	134,599	483,343	425,643
Abandonment and impairment of unproved properties		9,055	0	26,615	157
Stock-based compensation expense				17,680	16,160
Net derivative (gain) loss		178,026	80,599	249,304	(89,364)
Derivative settlement gain (loss)				(101,911)	29,402
Amortization of debt discount and deferred financing costs				11,542	12,478
Loss on extinguishment of debt		26,722	0	26,722	35
Deferred income taxes		(36,833)	(36,668)	60,672	(67,458)
Other, net				(2,084)	6,424
Net change working capital				(3,725)	40,153
Net cash provided by operating activities				541,177	370,610
Cash flows from investing activities:
Net proceeds from the sale of oil and gas properties				743,199	778,365
Capital expenditures				(1,032,588)	(624,969)
Acquisition of proved and unproved oil and gas properties				(24,571)	(87,389)
Net cash provided by (used in) investing activities				(313,960)	66,007
Cash flows from financing activities:
Proceeds from credit facility				0	406,000
Repayment of credit facility				0	(406,000)
Debt issuance costs related to credit facility				(4,771)	0
Net proceeds from Senior Notes				492,079	0
Cash paid to repurchase Senior Notes, including premium				(844,984)	(2,357)
Net proceeds from sale of common stock				1,881	1,738
Dividends paid				(5,584)	(5,563)
Other, net				(2,975)	(1,392)
Net cash used in financing activities				(364,354)	(7,574)
Net change in cash, cash equivalents, and restricted cash	[1]			(137,137)	429,043
Cash, cash equivalents, and restricted cash at beginning of period	[1]			313,943	12,372
Cash, cash equivalents, and restricted cash at end of period	[1]	176,806	441,415	176,806	441,415
Operating activities:
Cash paid for interest, net of capitalized interest				(124,435)	(124,443)
Net cash paid for income taxes				(9,085)	(2,800)
Investing activities:
Changes in capital expenditure accruals and other				19,811	2,788
Supplemental non-cash investing activities:
Carrying value of properties exchanged				95,121
Supplemental non-cash financing activities:
Non-cash loss on extinguishment of debt				6,334	22
Dividends declared, but not paid		$ 5,607	$ 5,581	$ 5,607	$ 5,581
[1]	(1) Refer to Note 1 - Summary of Significant Accounting Policies for a reconciliation of cash, cash equivalents, and restricted cash reported to the amounts reported within the accompanying unaudited condensed consolidated balance sheets (“accompanying balance sheets”).

Summary of Significant Accounti

Summary of Significant Accounting Policies	9 Months Ended
	Sep. 30, 2018
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 1 - Summary of Significant Accounting Policies Description of Operations SM Energy Company, together with its consolidated subsidiaries (“SM Energy” or the “Company”), is an independent energy company engaged in the acquisition, exploration, development, and production of crude oil and condensate, natural gas, and natural gas liquids (also respectively referred to as “oil,” “gas,” and “NGLs” throughout this report) in onshore North America. Basis of Presentation The accompanying unaudited condensed consolidated financial statements include the accounts of SM Energy and have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information, 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 the consolidated financial statements included in SM Energy’s Annual Report on Form 10-K for the year ended December 31, 2017 (the “ 2017 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 September 30, 2018 , and through the filing of this report. Certain prior period amounts have been reclassified to conform to the current presentation on the accompanying unaudited condensed consolidated financial statements. Correction of an Immaterial Error The accompanying unaudited condensed consolidated financial statements for the three and nine months ended September 30, 2018, include a non-cash adjustment that relates to prior years. For the three and nine months ended September 30, 2018, the depletion, depreciation, amortization, and asset retirement obligation liability accretion expense line item on the accompanying unaudited condensed consolidated statements of operations (“accompanying statements of operations”) includes $11.8 million of additional expense that should have been recognized in prior years. This non-cash adjustment, net of tax, resulted in reported net income for the nine months ended September 30, 2018 , to be understated by $9.0 million , and reported net loss for the three months ended September 30, 2018 , to be overstated by $9.0 million . This non-cash adjustment is not deemed material with respect to any prior period reported, the third quarter of 2018, or the anticipated results for fiscal year 2018. Significant Accounting Policies The significant accounting policies followed by the Company are set forth in Note 1 - Summary of Significant Accounting Policies in the 2017 Form 10-K, and are supplemented by the notes to the unaudited condensed consolidated financial statements included in this report. These unaudited condensed consolidated financial statements should be read in conjunction with the 2017 Form 10-K. Recently Issued Accounting Standards Effective December 31, 2017, the Company early adopted, on a retrospective basis, Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”) and FASB ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (“ASU 2016-18”). ASU 2016-15 is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows and ASU 2016-18 is intended to clarify guidance on the classification and presentation of restricted cash and restricted cash equivalents in the statement of cash flows. The Company did not have restricted cash reported within the accompanying balance sheets as of September 30, 2018, or December 31, 2017. Please refer to Note 1 - Summary of Significant Accounting Policies in the 2017 Form 10-K for more information. The accompanying unaudited condensed consolidated statements of cash flows (“accompanying statements of cash flows”) line items that were adjusted as a result of the adoption of ASU 2016-15 and ASU 2016-18 for the nine months ended September 30, 2017 , are summarized as follows: For the Nine Months Ended September 30, 2017 As Reported As Adjusted (in thousands) Cash flows from operating activities: Non-cash (gain) loss on extinguishment of debt, net $ 22 N/A Loss on extinguishment of debt N/A $ 35 Net cash provided by operating activities $ 370,597 $ 370,610 Cash flows from investing activities: Acquisition deposit held in escrow $ 3,000 N/A Net cash provided by (used in) investing activities $ 69,007 $ 66,007 Cash flows from financing activities: Cash paid for extinguishment of debt (1) N/A $ (13 ) Net cash used in financing activities $ (7,561 ) $ (7,574 ) Net change in cash and cash equivalents $ 432,043 N/A Net change in cash, cash equivalents, and restricted cash N/A $ 429,043 Cash and cash equivalents at beginning of period $ 9,372 N/A Cash, cash equivalents, and restricted cash at beginning of period N/A $ 12,372 Cash and cash equivalents at end of period $ 441,415 N/A Cash, cash equivalents, and restricted cash at end of period N/A $ 441,415 ____________________________________________ (1) Included as a component within the cash paid to repurchase Senior Notes, including premium line item on the accompanying statements of cash flows. Effective January 1, 2018, the Company adopted FASB ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) and all related ASUs (“ASU 2014-09”). Under the new guidance, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. The Company adopted ASU 2014-09 using the modified retrospective transition method, which was applied to all active contracts as of the effective date. The adoption of ASU 2014-09 did not result in a change to current or prior period results nor did it result in a material change to the Company’s business processes, systems, or controls. However, upon adopting ASU 2014-09, the Company expanded its disclosures to comply with the expanded disclosure requirements of ASU 2014-09. Please refer to Note 2 - Revenue from Contracts with Customers for additional discussion. Effective January 1, 2018, the Company adopted FASB ASU No. 2017-07, Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (“ASU 2017-07”). ASU 2017-07 requires presentation of service cost in the same line item(s) as other compensation costs arising from services rendered by employees during the period and presentation of the remaining components of net benefit cost in a separate line item, outside of operating items, which the Company adopted with retrospective application. In addition, only the service component of the net benefit cost is eligible for capitalization, which the Company adopted with prospective application. Please refer to Note 1 - Summary of Significant Accounting Policies in the 2017 Form 10-K for more information. The accompanying statements of operations line items that were adjusted as a result of the adoption of ASU 2017-07 for the three and nine months ended September 30, 2017 , are summarized as follows: For the Three Months Ended September 30, 2017 For the Nine Months Ended September 30, 2017 As Reported As Adjusted As Reported As Adjusted (in thousands) Operating expenses: Exploration $ 14,243 $ 14,119 $ 39,293 $ 38,919 General and administrative $ 27,880 $ 27,564 $ 85,564 $ 84,618 Total operating expenses $ 380,971 $ 380,531 $ 856,475 $ 855,155 Income (loss) from operations $ (85,592 ) $ (85,152 ) $ (67,637 ) $ (66,317 ) Other non-operating income, net $ 1,301 $ 861 $ 2,901 $ 1,581 Effective January 1, 2018, the Company early adopted FASB ASU No. 2018-02, Income Statement-Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (“ASU 2018-02”) by applying the changes in the period of adoption. ASU 2018-02 permits entities to reclassify tax effects stranded in accumulated other comprehensive income (loss) to retained earnings as a result of the enactment into law on December 22, 2017, of H.R.1, formally the Tax Cuts and Jobs Act (the “2017 Tax Act”). As a result of adopting ASU 2018-02, the Company reclassified $3.0 million of tax effects stranded in accumulated other comprehensive loss to retained earnings as of January 1, 2018. The Company’s policy for releasing income tax effects within accumulated other comprehensive loss is an incremental, unit-of-account approach. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”) , which requires recognition of right-of-use assets and lease payment liabilities on the balance sheet by lessees for virtually all leases currently classified as operating leases. The scope of ASU 2016-02 does not apply to leases used in the exploration or use of minerals, oil, natural gas, or other similar non-regenerative resources. The Company has established a cross-functional project team and is leveraging external consultants to evaluate the impacts of ASU 2016-02, which includes an analysis of non-cancelable leases, drilling rig contracts, certain midstream agreements, and other existing arrangements that may contain a lease component. The Company has substantially completed the process of reviewing and determining the contracts to which the new guidance applies. Further, the Company is also evaluating policies, internal controls, and processes that will be necessary to support the additional accounting and disclosure requirements. The Company will continue to monitor guidance issued by the FASB to clarify ASU 2016-02 and certain industry implementation issues. The Company is in the final stages of implementing a lease administration system that will support the on-going maintenance and accounting for leases after adoption. Policy elections allowed under ASU 2016-02 that the Company anticipates making as part of its adoption include (a) not recognizing lease assets or liabilities when lease terms are less than twelve months, and (b) for agreements that contain both lease and non-lease components, combining these components together and accounting for them as a single lease. Other policy elections allowed for under ASU 2016-02 are still being evaluated. The Company will adopt ASU 2016-02 on January 1, 2019, using the modified retrospective approach. Adoption of this guidance is expected to result in an increase in right-of-use assets and related liabilities on the Company’s consolidated balance sheets; however, the full impact to the Company’s financial statements and related disclosures is still being evaluated. In January 2018, the FASB issued ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842 (“ASU 2018-01”), which provides an optional transitional practical expedient that allows entities to exclude from evaluation land easements that existed or expired before adoption of ASU 2016-02. Companies that elect this practical expedient will need to evaluate new or modified land easements after adopting ASU 2016-02. If this practical expedient is not elected, companies will need to evaluate all existing or expired land easements as part of the overall adoption of ASU 2016-02. The Company expects to elect to use this practical expedient as outlined in ASU 2018-01 and will adopt ASU 2018-01 at the same time it adopts ASU 2016-02. In July 2018, the FASB issued ASU No. 2018-11, Leases (Topic 842): Targeted Improvements (“ASU 2018-11”). ASU 2018-11 provides an additional transition method for adopting ASU 2016-02, as well as provides lessors with a practical expedient when applying ASU 2016-02 to certain leases. The Company anticipates making a policy election in connection with adopting ASU 2018-11, which will eliminate the need for adjusting prior period comparable financial statements prepared under current lease accounting guidance. The Company will adopt ASU 2018-11 at the same time it adopts ASU 2016-02. In August 2018, the FASB issued ASU No. 2018-14, Compensation-Retirement Benefits-Defined Benefit Plans-General (Subtopic 715-20): Disclosure Framework-Changes to the Disclosure Requirements for Defined Benefit Plans (“ASU 2018-14”). ASU 2018-14 provides updated disclosure requirements related to retirement benefits and defined pension plans with the purpose of improving the effectiveness of disclosures with regard to such topics. The guidance is to be applied using a retrospective method and is effective for fiscal years ending after December 15, 2020, with early adoption permitted. The Company expects to early adopt ASU 2018-14 on December 31, 2018. The Company is evaluating the impact of this guidance on its consolidated financial statements, but does not expect the impact to be material. In August 2018, the FASB issued ASU No. 2018-15, Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”). ASU 2018-15 aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The Company expects to adopt ASU 2018-15 on January 1, 2020, with prospective application. The Company is evaluating the impact of ASU 2018-15 on its consolidated financial statements. Other than as disclosed above or in the 2017 Form 10-K, there are no other ASUs applicable to the Company that would have a material effect on the Company’s consolidated financial statements and related disclosures that have been issued but not yet adopted by the Company as of September 30, 2018 , and through the filing of this report.

Revenue from Contracts with Cus

Revenue from Contracts with Customers	9 Months Ended
	Sep. 30, 2018
Revenue from Contract with Customer [Abstract]
Revenue from Contracts with Customers	Note 2 - Revenue from Contracts with Customers The Company recognizes its share of revenue from the sale of produced oil, gas, and NGLs in its Permian, South Texas & Gulf Coast, and Rocky Mountain regions. During the first quarter of 2018, the Company entered into two definitive agreements to sell all of its producing properties in its Rocky Mountain region. One transaction closed in the first quarter of 2018, and the second transaction closed in the second quarter of 2018. As a result of these divestitures, there has been no production revenue from the Rocky Mountain region after the second quarter of 2018. Please refer to Note 3 - Divestitures, Assets Held for Sale, and Acquisitions for additional detail. Oil, gas, and NGL production revenue presented within the accompanying statements of operations is reflective of the revenue generated from contracts with customers. The tables below present the disaggregation of oil, gas, and NGL production revenue by product type for each of the Company’s operating regions for the three and nine months ended September 30, 2018 , and 2017: Permian South Texas & Gulf Coast Rocky Mountain Total Three Months Ended September 30, Three Months Ended September 30, Three Months Ended September 30, Three Months Ended September 30, 2018 2017 2018 2017 2018 2017 2018 2017 (in thousands) Oil, gas, and NGL production revenue: Oil production revenue $ 270,086 $ 107,248 $ 17,436 $ 13,726 $ — $ 33,229 $ 287,522 $ 154,203 Gas production revenue 40,364 16,034 56,446 69,069 — 1,162 96,810 86,265 NGL production revenue 563 151 73,487 53,023 — 817 74,050 53,991 Total $ 311,013 $ 123,433 $ 147,369 $ 135,818 $ — $ 35,208 $ 458,382 $ 294,459 Relative percentage 68 % 42 % 32 % 46 % — % 12 % 100 % 100 % ____________________________________________ Note: Amounts may not calculate due to rounding. Permian South Texas & Gulf Coast Rocky Mountain Total Nine Months Ended September 30, Nine Months Ended September 30, Nine Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 2018 2017 2018 2017 (in thousands) Oil, gas, and NGL production revenue: Oil production revenue $ 703,516 $ 267,301 $ 56,365 $ 65,662 $ 54,851 $ 117,738 $ 814,732 $ 450,701 Gas production revenue 96,974 40,280 161,414 245,030 1,595 3,846 259,983 289,156 NGL production revenue 816 405 167,505 169,938 790 2,396 169,111 172,739 Total $ 801,306 $ 307,986 $ 385,284 $ 480,630 $ 57,236 $ 123,980 $ 1,243,826 $ 912,596 Relative percentage 64 % 34 % 31 % 53 % 5 % 13 % 100 % 100 % ____________________________________________ Note: Amounts may not calculate due to rounding. The Company recognizes oil, gas, and NGL production revenue at the point in time when control of the product transfers to the customer, which differs depending on the contractual terms of each of the Company’s arrangements. Transfer of control drives the presentation of transportation, gathering, processing, and other post-production expenses (“fees and other deductions”) within the accompanying statements of operations. Fees and other deductions incurred prior to control transfer are recorded within the oil, gas, and NGL production expense line item on the accompanying statements of operations, while fees and other deductions incurred subsequent to control transfer are recorded as a reduction of oil, gas, and NGL production revenue. The Company has four general categories under which oil, gas, and NGL production revenue is generated. Each of the Company’s operating regions generate production revenue from a combination of some or all of the four different contract types summarized below: 1) The Company sells oil production at or near the wellhead and receives an agreed-upon index price from the purchaser, net of basis, quality, and transportation differentials. Under this arrangement, control transfers at or near the wellhead. 2) The Company sells unprocessed gas to a midstream processor at the wellhead or inlet of the midstream processing facility. The midstream processor gathers and processes the raw gas stream and remits proceeds to the Company from the ultimate sale of the processed NGLs and residue gas to third parties. In such arrangements, the midstream processor obtains control of the product at the wellhead or inlet of the facility and is considered the customer. Proceeds received for unprocessed gas under these arrangements are reflected as gas production revenue and are recorded net of transportation and processing fees incurred by the midstream processor after control has transferred. 3) The Company has certain processing arrangements that include the delivery of unprocessed gas to the inlet of a midstream processor’s facility for processing. Upon completion of processing, the midstream processor purchases the NGLs and redelivers residue gas back to the Company in-kind. For the NGLs extracted during processing, the midstream processor remits payment to the Company based on the proceeds it generates from selling the NGLs to other third parties. For the residue gas taken in-kind, the Company has separate sales contracts where control transfers at points downstream of the processing facility. Given the structure of these arrangements and where control transfers, the Company separately recognizes gathering, transportation, and processing fees incurred prior to control transfer. These fees are recorded within the oil, gas, and NGL production expense line item on the accompanying statements of operations. 4) The Company has certain midstream processing arrangements where unprocessed gas is delivered to the inlet of the midstream processor’s facility for processing. Upon completion of processing, the midstream processor purchases the processed NGLs and residue gas and remits the proceeds to the Company from the sale of the products to third-party customers. In these arrangements, control transfers at the tailgate of the midstream processing facility for both products. Given the structure of these arrangements and where control transfers, the Company separately recognizes gathering, transportation, and processing fees incurred prior to control transfer. These fees are recorded within the oil, gas, and NGL production expense line item on the accompanying statements of operations. Significant judgments made in applying the guidance in Accounting Standards Codification Topic 606, Revenue from Contracts with Customers relate to the point in time when control transfers to customers in gas processing arrangements with midstream processors. The Company does not believe that significant judgments are required with respect to the determination of the transaction price, including amounts that represent variable consideration, as volume and price carry a low level of estimation uncertainty given the precision of volumetric measurements and the use of index pricing with predictable differentials. Accordingly, the Company does not consider estimates of variable consideration to be constrained. The Company’s contractual performance obligations arise upon the production of hydrocarbons from wells in which the Company has an ownership interest. The performance obligations are considered satisfied upon control transferring to a customer at the wellhead, inlet, or tailgate of the midstream processor’s processing facility, or other contractually specified delivery point. The time period between production and satisfaction of performance obligations is generally less than one day; thus, there are no material unsatisfied or partially unsatisfied performance obligations at the end of the reporting period. Revenue is recorded in the month when contractual performance obligations are satisfied. However, settlement statements from the purchasers of hydrocarbons and the related cash consideration are generally received 30 to 90 days after production has occurred. As a result, the Company must estimate the amount of production delivered to the customer and the consideration that will ultimately be received for sale of the product. Estimated revenue due to the Company is recorded within accounts receivable on the accompanying balance sheets until payment is received. The accounts receivable balances from contracts with customers within the accompanying balance sheets as of September 30, 2018 , and December 31, 2017, were $120.3 million and $96.6 million , respectively. To estimate accounts receivable from contracts with customers, the Company uses knowledge of its properties, historical performance, contractual arrangements, pricing, quality and transportation differentials, and other factors as the basis for these estimates. Differences between estimates and actual amounts received for product sales are recorded in the month that payment is received from the purchaser. Revenue recognized for the three and nine months ended September 30, 2018 , that related to performance obligations satisfied in prior reporting periods was immaterial.

Divestitures, Assets Held for S

Divestitures, Assets Held for Sale, and Acquisitions	9 Months Ended
	Sep. 30, 2018
Divestitures, Assets Held for Sale, and Acquisitions [Abstract]
Divestitures, Assets Held for Sale, and Acquisitions [Text Block]	Note 3 - Divestitures, Assets Held for Sale, and Acquisitions Divestitures On March 26, 2018 , the Company divested approximately 112,000 net acres of its Powder River Basin assets (the “PRB Divestiture”) for total cash received at closing, net of costs (referred to throughout this report as “net divestiture proceeds”), of $490.8 million , subject to final purchase price adjustments, and recorded an estimated net gain of $410.6 million for the nine months ended September 30, 2018 . These assets were recorded as properties held for sale as of December 31, 2017. During the second quarter of 2018, the Company completed the divestitures of its remaining assets in the Williston Basin located in Divide County, North Dakota (the “Divide County Divestiture”) and its Halff East assets in the Midland Basin (the “Halff East Divestiture”), for combined net divestiture proceeds received at closing of $250.8 million , subject to final purchase price adjustments, and recorded a combined estimated net gain of $15.4 million for the nine months ended September 30, 2018 . A portion of these assets were recorded as properties held for sale as of December 31, 2017. The following table presents income (loss) before income taxes from the Divide County, North Dakota assets sold for the three and nine months ended September 30, 2018 , and 2017. The Divide County Divestiture was considered a disposal of a significant asset group. For the Three Months Ended September 30, For the Nine Months Ended September 30, 2018 2017 2018 2017 (in thousands) Income (loss) before income taxes (1) $ — $ 7,593 $ (28,975 ) $ (478,572 ) ____________________________________________ (1) Income (loss) before income taxes reflects oil, gas, and NGL production revenue, less oil, gas, and NGL production expense, depletion, depreciation, amortization, and asset retirement obligation liability accretion expense, impairment expense, and net loss on divestiture activity. On March 10, 2017, the Company closed the divestiture of its outside-operated Eagle Ford shale assets, including its ownership interest in related midstream assets, for final net divestiture proceeds of $744.1 million . The Company recorded a final net gain of $396.8 million related to these divested assets for the year ended December 31, 2017. Additionally, during the first nine months of 2017, the Company divested certain non-core properties in its Rocky Mountain and Permian regions for net divestiture proceeds of $31.0 million . Properties Held for Sale Assets are classified as held for sale when the Company commits to a plan to sell the assets and it is probable the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and a measurement for impairment is performed to identify and expense any excess of carrying value over fair value less estimated costs to sell. When assets no longer meet the criteria of assets held for sale, they are measured at the lower of the carrying value of the assets before being classified as held for sale, adjusted for any depletion, depreciation, and amortization expense that would have been recognized, or the fair value at the date they are reclassified to assets held for use. Any gain or loss recognized on assets held for sale or on assets held for sale that are subsequently reclassified to assets held for use is reflected in the net gain (loss) on divestiture activity line item on the accompanying statements of operations. As of September 30, 2018 , and December 31, 2017, there were $5.0 million and $111.7 million , respectively, of assets held for sale presented on the accompanying balance sheets. The balance as of December 31, 2017, consisted primarily of approximately 112,000 net acres in the Powder River Basin, and is presented net of accumulated depletion, depreciation, and amortization expense. As discussed above, the Company sold these assets in the first quarter of 2018. During the nine months ended September 30, 2017, the Company recorded a $526.5 million write-down on its Divide County, North Dakota, assets previously held for sale. As discussed above, the Company sold these assets in the second quarter of 2018. Acquisitions During the third quarter of 2018, the Company completed two non-monetary acreage trades of primarily unproved properties located in Howard and Martin Counties, Texas, resulting in the Company receiving 2,658 net acres in exchange for 2,654 net acres, with $95.1 million of carrying value attributed to the properties surrendered by the Company. These trades were recorded at carryover basis with no gain or loss recognized. During the second quarter of 2018, the Company acquired 720 net acres of unproved properties in Martin County, Texas, for $24.6 million . Under authoritative accounting guidance, this transaction was considered an asset acquisition. Therefore, the properties were recorded based on the fair value of the total consideration transferred on the acquisition date and the transaction costs were capitalized as a component of the cost of the assets acquired. During the nine months ended September 30, 2017, the Company acquired 3,400 net acres of primarily unproved properties in Howard and Martin Counties, Texas, in multiple transactions for a total of $72.2 million of cash consideration. Each of these transactions was accounted for as an asset acquisition. Also, during the nine months ended September 30, 2017, the Company completed several non-monetary acreage trades of primarily unproved properties in Howard and Martin Counties, Texas, resulting in the Company receiving 7,425 net acres in exchange for 6,725 net acres, with $283.7 million of carrying value attributed to the properties surrendered by the Company. These trades were recorded at carryover basis with no gain or loss recognized.

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2018
Income Tax Disclosure [Abstract]
Income Taxes	Note 4 - Income Taxes The income tax (expense) benefit recorded for the three and nine months ended September 30, 2018 , and 2017 , 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, excess tax benefits and deficiencies from share-based payment awards, changes in valuation allowances, and accumulated impacts of other smaller permanent differences. The quarterly rate can also be affected by the proportional impacts of forecasted net income or loss as of each period end presented. The provision for income taxes for the three and nine months ended September 30, 2018 , and 2017 , consisted of the following: For the Three Months Ended For the Nine Months Ended 2018 2017 2018 2017 (in thousands) Current portion of income tax (expense) benefit: Federal $ — $ 2,832 $ — $ — State (85 ) (230 ) (670 ) (1,633 ) Deferred portion of income tax (expense) benefit 36,833 36,668 (60,672 ) 67,458 Income tax (expense) benefit $ 36,748 $ 39,270 $ (61,342 ) $ 65,825 Effective tax rate 21.3 % 30.6 % 23.6 % 32.8 % The enactment of the 2017 Tax Act on December 22, 2017, reduced the Company’s federal tax rate for 2018 and future years from 35 percent to 21 percent . Although the Company believes it has properly analyzed the tax accounting impacts of the 2017 Tax Act, it will continue to monitor provisions with discrete rate impacts, such as the limitation on executive compensation for subsequent events and guidance within the one-year measurement period. There are no new estimates or finalized income tax items associated with the 2017 Tax Act included in income tax (expense) benefit for the three and nine months ended September 30, 2018 . On a year-to-date basis, a change in the Company’s effective tax rate between reporting periods will generally reflect differences in its estimated highest marginal state tax rate due to changes in the composition of income or loss from Company activities, including divestitures, among multiple state tax jurisdictions. Excess tax benefits and deficiencies from share-based payment awards impact the Company’s effective tax rate between periods. Cumulative effects of state tax rate changes are reflected in the period legislation is enacted. In 2017, the Company re-evaluated various factors affecting deferred tax assets related to net operating losses and tax credits and determined utilization would be appropriate. The change in the current portion of income tax (expense) benefit between periods reflects the effect of this determination. Subsequent to the quarter ended September 30, 2018, the Company received its anticipated $5.9 million cash refund for a net operating loss carryback claim. During the third quarter of 2018, the Internal Revenue Service finalized its examination of the net operating loss claims back to tax years 2003 through 2005 with no changes to claimed amounts. The Company is generally no longer subject to United States federal or state income tax examinations by tax authorities for years before 2015.

Long-Term Debt (Notes)

Long-Term Debt (Notes)	9 Months Ended
	Sep. 30, 2018
Debt Disclosure [Abstract]
Long-Term Debt [Text Block]	Note 5 - Long-Term Debt Credit Agreement On September 28, 2018 , the Company and its lenders entered into the Sixth Amended and Restated Credit Agreement (the “Credit Agreement”). The Credit Agreement, which replaced the Company’s Fifth Amended and Restated Credit Agreement, provides for a senior secured revolving credit facility with a maximum loan amount of $2.5 billion , an initial borrowing base of $1.5 billion , and initial aggregate lender commitments totaling $1.0 billion . The borrowing base is subject to regular, semi-annual redetermination, and considers the value of both the Company’s (a) proved oil and gas properties reflected in the Company’s most recent reserve report; and (b) commodity derivative contracts, each as determined by the Company’s lender group. The next scheduled redetermination date is April 1, 2019 . The Credit Agreement is scheduled to mature on the earlier of September 28, 2023 , (the “Scheduled Maturity Date”), and August 16, 2022, to the extent that, on or before such date, the Company’s outstanding 6.125% Senior Notes due 2022 (the “2022 Senior Notes”) are not repurchased, redeemed, or refinanced to have a maturity date at least 91 days after the Scheduled Maturity Date unless, on August 16, 2022, both (i) the aggregate outstanding principal amount of the 2022 Senior Notes is not more than $100.0 million and (ii) after giving pro forma effect to the repayment in full at maturity of the 2022 Senior Notes then outstanding, the aggregate amount of unrestricted cash and certain types of unrestricted investments held by the Company and its Consolidated Restricted Subsidiaries plus the amount of unused availability under the Credit Agreement is at least $300.0 million . The Company must comply with certain financial and non-financial covenants under the terms of the Credit Agreement, including covenants limiting dividend payments and requiring the Company to maintain certain financial ratios, as defined by the Credit Agreement. The financial covenants under the Credit Agreement require that the Company’s (a) total funded debt, as defined in the Credit Agreement, to adjusted EBITDAX ratio for the most recently ended four consecutive fiscal quarters (excluding the first three quarters which will use annualized adjusted EBITDAX), cannot be greater than 4.25 to 1.00 beginning with the quarter ending December 31, 2018, through and including the fiscal quarter ending December 31, 2019, and for each quarter ending thereafter, the ratio cannot be greater than 4.00 to 1.00; and (b) adjusted current ratio cannot be less than 1.0 to 1.0 as of the last day of any fiscal quarter. The Company was in compliance with all financial and non-financial covenants as of September 30, 2018 , and through the filing of this report. Interest and commitment fees are accrued based on a borrowing base utilization grid set forth in the Credit Agreement. Eurodollar loans accrue interest at the London Interbank Offered Rate, plus the applicable margin from the utilization grid, and Alternate Base Rate (“ABR”) loans accrue interest at a market based floating rate, plus the applicable margin from the utilization grid. Commitment fees are accrued on the unused portion of the aggregate lender commitment amount at rates from the utilization grid and are included in the interest expense line item on the accompanying statements of operations. The borrowing base utilization grid under the Credit Agreement is as follows: Borrowing Base Utilization Percentage <25% ≥25% <50% ≥50% <75% ≥75% <90% ≥90% Eurodollar Loans 1.500 % 1.750 % 2.000 % 2.250 % 2.500 % ABR Loans or Swingline Loans 0.500 % 0.750 % 1.000 % 1.250 % 1.500 % Commitment Fee Rate 0.375 % 0.375 % 0.500 % 0.500 % 0.500 % The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Credit Agreement as of October 24, 2018 , and September 30, 2018 , and under the Fifth Amended and Restated Credit Agreement as of December 31, 2017 : As of October 24, 2018 As of September 30, 2018 As of December 31, 2017 (in thousands) Credit facility balance (1) $ — $ — $ — Letters of credit (2) 200 200 200 Available borrowing capacity 999,800 999,800 924,800 Total aggregate lender commitment amount $ 1,000,000 $ 1,000,000 $ 925,000 ____________________________________________ (1) Unamortized deferred financing costs attributable to the credit facility are presented as a component of other noncurrent assets on the accompanying balance sheets and totaled $6.7 million and $3.1 million as of September 30, 2018 , and December 31, 2017 , respectively. These costs are being amortized over the term of the credit facility on a straight-line basis. (2) Letters of credit outstanding reduce the amount available under the credit facility on a dollar-for-dollar basis. Senior Notes During the third quarter of 2018, the Company redeemed its 6.50% Senior Notes due 2021 (“2021 Senior Notes”), repurchased or redeemed all of its 6.50% Senior Notes due 2023 (“2023 Senior Notes”), repurchased a portion of its 6.125% Senior Notes due 2022 (“2022 Senior Notes”), and issued its 6.625% Senior Notes due 2027 (“2027 Senior Notes”). As of September 30, 2018, the Company’s Senior Notes consisted of 6.125% Senior Notes due 2022, 5.0% Senior Notes due 2024, 5.625% Senior Notes due 2025, 6.75% Senior Notes due 2026, and 6.625% Senior Notes due 2027 (collectively referred to as “Senior Notes”). Please refer to the discussion below for additional information. The Senior Notes, net of unamortized deferred financing costs line item on the accompanying balance sheets as of September 30, 2018 , and December 31, 2017 , consisted of the following: As of September 30, 2018 As of December 31, 2017 Principal Amount Unamortized Deferred Financing Costs Principal Amount, Net of Unamortized Deferred Financing Costs Principal Amount Unamortized Deferred Financing Costs Principal Amount, Net of Unamortized Deferred Financing Costs (in thousands) 6.50% Senior Notes due 2021 $ — $ — $ — $ 344,611 $ 2,656 $ 341,955 6.125% Senior Notes due 2022 476,796 4,171 472,625 561,796 5,800 555,996 6.50% Senior Notes due 2023 — — — 394,985 3,707 391,278 5.0% Senior Notes due 2024 500,000 4,919 495,081 500,000 5,610 494,390 5.625% Senior Notes due 2025 500,000 6,035 493,965 500,000 6,714 493,286 6.75% Senior Notes due 2026 500,000 6,615 493,385 500,000 7,242 492,758 6.625% Senior Notes due 2027 500,000 7,766 492,234 — — — Total $ 2,476,796 $ 29,506 $ 2,447,290 $ 2,801,392 $ 31,729 $ 2,769,663 The Senior Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt and are senior in right of payment to any future subordinated debt. There are no subsidiary guarantors of the Senior Notes. The Company is subject to certain covenants under the indentures governing the Senior Notes and was in compliance with all such covenants as of September 30, 2018 , and through the filing of this report. The Company may redeem some or all of its Senior Notes prior to their maturity at redemption prices based on a premium, plus accrued and unpaid interest as described in the indentures governing the Senior Notes. 2021 Senior Notes. On June 15, 2018 , the Company called for redemption all of the $344.6 million principal outstanding on its 2021 Senior Notes at a redemption price of 102.167% of the principal amount, plus accrued and unpaid interest on the principal amount of the 2021 Senior Notes redeemed (“2021 Senior Notes Redemption”). On July 16, 2018, the Company completed the 2021 Senior Notes Redemption, which resulted in the payment of total cash consideration, including accrued interest, of $355.9 million . The Company recorded a loss on extinguishment of debt of $9.8 million for the quarter ended September 30, 2018. This amount included $7.5 million associated with the premium paid for the 2021 Senior Notes Redemption and $2.3 million of accelerated unamortized deferred financing costs. Tender Offer and Redemption of the 2023 Senior Notes and 2022 Senior Notes. During the third quarter of 2018, the Company used the proceeds from the issuance of its 2027 Senior Notes, as discussed below, and cash on hand to retire $395.0 million of its 2023 Senior Notes and $85.0 million of its 2022 Senior Notes through a cash tender offer (the “Tender Offer”) and subsequent redemption of the remaining 2023 Senior Notes not repurchased as part of the Tender Offer (“2023 Senior Notes Redemption”). Total consideration paid, including accrued interest, for the retirement of the 2023 Senior Notes and the 2022 Senior Notes was $497.8 million . As a result of the Tender Offer and the 2023 Senior Notes Redemption, the Company recorded a loss on extinguishment of debt of $16.9 million for the quarter ended September 30, 2018. This amount included $12.9 million of premiums paid for the Tender Offer and 2023 Senior Notes Redemption and $4.0 million of accelerated unamortized deferred financing costs. 2027 Senior Notes. On August 20, 2018 , the Company issued $500.0 million in aggregate principal amount of 6.625% Senior Notes due 2027. The 2027 Senior Notes were issued at par and mature on January 15, 2027. The Company received net proceeds of $492.1 million after deducting fees of $7.9 million , which are being amortized as deferred financing costs over the life of the 2027 Senior Notes. The net proceeds were used to fund the Tender Offer and 2023 Senior Notes Redemption discussed above. Senior Convertible Notes The Company’s Senior Convertible Notes consist of $172.5 million in aggregate principal amount of 1.50% Senior Convertible Notes due July 1, 2021 (the “Senior Convertible Notes”). The Senior Convertible Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt and are senior in right of payment to any future subordinated debt. Please refer to Note 5 - Long-Term Debt in the 2017 Form 10-K for additional detail on the Company’s Senior Convertible Notes and associated capped call transactions. The Senior Convertible Notes were not convertible at the option of holders as of September 30, 2018 , or through the filing of this report. Notwithstanding the inability to convert, the if-converted value of the Senior Convertible Notes as of September 30, 2018 , did not exceed the principal amount. The debt discount and debt-related issuance costs are amortized to the principal value of the Senior Convertible Notes as interest expense through the maturity date of July 1, 2021 . Interest expense recognized on the Senior Convertible Notes related to the stated interest rate and amortization of the debt discount totaled $2.6 million and $2.5 million for the three months ended September 30, 2018 , and 2017, respectively, and totaled $7.8 million and $7.4 million for the nine months ended September 30, 2018 , and 2017, respectively. There have been no changes to the initial net carrying amount of the equity component of the Senior Convertible Notes recorded in additional paid-in capital on the accompanying balance sheets since issuance. The Senior Convertible Notes, net of unamortized discount and deferred financing costs line on the accompanying balance sheets as of September 30, 2018 , and December 31, 2017 , consisted of the following: As of September 30, 2018 As of December 31, 2017 (in thousands) Principal amount of Senior Convertible Notes $ 172,500 $ 172,500 Unamortized debt discount (24,316 ) (30,183 ) Unamortized deferred financing costs (2,522 ) (3,210 ) Senior Convertible Notes, net of unamortized discount and deferred financing costs $ 145,662 $ 139,107 The Company is subject to certain covenants under the indenture governing the Senior Convertible Notes and was in compliance with all such covenants as of September 30, 2018 , and through the filing of this report.

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies [Text Block]	Note 6 - Commitments and Contingencies Commitments As of September 30, 2018 , the Company had total gathering, processing, transportation throughput, and purchase commitments with various third parties that require delivery of a minimum quantity of 30 MMBbl of oil, 691 Bcf of gas, and 22 MMBbl of produced water through 2027 and a minimum purchase quantity of 7 MMBbl of water by 2022 . If the Company fails to deliver or purchase any product, as applicable, the aggregate undiscounted future deficiency payments as of September 30, 2018 , would total approximately $342.2 million . This amount does not include any costs that may be incurred for certain contracts where the Company cannot predict with accuracy the amount and timing of any payments that may be incurred for not meeting certain minimum commitments, as such payments are dependent upon the price of oil in effect at the time of settlement. Under certain of the Company’s commitment agreements, if the Company is unable to deliver the minimum quantity from its production, it may deliver production acquired from third parties. As of the filing of this report, the Company does not expect to incur any material shortfalls with regard to these commitments. The Company entered into new and amended drilling rig and completion service contracts during the first nine months of 2018 , and subsequent to September 30, 2018 . As of the filing of this report, the Company’s drilling rig and completion service contract commitments totaled $93.0 million . If all of these contracts were terminated as of the filing of this report, the Company would avoid a portion of the contractual service commitments; however, would be required to pay $42.7 million in early termination fees. Additionally, as of September 30, 2018 , the Company had fixed price contracts with various third parties to purchase electricity through 2027 for total consideration of $29.9 million . As of the filing of this report, the Company expects to meet these purchase commitments. There were no other material changes in commitments during the first nine months of 2018 . Please refer to Note 6 - Commitments and Contingencies in the 2017 Form 10-K for additional discussion of the Company’s commitments. Contingencies The Company is subject to litigation and claims arising in the ordinary course of business. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. In the opinion of management, the anticipated results of any pending litigation and claims are not expected to have a material effect on the results of operations, the financial position, or the cash flows of the Company.

Compensation Plans

Compensation Plans	9 Months Ended
	Sep. 30, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Compensation Plans [Text Block]	Note 7 - Compensation Plans Equity Incentive Compensation Plan As of September 30, 2018 , 5.7 million shares of common stock were available for grant under the Company’s Equity Incentive Compensation Plan. Performance Share Units The Company grants performance share units (“PSUs”) to eligible employees as part of its long-term equity incentive compensation program. The number of shares of the Company’s common stock issued to settle PSUs ranges from zero to two times the number of PSUs awarded and is determined based on certain performance criteria over a three -year performance period. PSUs generally vest on the third anniversary of the date of the grant. PSUs, which the Company has determined to be equity awards, are subject to a combination of market, performance, and service vesting criteria. For awards with market criteria or portions of awards with market criteria, which include annualized Total Shareholder Return (“TSR”) for the performance period and the relative performance of the Company’s TSR compared with the annualized TSR of the Company’s peer group for the performance period, the fair value is measured at the grant date using a stochastic Monte Carlo simulation using geometric Brownian motion. Compensation expense for market-based PSUs is recognized on a straight-line basis within general and administrative expense and exploration expense over the vesting periods of the respective awards. For awards that include performance criteria, the grant-date fair value is equal to the Company's stock price on the grant date. Compensation expense for performance-based PSUs will be evaluated on a quarterly basis and may be adjusted as the number of units expected to vest increases or decreases. Currently, the Company uses debt adjusted per share cash flow growth (“DACFG”) compared with the DACFG, as calculated by the Company, of its peer group as the performance criteria that is evaluated over the three-year performance period for PSUs. Total compensation expense recorded for PSUs was $3.0 million and $2.6 million for the three months ended September 30, 2018 , and 2017 , respectively, and was $7.7 million and $6.8 million for the nine months ended September 30, 2018 , and 2017 , respectively. As of September 30, 2018 , there was $22.9 million of total unrecognized compensation expense related to non-vested PSU awards, which is being amortized through 2021. A summary of the status and activity of non-vested PSUs for the nine months ended September 30, 2018 , is presented in the following table: PSUs (1) Weighted-Average Grant-Date Fair Value Non-vested at beginning of year 1,533,491 $ 22.97 Granted 572,924 $ 24.45 Vested (233,102) $ 44.25 Forfeited (97,122) $ 22.89 Non-vested at end of quarter 1,776,191 $ 20.66 ____________________________________________ (1) The number of awards assumes a multiplier of one . The final number of shares of common stock issued may vary depending on the three -year performance multiplier which ranges from zero to two . During the nine months ended September 30, 2018 , the Company granted 572,924 PSUs to eligible employees with a fair value of $14.0 million (“2018 PSU Grant”). As outlined in the award agreement for the 2018 PSU Grant, performance measurements affecting vesting are based on a combination of relative performance of the Company’s annualized TSR compared with the annualized TSR of the Company’s peer group over the three-year performance period, and relative performance of the Company’s DACFG compared with its peer group DACFG over the three-year performance period. In addition to these performance measures, the award agreement for the 2018 PSU Grant also stipulates that if the Company’s absolute TSR is negative over the three -year performance period, the maximum number of shares of common stock that can be issued to settle outstanding PSUs is capped at one times the number of PSUs granted on the award date, regardless of the Company’s TSR and DACFG performance relative to its peer group. During the nine months ended September 30, 2018 , PSUs that were granted in 2015 did not satisfy the minimum performance requirements. This resulted in a multiplier of zero times and therefore no shares were issued upon settlement. Restricted Stock Units The Company grants restricted stock units (“RSUs”) to eligible persons as part of its long-term equity incentive compensation program. Each RSU represents a right to receive one share of the Company’s common stock upon settlement of the award at the end of the specified vesting period. Compensation expense for RSUs is recognized within general and administrative expense and exploration expense over the vesting periods of the respective awards. RSUs granted to employees generally vest one-third on each anniversary date of the grant over a three -year vesting period. Total compensation expense recorded for employee RSUs was $3.0 million and $2.9 million for the three months ended September 30, 2018 , and 2017 , respectively, and was $8.0 million and $7.5 million for the nine months ended September 30, 2018 , and 2017 , respectively. As of September 30, 2018 , there was $24.1 million of total unrecognized compensation expense related to non-vested RSU awards, which is being amortized through 2021. A summary of the status and activity of non-vested RSUs granted to employees for the nine months ended September 30, 2018 , is presented in the following table: RSUs Weighted-Average Grant-Date Fair Value Non-vested at beginning of year 1,244,262 $ 20.25 Granted 583,552 $ 25.77 Vested (407,529) $ 24.30 Forfeited (112,141) $ 17.93 Non-vested at end of quarter 1,308,144 $ 21.46 During the nine months ended September 30, 2018 , the Company granted 583,552 RSUs to eligible employees with a fair value of $15.0 million . During the nine months ended September 30, 2018 , the Company settled 407,529 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 291,745 net shares of common stock upon settlement of the awards. Director Shares During the second quarter of 2018, the Company issued 58,572 shares of its common stock to its non-employee directors under the Company’s Equity Incentive Compensation Plan, which fully vest on December 31, 2018. During the second quarter of 2017, the Company issued 71,573 shares of its common stock to its non-employee directors and 8,794 RSUs to a non-employee director. The Company did not issue any director shares during the third quarters of 2018, or 2017. Employee Stock Purchase Plan Under the Company’s Employee Stock Purchase Plan (“ESPP”), eligible employees may purchase shares of the Company’s common stock through payroll deductions of up to 15 percent of eligible compensation, without accruing in excess of $25,000 in value from purchases for each calendar year. The purchase price of the stock is 85 percent of the lower of the fair market value of the stock on either the first or last day of the purchase period. The ESPP is intended to qualify under Section 423 of the Internal Revenue Code. The Company issued 100,249 and 123,678 shares under the ESPP during the nine months ended September 30, 2018 , and 2017, respectively. Total proceeds to the Company for the issuance of these shares was $1.9 million and $1.7 million for the nine months ended September 30, 2018 , and 2017, 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	9 Months Ended
	Sep. 30, 2018
Defined Benefit Plan [Abstract]
Pension Benefits [Text Block]	Note 8 - Pension Benefits Pension Plans The Company has a non-contributory defined benefit pension plan covering employees who meet age and service requirements (the “Qualified Pension Plan”). The Company also has a supplemental non-contributory pension plan covering certain management employees (the “Nonqualified Pension Plan” and together with the Qualified Pension Plan, the “Pension Plans”). Effective as of January 1, 2016, the Company froze the Pension Plans to new participants, and employees eligible to participate in the Pension Plans prior to them being frozen 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 For the Nine Months Ended 2018 2017 2018 2017 (in thousands) Service cost $ 1,683 $ 1,660 $ 5,048 $ 4,979 Interest cost 657 673 1,967 2,017 Expected return on plan assets that reduces periodic pension benefit cost (466 ) (561 ) (1,397 ) (1,683 ) Amortization of prior service cost 4 4 13 13 Amortization of net actuarial loss 331 324 995 973 Net periodic benefit cost $ 2,209 $ 2,100 $ 6,626 $ 6,299 Prior service costs are amortized on a straight-line basis over the average remaining service period of active participants. Gains and losses in excess of 10 percent of the greater of the benefit obligation or the market-related value of assets are amortized over the average remaining service period of active participants. As a result of the adoption of ASU 2017-07, the service cost component of net periodic benefit cost for the Pension Plans is presented as an operating expense within the general and administrative and exploration expense line items on the accompanying statements of operations while the other components of net periodic benefit cost for the Pension Plans are presented as non-operating expenses within the other non-operating income, net line item on the accompanying statements of operations. Please refer to Note 1 - Summary of Significant Accounting Policies for further detail. Contributions The Company contributed $8.1 million to the Qualified Pension Plan during the nine months ended September 30, 2018 .

Earnings per Share

Earnings per Share	9 Months Ended
	Sep. 30, 2018
Earnings Per Share [Abstract]
Earnings per Share [Text Block]	Note 9 - Earnings Per Share Basic net income or loss per common share is calculated by dividing net income or loss available to common stockholders by the basic weighted-average number of common shares outstanding for the respective period. Diluted net income or loss per common share is calculated by dividing adjusted net income or loss by the diluted weighted-average number of common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist primarily of non-vested RSUs, contingent PSUs, and shares into which the Senior Convertible Notes are convertible, which are measured using the treasury stock method. Shares of the Company’s common stock traded at an average closing price below the $40.50 conversion price for the three and nine months ended September 30, 2018 , and 2017 , and therefore the Senior Convertible Notes had no dilutive impact. Please refer to Note 1 - Summary of Significant Accounting Policies in the 2017 Form 10-K for additional detail on these potentially dilutive securities. When the Company recognizes a loss from continuing operations, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted net loss per common share. The following table presents the weighted-average anti-dilutive securities for the periods presented: For the Three Months Ended For the Nine Months Ended 2018 2017 2018 2017 (in thousands) Anti-dilutive 2,433 — — 78 The following table sets forth the calculations of basic and diluted net income (loss) per common share: For the Three Months Ended For the Nine Months Ended 2018 2017 2018 2017 (in thousands, except per share data) Net income (loss) $ (135,923 ) $ (89,112 ) $ 198,675 $ (134,585 ) Basic weighted-average common shares outstanding 112,107 111,575 111,836 111,366 Dilutive effect of non-vested RSUs and contingent PSUs — — 1,764 — Dilutive effect of Senior Convertible Notes — — — — Diluted weighted-average common shares outstanding 112,107 111,575 113,600 111,366 Basic net income (loss) per common share $ (1.21 ) $ (0.80 ) $ 1.78 $ (1.21 ) Diluted net income (loss) per common share $ (1.21 ) $ (0.80 ) $ 1.75 $ (1.21 )

Derivative Financial Instrument

Derivative Financial Instruments	9 Months Ended
	Sep. 30, 2018
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Derivative Financial Instruments	Note 10 - Derivative Financial Instruments Summary of Oil, Gas, and NGL Derivative Contracts in Place The Company has entered into various commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in commodity prices and the associated impact on cash flows. As of September 30, 2018 , all derivative counterparties were members of the Company’s Credit Agreement lender group and all contracts were entered into for other-than-trading purposes. The Company’s commodity derivative contracts consist of swap and collar arrangements for oil and gas production, and swap arrangements for NGL production. In a typical commodity swap agreement, if the agreed upon published third-party index price (“index price”) is lower than the swap fixed price, the Company receives the difference between the index price and the agreed upon swap fixed price. If the index price is higher than the swap fixed price, the Company pays the difference. For collar arrangements, the Company receives the difference between an agreed upon index and the floor price if the index price is below the floor price. The Company pays the difference between the agreed upon ceiling price and the index price if the index price is above the ceiling price. No amounts are paid or received if the index price is between the floor and ceiling prices. The Company has also entered into fixed price oil basis swaps in order to mitigate exposure to adverse pricing differentials between certain industry benchmark prices and the actual physical pricing points where the Company’s production volumes are sold. Currently, the Company has basis swap contracts with fixed price differentials between NYMEX WTI and WTI Midland for a portion of its Midland Basin production with sales contracts that settle at WTI Midland prices. The Company also has basis swaps with fixed price differentials between NYMEX WTI and Intercontinental Exchange Brent Crude (“ICE Brent”) for a portion of its Midland Basin oil production with sales contracts that settle at ICE Brent prices. As of September 30, 2018 , the Company had commodity derivative contracts outstanding as summarized in the tables below: Oil Swaps Contract Period NYMEX WTI Volumes Weighted-Average Contract Price (MBbl) (per Bbl) Fourth quarter 2018 1,894 $ 49.87 2019 3,733 $ 59.80 2020 2,491 $ 65.68 Total 8,118 Oil Collars Contract Period NYMEX WTI Volumes Weighted- Average Floor Price Weighted- Average Ceiling Price (MBbl) (per Bbl) (per Bbl) Fourth quarter 2018 2,222 $ 50.00 $ 58.44 2019 10,055 $ 50.59 $ 63.62 2020 1,165 $ 55.00 $ 66.47 Total 13,442 Oil Basis Swaps Contract Period WTI Midland-NYMEX WTI Volumes Weighted-Average Contract Price (1) NYMEX WTI-ICE Brent Volumes Weighted-Average (2) (MBbl) (per Bbl) (MBbl) (per Bbl) Fourth quarter 2018 3,327 $ (1.08 ) — $ — 2019 11,217 $ (3.36 ) — $ — 2020 10,960 $ (1.05 ) 1,840 $ (8.01 ) 2021 — $ — 3,650 $ (7.86 ) 2022 — $ — 3,650 $ (7.78 ) Total 25,504 9,140 ____________________________________________ (1) Represents the price differential between WTI Midland (Midland, Texas) and NYMEX WTI (Cushing, Oklahoma). (2) Represents the price differential between NYMEX WTI (Cushing, Oklahoma) and ICE Brent (North Sea). Gas Swaps Contract Period Sold IF HSC Volumes Weighted-Average Contract Price Purchased IF HSC Volumes Weighted-Average Contract Price Net IF HSC Volumes Weighted-Average Contract Price (BBtu) (per MMBtu) (BBtu) (per MMBtu) (BBtu) (per MMBtu) Fourth quarter 2018 28,204 $ 3.27 (7,210 ) $ 4.27 20,994 $ 2.92 2019 50,021 $ 3.58 (24,415 ) $ 4.34 25,606 $ 2.85 2020 2,942 $ 2.82 — $ — 2,942 $ 2.82 Total 81,167 (31,625 ) 49,542 Gas Collars Contract Period IF HSC Volumes Weighted- Average Floor Price Weighted- Average Ceiling Price (BBtu) (per MMBtu) (per MMBtu) 2019 14,242 $ 2.50 $ 2.83 NGL Swaps OPIS Ethane Purity Mont Belvieu OPIS Propane Mont Belvieu Non-TET OPIS Normal Butane Mont Belvieu Non-TET OPIS Isobutane Mont Belvieu Non-TET OPIS Natural Gasoline Mont Belvieu Non-TET Contract Period Volumes Weighted-Average Contract Price Volumes Weighted-Average Volumes Weighted-Average Volumes Weighted-Average Volumes Weighted-Average (MBbl) (per Bbl) (MBbl) (per Bbl) (MBbl) (per Bbl) (MBbl) (per Bbl) (MBbl) (per Bbl) Fourth quarter 2018 1,146 $ 11.18 671 $ 24.39 102 $ 35.70 76 $ 35.07 208 $ 50.99 2019 3,533 $ 12.31 1,980 $ 28.89 154 $ 35.64 117 $ 35.70 197 $ 50.93 2020 539 $ 11.13 — $ — — $ — — $ — — $ — Total 5,218 2,651 256 193 405 Commodity Derivative Contracts Entered Into Subsequent to September 30, 2018 Subsequent to September 30, 2018 , the Company entered into various commodity derivative contracts, as summarized below: • fixed price NYMEX WTI-ICE Brent basis swap contracts for 2020 for a total of 0.9 MMBbl of oil production at contract prices ranging from ($8.05) per Bbl to ($8.10) per Bbl; • IF HSC swap contracts for 2019 for a total of 15,769 BBtu of natural gas production at contract prices ranging from $2.80 per MMBtu to $3.42 per MMBtu; • fixed price OPIS Propane Mont Belvieu Non-TET swap contract for the fourth quarter of 2018 for a total of 0.1 MMBbl of propane production at a contract price of $45.59 per Bbl; and • fixed price OPIS Propane Mont Belvieu Non-TET swap contracts for 2019 for a total of 0.4 MMBbl of propane production at a contract price of $40.11 per Bbl. Derivative Assets and Liabilities Fair Value The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities. The fair value of the commodity derivative contracts was a net liability of $286.7 million and $139.4 million as of September 30, 2018 , and December 31, 2017 , respectively. The following table details the fair value of commodity derivative contracts recorded in the accompanying balance sheets, by category: As of September 30, 2018 As of December 31, 2017 (in thousands) Derivative assets: Current assets $ 81,163 $ 64,266 Noncurrent assets 8,853 40,362 Total derivative assets $ 90,016 $ 104,628 Derivative liabilities: Current liabilities $ 304,159 $ 172,582 Noncurrent liabilities 72,605 71,402 Total derivative liabilities $ 376,764 $ 243,984 Offsetting of Derivative Assets and Liabilities As of September 30, 2018 , and December 31, 2017 , all derivative instruments held by the Company were subject to master netting arrangements with various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between it and the counterparty, at the election of both parties, for transactions that settle on the same date and in the same currency. The Company’s agreements also provide that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to not offset these positions in its accompanying balance sheets. The following table provides a reconciliation between the gross assets and liabilities reflected on the accompanying balance sheets and the potential effects of master netting arrangements on the fair value of the Company’s commodity derivative contracts: Derivative Assets Derivative Liabilities As of As of September 30, December 31, 2017 September 30, December 31, 2017 (in thousands) Gross amounts presented in the accompanying balance sheets $ 90,016 $ 104,628 $ (376,764 ) $ (243,984 ) Amounts not offset in the accompanying balance sheets (90,016 ) (100,035 ) 90,016 100,035 Net amounts $ — $ 4,593 $ (286,748 ) $ (143,949 ) The following table summarizes the components of the net derivative (gain) loss line item presented in the accompanying statements of operations: For the Three Months Ended For the Nine Months Ended 2018 2017 2018 2017 (in thousands) Derivative settlement (gain) loss: Oil contracts $ 16,798 $ 2,472 $ 61,976 $ 14,310 Gas contracts 802 (24,088 ) (4,851 ) (63,345 ) NGL contracts 23,118 8,524 44,786 19,633 Total derivative settlement (gain) loss $ 40,718 $ (13,092 ) $ 101,911 $ (29,402 ) Net derivative (gain) loss: Oil contracts $ 110,413 $ 45,874 $ 146,781 $ (41,910 ) Gas contracts 4,309 (6,068 ) 21,299 (56,574 ) NGL contracts 63,304 40,793 81,224 9,120 Total net derivative (gain) loss $ 178,026 $ 80,599 $ 249,304 $ (89,364 ) Credit Related Contingent Features As of September 30, 2018 , and through the filing of this report, all of the Company’s derivative counterparties were members of the Company’s Credit Agreement lender group. Under the Credit Agreement, the Company is required to provide mortgage liens on assets having a value equal to at least 85 percent of the total PV-9 of the Company’s proved oil and gas properties evaluated in the most recent reserve report. Collateral securing indebtedness under the Credit Agreement also secures the Company’s derivative agreement obligations.

Fair Value Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2018
Fair Value Disclosures [Abstract]
Fair Value Disclosures [Text Block]	Note 11 - Fair Value Measurements The Company follows fair value measurement accounting guidance for all assets and liabilities measured at fair value. This guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The fair value hierarchy for grouping these assets and liabilities is based on the significance level of the following inputs: • Level 1 – quoted prices in active markets for identical assets or liabilities • Level 2 – quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable • Level 3 – significant inputs to the valuation model are unobservable 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 September 30, 2018 : Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 90,016 $ — Liabilities: Derivatives (1) $ — $ 376,764 $ — __________________________________________ (1) This represents a financial asset or liability that is measured at fair value on a recurring basis. The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they were classified within the fair value hierarchy as of December 31, 2017 : Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 104,628 $ — Liabilities: Derivatives (1) $ — $ 243,984 $ — ____________________________________________ (1) This represents a financial asset or liability that is measured at fair value on a recurring basis. Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The following is a description of the valuation methodologies used by the Company as well as the general classification of such instruments pursuant to the above fair value hierarchy. Derivatives The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivatives. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration forward commodity price curves, counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The commodity derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity derivative markets are highly active. Please refer to Note 10 - Derivative Financial Instruments and to Note 11 - Fair Value Measurements in the 2017 Form 10-K for more information regarding the Company’s derivative instruments. Proved and Unproved Oil and Gas Properties and Other Property and Equipment Proved oil and gas properties. Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication the carrying costs may not be recoverable. The Company uses Level 3 inputs and the income valuation technique, which converts future cash flows 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. There were no material impairments of proved properties during the three and nine months ended September 30, 2018 , or 2017. Unproved oil and gas properties. Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. Lease acquisition costs that are not individually significant are aggregated by prospect and the portion of such costs estimated to be nonproductive prior to lease expiration are amortized over the appropriate period. The estimate of what could be nonproductive is based on historical trends or other information, including current drilling plans and the Company’s intent to renew leases. To measure the fair value of unproved properties, the Company uses a market approach, which takes into account the following significant assumptions: remaining lease terms, future development plans, risk-weighted potential resource recovery, estimated reserve values, and estimated acreage value based on price(s) received for similar, recent acreage transactions by the Company or other market participants. During the three and nine months ended September 30, 2018 , the Company recorded $9.1 million and $26.6 million , respectively, in abandonment and impairment of unproved properties expense related to lease expirations. There were no material abandonments or impairments of unproved properties expenses for the three and nine months ended September 30, 2017 . Properties held for sale. Properties classified as held for sale, including any corresponding asset retirement obligation liability, are valued using a market approach, based on an estimated net selling price, as evidenced by the most current bid prices received from third parties, if available. If an estimated selling price is not available, the Company utilizes the various valuation techniques discussed above. Any initial write-down and subsequent changes to the fair value less estimated cost to sell is included within the net gain (loss) on divestiture activity line item in the accompanying statements of operations. There were no material assets held for sale that were recorded at fair value as of September 30, 2018 . The Company had $111.7 million of assets classified as held for sale as of December 31, 2017 ; however, none of these properties were recorded at fair value as the carrying value of these assets was below their estimated fair value less selling costs. For the nine months ended September 30, 2017 , the Company recorded a $526.5 million write-down on assets previously held for sale. Please refer to Note 3 - Divestitures, Assets Held for Sale, and Acquisitions above and in the 2017 Form 10-K for more information regarding the Company’s oil and gas properties held for sale . Please refer to Note 11 - Fair Value Measurements in the 2017 Form 10-K for more information regarding the Company’s approach in determining fair value of its properties, including assets held for sale. Long-Term Debt The following table reflects the fair value of the Company’s unsecured senior note obligations measured using Level 1 inputs based on quoted secondary market trading prices. These notes were not presented at fair value on the accompanying balance sheets as of September 30, 2018 , or December 31, 2017 , as they were recorded at carrying value, net of any unamortized discounts and deferred financing costs. Please refer to Note 5 - Long-Term Debt for additional discussion. As of September 30, 2018 As of December 31, 2017 Principal Amount Fair Value Principal Amount Fair Value (in thousands) 6.50% Senior Notes due 2021 $ — $ — $ 344,611 $ 351,682 6.125% Senior Notes due 2022 $ 476,796 $ 491,076 $ 561,796 $ 571,627 6.50% Senior Notes due 2023 $ — $ — $ 394,985 $ 403,434 5.0% Senior Notes due 2024 $ 500,000 $ 491,000 $ 500,000 $ 483,440 5.625% Senior Notes due 2025 $ 500,000 $ 498,125 $ 500,000 $ 494,355 6.75% Senior Notes due 2026 $ 500,000 $ 522,150 $ 500,000 $ 516,350 6.625% Senior Notes due 2027 $ 500,000 $ 517,250 $ — $ — 1.50% Senior Convertible Notes due 2021 $ 172,500 $ 191,044 $ 172,500 $ 168,291

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2018
Accounting Policies [Abstract]
Basis of Presentation, Policy	Basis of Presentation The accompanying unaudited condensed consolidated financial statements include the accounts of SM Energy and have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information, 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 the consolidated financial statements included in SM Energy’s Annual Report on Form 10-K for the year ended December 31, 2017 (the “ 2017 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 September 30, 2018 , and through the filing of this report. Certain prior period amounts have been reclassified to conform to the current presentation on the accompanying unaudited condensed consolidated financial statements.
Recently Issued Accounting Standards, Policy [Policy Text Block]	Recently Issued Accounting Standards Effective December 31, 2017, the Company early adopted, on a retrospective basis, Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”) and FASB ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (“ASU 2016-18”). ASU 2016-15 is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows and ASU 2016-18 is intended to clarify guidance on the classification and presentation of restricted cash and restricted cash equivalents in the statement of cash flows. The Company did not have restricted cash reported within the accompanying balance sheets as of September 30, 2018, or December 31, 2017. Please refer to Note 1 - Summary of Significant Accounting Policies in the 2017 Form 10-K for more information. The accompanying unaudited condensed consolidated statements of cash flows (“accompanying statements of cash flows”) line items that were adjusted as a result of the adoption of ASU 2016-15 and ASU 2016-18 for the nine months ended September 30, 2017 , are summarized as follows: For the Nine Months Ended September 30, 2017 As Reported As Adjusted (in thousands) Cash flows from operating activities: Non-cash (gain) loss on extinguishment of debt, net $ 22 N/A Loss on extinguishment of debt N/A $ 35 Net cash provided by operating activities $ 370,597 $ 370,610 Cash flows from investing activities: Acquisition deposit held in escrow $ 3,000 N/A Net cash provided by (used in) investing activities $ 69,007 $ 66,007 Cash flows from financing activities: Cash paid for extinguishment of debt (1) N/A $ (13 ) Net cash used in financing activities $ (7,561 ) $ (7,574 ) Net change in cash and cash equivalents $ 432,043 N/A Net change in cash, cash equivalents, and restricted cash N/A $ 429,043 Cash and cash equivalents at beginning of period $ 9,372 N/A Cash, cash equivalents, and restricted cash at beginning of period N/A $ 12,372 Cash and cash equivalents at end of period $ 441,415 N/A Cash, cash equivalents, and restricted cash at end of period N/A $ 441,415 ____________________________________________ (1) Included as a component within the cash paid to repurchase Senior Notes, including premium line item on the accompanying statements of cash flows. Effective January 1, 2018, the Company adopted FASB ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) and all related ASUs (“ASU 2014-09”). Under the new guidance, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. The Company adopted ASU 2014-09 using the modified retrospective transition method, which was applied to all active contracts as of the effective date. The adoption of ASU 2014-09 did not result in a change to current or prior period results nor did it result in a material change to the Company’s business processes, systems, or controls. However, upon adopting ASU 2014-09, the Company expanded its disclosures to comply with the expanded disclosure requirements of ASU 2014-09. Please refer to Note 2 - Revenue from Contracts with Customers for additional discussion. Effective January 1, 2018, the Company adopted FASB ASU No. 2017-07, Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (“ASU 2017-07”). ASU 2017-07 requires presentation of service cost in the same line item(s) as other compensation costs arising from services rendered by employees during the period and presentation of the remaining components of net benefit cost in a separate line item, outside of operating items, which the Company adopted with retrospective application. In addition, only the service component of the net benefit cost is eligible for capitalization, which the Company adopted with prospective application. Please refer to Note 1 - Summary of Significant Accounting Policies in the 2017 Form 10-K for more information. The accompanying statements of operations line items that were adjusted as a result of the adoption of ASU 2017-07 for the three and nine months ended September 30, 2017 , are summarized as follows: For the Three Months Ended September 30, 2017 For the Nine Months Ended September 30, 2017 As Reported As Adjusted As Reported As Adjusted (in thousands) Operating expenses: Exploration $ 14,243 $ 14,119 $ 39,293 $ 38,919 General and administrative $ 27,880 $ 27,564 $ 85,564 $ 84,618 Total operating expenses $ 380,971 $ 380,531 $ 856,475 $ 855,155 Income (loss) from operations $ (85,592 ) $ (85,152 ) $ (67,637 ) $ (66,317 ) Other non-operating income, net $ 1,301 $ 861 $ 2,901 $ 1,581 Effective January 1, 2018, the Company early adopted FASB ASU No. 2018-02, Income Statement-Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (“ASU 2018-02”) by applying the changes in the period of adoption. ASU 2018-02 permits entities to reclassify tax effects stranded in accumulated other comprehensive income (loss) to retained earnings as a result of the enactment into law on December 22, 2017, of H.R.1, formally the Tax Cuts and Jobs Act (the “2017 Tax Act”). As a result of adopting ASU 2018-02, the Company reclassified $3.0 million of tax effects stranded in accumulated other comprehensive loss to retained earnings as of January 1, 2018. The Company’s policy for releasing income tax effects within accumulated other comprehensive loss is an incremental, unit-of-account approach. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”) , which requires recognition of right-of-use assets and lease payment liabilities on the balance sheet by lessees for virtually all leases currently classified as operating leases. The scope of ASU 2016-02 does not apply to leases used in the exploration or use of minerals, oil, natural gas, or other similar non-regenerative resources. The Company has established a cross-functional project team and is leveraging external consultants to evaluate the impacts of ASU 2016-02, which includes an analysis of non-cancelable leases, drilling rig contracts, certain midstream agreements, and other existing arrangements that may contain a lease component. The Company has substantially completed the process of reviewing and determining the contracts to which the new guidance applies. Further, the Company is also evaluating policies, internal controls, and processes that will be necessary to support the additional accounting and disclosure requirements. The Company will continue to monitor guidance issued by the FASB to clarify ASU 2016-02 and certain industry implementation issues. The Company is in the final stages of implementing a lease administration system that will support the on-going maintenance and accounting for leases after adoption. Policy elections allowed under ASU 2016-02 that the Company anticipates making as part of its adoption include (a) not recognizing lease assets or liabilities when lease terms are less than twelve months, and (b) for agreements that contain both lease and non-lease components, combining these components together and accounting for them as a single lease. Other policy elections allowed for under ASU 2016-02 are still being evaluated. The Company will adopt ASU 2016-02 on January 1, 2019, using the modified retrospective approach. Adoption of this guidance is expected to result in an increase in right-of-use assets and related liabilities on the Company’s consolidated balance sheets; however, the full impact to the Company’s financial statements and related disclosures is still being evaluated. In January 2018, the FASB issued ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842 (“ASU 2018-01”), which provides an optional transitional practical expedient that allows entities to exclude from evaluation land easements that existed or expired before adoption of ASU 2016-02. Companies that elect this practical expedient will need to evaluate new or modified land easements after adopting ASU 2016-02. If this practical expedient is not elected, companies will need to evaluate all existing or expired land easements as part of the overall adoption of ASU 2016-02. The Company expects to elect to use this practical expedient as outlined in ASU 2018-01 and will adopt ASU 2018-01 at the same time it adopts ASU 2016-02. In July 2018, the FASB issued ASU No. 2018-11, Leases (Topic 842): Targeted Improvements (“ASU 2018-11”). ASU 2018-11 provides an additional transition method for adopting ASU 2016-02, as well as provides lessors with a practical expedient when applying ASU 2016-02 to certain leases. The Company anticipates making a policy election in connection with adopting ASU 2018-11, which will eliminate the need for adjusting prior period comparable financial statements prepared under current lease accounting guidance. The Company will adopt ASU 2018-11 at the same time it adopts ASU 2016-02. In August 2018, the FASB issued ASU No. 2018-14, Compensation-Retirement Benefits-Defined Benefit Plans-General (Subtopic 715-20): Disclosure Framework-Changes to the Disclosure Requirements for Defined Benefit Plans (“ASU 2018-14”). ASU 2018-14 provides updated disclosure requirements related to retirement benefits and defined pension plans with the purpose of improving the effectiveness of disclosures with regard to such topics. The guidance is to be applied using a retrospective method and is effective for fiscal years ending after December 15, 2020, with early adoption permitted. The Company expects to early adopt ASU 2018-14 on December 31, 2018. The Company is evaluating the impact of this guidance on its consolidated financial statements, but does not expect the impact to be material. In August 2018, the FASB issued ASU No. 2018-15, Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”). ASU 2018-15 aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The Company expects to adopt ASU 2018-15 on January 1, 2020, with prospective application. The Company is evaluating the impact of ASU 2018-15 on its consolidated financial statements. Other than as disclosed above or in the 2017 Form 10-K, there are no other ASUs applicable to the Company that would have a material effect on the Company’s consolidated financial statements and related disclosures that have been issued but not yet adopted by the Company as of September 30, 2018 , and through the filing of this report.
Derivatives, Policy	Derivatives The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivatives. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration forward commodity price curves, counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The commodity derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity derivative markets are highly active. Please refer to Note 10 - Derivative Financial Instruments and to Note 11 - Fair Value Measurements in the 2017 Form 10-K for more information regarding the Company’s derivative instruments.
Proved and Unproved Oil and Gas Properties and Other Property and Equipment, Policy	Proved and Unproved Oil and Gas Properties and Other Property and Equipment Proved oil and gas properties. Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication the carrying costs may not be recoverable. The Company uses Level 3 inputs and the income valuation technique, which converts future cash flows 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. There were no material impairments of proved properties during the three and nine months ended September 30, 2018 , or 2017. Unproved oil and gas properties. Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. Lease acquisition costs that are not individually significant are aggregated by prospect and the portion of such costs estimated to be nonproductive prior to lease expiration are amortized over the appropriate period. The estimate of what could be nonproductive is based on historical trends or other information, including current drilling plans and the Company’s intent to renew leases. To measure the fair value of unproved properties, the Company uses a market approach, which takes into account the following significant assumptions: remaining lease terms, future development plans, risk-weighted potential resource recovery, estimated reserve values, and estimated acreage value based on price(s) received for similar, recent acreage transactions by the Company or other market participants. During the three and nine months ended September 30, 2018 , the Company recorded $9.1 million and $26.6 million , respectively, in abandonment and impairment of unproved properties expense related to lease expirations. There were no material abandonments or impairments of unproved properties expenses for the three and nine months ended September 30, 2017 . Properties held for sale. Properties classified as held for sale, including any corresponding asset retirement obligation liability, are valued using a market approach, based on an estimated net selling price, as evidenced by the most current bid prices received from third parties, if available. If an estimated selling price is not available, the Company utilizes the various valuation techniques discussed above. Any initial write-down and subsequent changes to the fair value less estimated cost to sell is included within the net gain (loss) on divestiture activity line item in the accompanying statements of operations. There were no material assets held for sale that were recorded at fair value as of September 30, 2018 . The Company had $111.7 million of assets classified as held for sale as of December 31, 2017 ; however, none of these properties were recorded at fair value as the carrying value of these assets was below their estimated fair value less selling costs. For the nine months ended September 30, 2017 , the Company recorded a $526.5 million write-down on assets previously held for sale. Please refer to Note 3 - Divestitures, Assets Held for Sale, and Acquisitions above and in the 2017 Form 10-K for more information regarding the Company’s oil and gas properties held for sale . Please refer to Note 11 - Fair Value Measurements in the 2017 Form 10-K for more information regarding the Company’s approach in determining fair value of its properties, including assets held for sale.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	9 Months Ended
	Sep. 30, 2018
Accounting Standards Update 2016-15, 2016-18 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Schedule of New Accounting Pronouncements and Changes in Accounting Principles [Table Text Block]	The accompanying unaudited condensed consolidated statements of cash flows (“accompanying statements of cash flows”) line items that were adjusted as a result of the adoption of ASU 2016-15 and ASU 2016-18 for the nine months ended September 30, 2017 , are summarized as follows: For the Nine Months Ended September 30, 2017 As Reported As Adjusted (in thousands) Cash flows from operating activities: Non-cash (gain) loss on extinguishment of debt, net $ 22 N/A Loss on extinguishment of debt N/A $ 35 Net cash provided by operating activities $ 370,597 $ 370,610 Cash flows from investing activities: Acquisition deposit held in escrow $ 3,000 N/A Net cash provided by (used in) investing activities $ 69,007 $ 66,007 Cash flows from financing activities: Cash paid for extinguishment of debt (1) N/A $ (13 ) Net cash used in financing activities $ (7,561 ) $ (7,574 ) Net change in cash and cash equivalents $ 432,043 N/A Net change in cash, cash equivalents, and restricted cash N/A $ 429,043 Cash and cash equivalents at beginning of period $ 9,372 N/A Cash, cash equivalents, and restricted cash at beginning of period N/A $ 12,372 Cash and cash equivalents at end of period $ 441,415 N/A Cash, cash equivalents, and restricted cash at end of period N/A $ 441,415 ____________________________________________ (1) Included as a component within the cash paid to repurchase Senior Notes, including premium line item on the accompanying statements of cash flows.
Accounting Standards Update 2017-07 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Schedule of New Accounting Pronouncements and Changes in Accounting Principles [Table Text Block]	The accompanying statements of operations line items that were adjusted as a result of the adoption of ASU 2017-07 for the three and nine months ended September 30, 2017 , are summarized as follows: For the Three Months Ended September 30, 2017 For the Nine Months Ended September 30, 2017 As Reported As Adjusted As Reported As Adjusted (in thousands) Operating expenses: Exploration $ 14,243 $ 14,119 $ 39,293 $ 38,919 General and administrative $ 27,880 $ 27,564 $ 85,564 $ 84,618 Total operating expenses $ 380,971 $ 380,531 $ 856,475 $ 855,155 Income (loss) from operations $ (85,592 ) $ (85,152 ) $ (67,637 ) $ (66,317 ) Other non-operating income, net $ 1,301 $ 861 $ 2,901 $ 1,581

Revenue from Contracts with C_2

Revenue from Contracts with Customers (Tables)	9 Months Ended
	Sep. 30, 2018
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue	The tables below present the disaggregation of oil, gas, and NGL production revenue by product type for each of the Company’s operating regions for the three and nine months ended September 30, 2018 , and 2017: Permian South Texas & Gulf Coast Rocky Mountain Total Three Months Ended September 30, Three Months Ended September 30, Three Months Ended September 30, Three Months Ended September 30, 2018 2017 2018 2017 2018 2017 2018 2017 (in thousands) Oil, gas, and NGL production revenue: Oil production revenue $ 270,086 $ 107,248 $ 17,436 $ 13,726 $ — $ 33,229 $ 287,522 $ 154,203 Gas production revenue 40,364 16,034 56,446 69,069 — 1,162 96,810 86,265 NGL production revenue 563 151 73,487 53,023 — 817 74,050 53,991 Total $ 311,013 $ 123,433 $ 147,369 $ 135,818 $ — $ 35,208 $ 458,382 $ 294,459 Relative percentage 68 % 42 % 32 % 46 % — % 12 % 100 % 100 % ____________________________________________ Note: Amounts may not calculate due to rounding. Permian South Texas & Gulf Coast Rocky Mountain Total Nine Months Ended September 30, Nine Months Ended September 30, Nine Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 2018 2017 2018 2017 (in thousands) Oil, gas, and NGL production revenue: Oil production revenue $ 703,516 $ 267,301 $ 56,365 $ 65,662 $ 54,851 $ 117,738 $ 814,732 $ 450,701 Gas production revenue 96,974 40,280 161,414 245,030 1,595 3,846 259,983 289,156 NGL production revenue 816 405 167,505 169,938 790 2,396 169,111 172,739 Total $ 801,306 $ 307,986 $ 385,284 $ 480,630 $ 57,236 $ 123,980 $ 1,243,826 $ 912,596 Relative percentage 64 % 34 % 31 % 53 % 5 % 13 % 100 % 100 % ____________________________________________ Note: Amounts may not calculate due to rounding.

Divestitures, Assets Held for_2

Divestitures, Assets Held for Sale, and Acquisitions (Tables)	9 Months Ended
	Sep. 30, 2018
Divestitures, Assets Held for Sale, and Acquisitions [Abstract]
Disposal Groups, Including Discontinued Operations [Table Text Block]	The following table presents income (loss) before income taxes from the Divide County, North Dakota assets sold for the three and nine months ended September 30, 2018 , and 2017. The Divide County Divestiture was considered a disposal of a significant asset group. For the Three Months Ended September 30, For the Nine Months Ended September 30, 2018 2017 2018 2017 (in thousands) Income (loss) before income taxes (1) $ — $ 7,593 $ (28,975 ) $ (478,572 ) ____________________________________________ (1) Income (loss) before income taxes reflects oil, gas, and NGL production revenue, less oil, gas, and NGL production expense, depletion, depreciation, amortization, and asset retirement obligation liability accretion expense, impairment expense, and net loss on divestiture activity.

Income Taxes (Tables)

Income Taxes (Tables)	9 Months Ended
	Sep. 30, 2018
Income Tax Disclosure [Abstract]
Schedule of provision for income taxes	The provision for income taxes for the three and nine months ended September 30, 2018 , and 2017 , consisted of the following: For the Three Months Ended For the Nine Months Ended 2018 2017 2018 2017 (in thousands) Current portion of income tax (expense) benefit: Federal $ — $ 2,832 $ — $ — State (85 ) (230 ) (670 ) (1,633 ) Deferred portion of income tax (expense) benefit 36,833 36,668 (60,672 ) 67,458 Income tax (expense) benefit $ 36,748 $ 39,270 $ (61,342 ) $ 65,825 Effective tax rate 21.3 % 30.6 % 23.6 % 32.8 %

Long-Term Debt (Tables)

Long-Term Debt (Tables)	9 Months Ended
	Sep. 30, 2018
Debt Disclosure [Abstract]
Schedule of Borrowing Base Utilization [Table Text Block]	The borrowing base utilization grid under the Credit Agreement is as follows: Borrowing Base Utilization Percentage <25% ≥25% <50% ≥50% <75% ≥75% <90% ≥90% Eurodollar Loans 1.500 % 1.750 % 2.000 % 2.250 % 2.500 % ABR Loans or Swingline Loans 0.500 % 0.750 % 1.000 % 1.250 % 1.500 % Commitment Fee Rate 0.375 % 0.375 % 0.500 % 0.500 % 0.500 %
Schedule of Credit Agreement Facilities [Table Text Block]	The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Credit Agreement as of October 24, 2018 , and September 30, 2018 , and under the Fifth Amended and Restated Credit Agreement as of December 31, 2017 : As of October 24, 2018 As of September 30, 2018 As of December 31, 2017 (in thousands) Credit facility balance (1) $ — $ — $ — Letters of credit (2) 200 200 200 Available borrowing capacity 999,800 999,800 924,800 Total aggregate lender commitment amount $ 1,000,000 $ 1,000,000 $ 925,000 ____________________________________________ (1) Unamortized deferred financing costs attributable to the credit facility are presented as a component of other noncurrent assets on the accompanying balance sheets and totaled $6.7 million and $3.1 million as of September 30, 2018 , and December 31, 2017 , respectively. These costs are being amortized over the term of the credit facility on a straight-line basis. (2) Letters of credit outstanding reduce the amount available under the credit facility on a dollar-for-dollar basis.
Schedule of Senior Notes [Table Text Block]	The Senior Notes, net of unamortized deferred financing costs line item on the accompanying balance sheets as of September 30, 2018 , and December 31, 2017 , consisted of the following: As of September 30, 2018 As of December 31, 2017 Principal Amount Unamortized Deferred Financing Costs Principal Amount, Net of Unamortized Deferred Financing Costs Principal Amount Unamortized Deferred Financing Costs Principal Amount, Net of Unamortized Deferred Financing Costs (in thousands) 6.50% Senior Notes due 2021 $ — $ — $ — $ 344,611 $ 2,656 $ 341,955 6.125% Senior Notes due 2022 476,796 4,171 472,625 561,796 5,800 555,996 6.50% Senior Notes due 2023 — — — 394,985 3,707 391,278 5.0% Senior Notes due 2024 500,000 4,919 495,081 500,000 5,610 494,390 5.625% Senior Notes due 2025 500,000 6,035 493,965 500,000 6,714 493,286 6.75% Senior Notes due 2026 500,000 6,615 493,385 500,000 7,242 492,758 6.625% Senior Notes due 2027 500,000 7,766 492,234 — — — Total $ 2,476,796 $ 29,506 $ 2,447,290 $ 2,801,392 $ 31,729 $ 2,769,663
Schedule of Senior Convertible Notes [Table Text Block]	The Senior Convertible Notes, net of unamortized discount and deferred financing costs line on the accompanying balance sheets as of September 30, 2018 , and December 31, 2017 , consisted of the following: As of September 30, 2018 As of December 31, 2017 (in thousands) Principal amount of Senior Convertible Notes $ 172,500 $ 172,500 Unamortized debt discount (24,316 ) (30,183 ) Unamortized deferred financing costs (2,522 ) (3,210 ) Senior Convertible Notes, net of unamortized discount and deferred financing costs $ 145,662 $ 139,107

Compensation Plans Compensation

Compensation Plans Compensation Plans (Tables)	9 Months Ended
	Sep. 30, 2018
Compensation Related Costs [Abstract]
Share-based Compensation, Performance Shares Award Nonvested Activity [Table Text Block]	A summary of the status and activity of non-vested PSUs for the nine months ended September 30, 2018 , is presented in the following table: PSUs (1) Weighted-Average Grant-Date Fair Value Non-vested at beginning of year 1,533,491 $ 22.97 Granted 572,924 $ 24.45 Vested (233,102) $ 44.25 Forfeited (97,122) $ 22.89 Non-vested at end of quarter 1,776,191 $ 20.66 ____________________________________________ (1) The number of awards assumes a multiplier of one . The final number of shares of common stock issued may vary depending on the three -year performance multiplier which ranges from zero to two .
Schedule of Share-based Compensation, Restricted Stock Units Award Activity [Table Text Block]	A summary of the status and activity of non-vested RSUs granted to employees for the nine months ended September 30, 2018 , is presented in the following table: RSUs Weighted-Average Grant-Date Fair Value Non-vested at beginning of year 1,244,262 $ 20.25 Granted 583,552 $ 25.77 Vested (407,529) $ 24.30 Forfeited (112,141) $ 17.93 Non-vested at end of quarter 1,308,144 $ 21.46

Pension Benefits (Tables)

Pension Benefits (Tables)	9 Months Ended
	Sep. 30, 2018
Defined Benefit Plan [Abstract]
Components of the net periodic benefit cost for the Pension Plans [Table Text Block]	The following table presents the components of the net periodic benefit cost for the Pension Plans: For the Three Months Ended For the Nine Months Ended 2018 2017 2018 2017 (in thousands) Service cost $ 1,683 $ 1,660 $ 5,048 $ 4,979 Interest cost 657 673 1,967 2,017 Expected return on plan assets that reduces periodic pension benefit cost (466 ) (561 ) (1,397 ) (1,683 ) Amortization of prior service cost 4 4 13 13 Amortization of net actuarial loss 331 324 995 973 Net periodic benefit cost $ 2,209 $ 2,100 $ 6,626 $ 6,299

Earnings per Share (Tables)

Earnings per Share (Tables)	9 Months Ended
	Sep. 30, 2018
Earnings Per Share [Abstract]
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share	The following table presents the weighted-average anti-dilutive securities for the periods presented: For the Three Months Ended For the Nine Months Ended 2018 2017 2018 2017 (in thousands) Anti-dilutive 2,433 — — 78
Schedule of calculations of basic and diluted net loss per common share	The following table sets forth the calculations of basic and diluted net income (loss) per common share: For the Three Months Ended For the Nine Months Ended 2018 2017 2018 2017 (in thousands, except per share data) Net income (loss) $ (135,923 ) $ (89,112 ) $ 198,675 $ (134,585 ) Basic weighted-average common shares outstanding 112,107 111,575 111,836 111,366 Dilutive effect of non-vested RSUs and contingent PSUs — — 1,764 — Dilutive effect of Senior Convertible Notes — — — — Diluted weighted-average common shares outstanding 112,107 111,575 113,600 111,366 Basic net income (loss) per common share $ (1.21 ) $ (0.80 ) $ 1.78 $ (1.21 ) Diluted net income (loss) per common share $ (1.21 ) $ (0.80 ) $ 1.75 $ (1.21 )

Derivative Financial Instrume_2

Derivative Financial Instruments (Tables)	9 Months Ended
	Sep. 30, 2018
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Schedule of notional amounts of outstanding derivative positions	As of September 30, 2018 , the Company had commodity derivative contracts outstanding as summarized in the tables below: Oil Swaps Contract Period NYMEX WTI Volumes Weighted-Average Contract Price (MBbl) (per Bbl) Fourth quarter 2018 1,894 $ 49.87 2019 3,733 $ 59.80 2020 2,491 $ 65.68 Total 8,118 Oil Collars Contract Period NYMEX WTI Volumes Weighted- Average Floor Price Weighted- Average Ceiling Price (MBbl) (per Bbl) (per Bbl) Fourth quarter 2018 2,222 $ 50.00 $ 58.44 2019 10,055 $ 50.59 $ 63.62 2020 1,165 $ 55.00 $ 66.47 Total 13,442 Oil Basis Swaps Contract Period WTI Midland-NYMEX WTI Volumes Weighted-Average Contract Price (1) NYMEX WTI-ICE Brent Volumes Weighted-Average (2) (MBbl) (per Bbl) (MBbl) (per Bbl) Fourth quarter 2018 3,327 $ (1.08 ) — $ — 2019 11,217 $ (3.36 ) — $ — 2020 10,960 $ (1.05 ) 1,840 $ (8.01 ) 2021 — $ — 3,650 $ (7.86 ) 2022 — $ — 3,650 $ (7.78 ) Total 25,504 9,140 ____________________________________________ (1) Represents the price differential between WTI Midland (Midland, Texas) and NYMEX WTI (Cushing, Oklahoma). (2) Represents the price differential between NYMEX WTI (Cushing, Oklahoma) and ICE Brent (North Sea). Gas Swaps Contract Period Sold IF HSC Volumes Weighted-Average Contract Price Purchased IF HSC Volumes Weighted-Average Contract Price Net IF HSC Volumes Weighted-Average Contract Price (BBtu) (per MMBtu) (BBtu) (per MMBtu) (BBtu) (per MMBtu) Fourth quarter 2018 28,204 $ 3.27 (7,210 ) $ 4.27 20,994 $ 2.92 2019 50,021 $ 3.58 (24,415 ) $ 4.34 25,606 $ 2.85 2020 2,942 $ 2.82 — $ — 2,942 $ 2.82 Total 81,167 (31,625 ) 49,542 Gas Collars Contract Period IF HSC Volumes Weighted- Average Floor Price Weighted- Average Ceiling Price (BBtu) (per MMBtu) (per MMBtu) 2019 14,242 $ 2.50 $ 2.83 NGL Swaps OPIS Ethane Purity Mont Belvieu OPIS Propane Mont Belvieu Non-TET OPIS Normal Butane Mont Belvieu Non-TET OPIS Isobutane Mont Belvieu Non-TET OPIS Natural Gasoline Mont Belvieu Non-TET Contract Period Volumes Weighted-Average Contract Price Volumes Weighted-Average Volumes Weighted-Average Volumes Weighted-Average Volumes Weighted-Average (MBbl) (per Bbl) (MBbl) (per Bbl) (MBbl) (per Bbl) (MBbl) (per Bbl) (MBbl) (per Bbl) Fourth quarter 2018 1,146 $ 11.18 671 $ 24.39 102 $ 35.70 76 $ 35.07 208 $ 50.99 2019 3,533 $ 12.31 1,980 $ 28.89 154 $ 35.64 117 $ 35.70 197 $ 50.93 2020 539 $ 11.13 — $ — — $ — — $ — — $ — Total 5,218 2,651 256 193 405
Schedule of fair value of derivatives in accompanying balance sheets	The following table details the fair value of commodity derivative contracts recorded in the accompanying balance sheets, by category: As of September 30, 2018 As of December 31, 2017 (in thousands) Derivative assets: Current assets $ 81,163 $ 64,266 Noncurrent assets 8,853 40,362 Total derivative assets $ 90,016 $ 104,628 Derivative liabilities: Current liabilities $ 304,159 $ 172,582 Noncurrent liabilities 72,605 71,402 Total derivative liabilities $ 376,764 $ 243,984
Schedule of the potential effects of master netting arrangements	The following table provides a reconciliation between the gross assets and liabilities reflected on the accompanying balance sheets and the potential effects of master netting arrangements on the fair value of the Company’s commodity derivative contracts: Derivative Assets Derivative Liabilities As of As of September 30, December 31, 2017 September 30, December 31, 2017 (in thousands) Gross amounts presented in the accompanying balance sheets $ 90,016 $ 104,628 $ (376,764 ) $ (243,984 ) Amounts not offset in the accompanying balance sheets (90,016 ) (100,035 ) 90,016 100,035 Net amounts $ — $ 4,593 $ (286,748 ) $ (143,949 )
Schedule of derivative (gain) loss	The following table summarizes the components of the net derivative (gain) loss line item presented in the accompanying statements of operations: For the Three Months Ended For the Nine Months Ended 2018 2017 2018 2017 (in thousands) Derivative settlement (gain) loss: Oil contracts $ 16,798 $ 2,472 $ 61,976 $ 14,310 Gas contracts 802 (24,088 ) (4,851 ) (63,345 ) NGL contracts 23,118 8,524 44,786 19,633 Total derivative settlement (gain) loss $ 40,718 $ (13,092 ) $ 101,911 $ (29,402 ) Net derivative (gain) loss: Oil contracts $ 110,413 $ 45,874 $ 146,781 $ (41,910 ) Gas contracts 4,309 (6,068 ) 21,299 (56,574 ) NGL contracts 63,304 40,793 81,224 9,120 Total net derivative (gain) loss $ 178,026 $ 80,599 $ 249,304 $ (89,364 )

Fair Value Measurements Fair Va

Fair Value Measurements Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2018
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they are classified within the fair value hierarchy as of September 30, 2018 : Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 90,016 $ — Liabilities: Derivatives (1) $ — $ 376,764 $ — __________________________________________ (1) This represents a financial asset or liability that is measured at fair value on a recurring basis. The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they were classified within the fair value hierarchy as of December 31, 2017 : Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 104,628 $ — Liabilities: Derivatives (1) $ — $ 243,984 $ — ____________________________________________ (1) This represents a financial asset or liability that is measured at fair value on a recurring basis.
Long Term Debt Fair Value [Table Text Block]	The following table reflects the fair value of the Company’s unsecured senior note obligations measured using Level 1 inputs based on quoted secondary market trading prices. These notes were not presented at fair value on the accompanying balance sheets as of September 30, 2018 , or December 31, 2017 , as they were recorded at carrying value, net of any unamortized discounts and deferred financing costs. Please refer to Note 5 - Long-Term Debt for additional discussion. As of September 30, 2018 As of December 31, 2017 Principal Amount Fair Value Principal Amount Fair Value (in thousands) 6.50% Senior Notes due 2021 $ — $ — $ 344,611 $ 351,682 6.125% Senior Notes due 2022 $ 476,796 $ 491,076 $ 561,796 $ 571,627 6.50% Senior Notes due 2023 $ — $ — $ 394,985 $ 403,434 5.0% Senior Notes due 2024 $ 500,000 $ 491,000 $ 500,000 $ 483,440 5.625% Senior Notes due 2025 $ 500,000 $ 498,125 $ 500,000 $ 494,355 6.75% Senior Notes due 2026 $ 500,000 $ 522,150 $ 500,000 $ 516,350 6.625% Senior Notes due 2027 $ 500,000 $ 517,250 $ — $ — 1.50% Senior Convertible Notes due 2021 $ 172,500 $ 191,044 $ 172,500 $ 168,291

Summary of Significant Accoun_4

Summary of Significant Accounting Policies (Details) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Statement of Cash Flows [Abstract]
Non-cash (gain) loss on extinguishment of debt, net				$ 6,334	$ 22
Loss on extinguishment of debt		$ 26,722	$ 0	26,722	35
Net cash provided by operating activities				541,177	370,610
Net cash provided by (used in) investing activities				(313,960)	66,007
Cash paid for extinguishment of debt	[1]				13
Net cash used in financing activities				(364,354)	(7,574)
Net change in cash, cash equivalents, and restricted cash					429,043
Cash, cash equivalents, and restricted cash at beginning of period	[2]			313,943	12,372
Cash, cash equivalents, and restricted cash at end of period	[2]	176,806	441,415	176,806	441,415
Income Statement [Abstract]
Exploration		13,061	14,119	40,844	38,919
General and administrative		29,464	27,564	86,066	84,618
Total operating expenses		568,013	380,531	1,266,308	855,155
Income (loss) from operations		(108,644)	(85,152)	406,572	(66,317)
Other non-operating income, net		806	861	3,017	1,581
Prior Period Adjustments Restatement [Line Items]
Depletion, depreciation, amortization, and asset retirement obligation liability accretion		201,105	134,599	483,343	425,643
Net income (loss)		135,923	89,112	(198,675)	134,585
Previously Reported [Member] | Accounting Standards Update 2016-15, 2016-18 [Member]
Statement of Cash Flows [Abstract]
Non-cash (gain) loss on extinguishment of debt, net					22
Net cash provided by operating activities					370,597
Acquisition deposit held in escrow					3,000
Net cash provided by (used in) investing activities					69,007
Net cash used in financing activities					(7,561)
Net change in cash and cash equivalents					432,043
Cash and cash equivalents at beginning of period					9,372
Cash and cash equivalents at end of period			441,415		441,415
Previously Reported [Member] | Accounting Standards Update 2017-07 [Member]
Income Statement [Abstract]
Exploration			14,243		39,293
General and administrative			27,880		85,564
Total operating expenses			380,971		856,475
Income (loss) from operations			(85,592)		(67,637)
Other non-operating income, net			$ 1,301		$ 2,901
Correction of Immaterial Errors Before Tax [Member]
Prior Period Adjustments Restatement [Line Items]
Depletion, depreciation, amortization, and asset retirement obligation liability accretion		11,800		11,800
Understatement of Net Income After Tax [Member]
Prior Period Adjustments Restatement [Line Items]
Net income (loss)				$ 9,000
Overstatement of Net Loss After Tax [Member]
Prior Period Adjustments Restatement [Line Items]
Net income (loss)		$ 9,000
[1]	(1) Included as a component within the cash paid to repurchase Senior Notes, including premium line item on the accompanying statements of cash flows.
[2]	(1) Refer to Note 1 - Summary of Significant Accounting Policies for a reconciliation of cash, cash equivalents, and restricted cash reported to the amounts reported within the accompanying unaudited condensed consolidated balance sheets (“accompanying balance sheets”).

Summary of Significant Accoun_5

Summary of Significant Accounting Policies Reconciliation (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Cash and Cash Equivalents [Abstract]
Restricted cash	$ 0	$ 0

Revenue from Contracts with C_3

Revenue from Contracts with Customers Disaggregation of Revenue (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	$ 458,382	$ 294,459	$ 1,243,826	$ 912,596
Revenue, Remaining Performance Obligation, Amount	0		0
Permian
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	311,013	123,433	801,306	307,986
South Texas & Gulf Coast
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	147,369	135,818	385,284	480,630
Rocky Mountain
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	$ 0	$ 35,208	$ 57,236	$ 123,980
Sales Revenue, Net | Geographic Concentration Risk
Segment Reporting Information [Line Items]
Relative percentage	100.00%	100.00%	100.00%	100.00%
Sales Revenue, Net | Geographic Concentration Risk | Permian
Segment Reporting Information [Line Items]
Relative percentage	68.00%	42.00%	64.00%	34.00%
Sales Revenue, Net | Geographic Concentration Risk | South Texas & Gulf Coast
Segment Reporting Information [Line Items]
Relative percentage	32.00%	46.00%	31.00%	53.00%
Sales Revenue, Net | Geographic Concentration Risk | Rocky Mountain
Segment Reporting Information [Line Items]
Relative percentage	0.00%	12.00%	5.00%	13.00%
Oil Revenue [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	$ 287,522	$ 154,203	$ 814,732	$ 450,701
Oil Revenue [Member] | Permian
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	270,086	107,248	703,516	267,301
Oil Revenue [Member] | South Texas & Gulf Coast
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	17,436	13,726	56,365	65,662
Oil Revenue [Member] | Rocky Mountain
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	33,229	54,851	117,738
Natural Gas Revenue [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	96,810	86,265	259,983	289,156
Natural Gas Revenue [Member] | Permian
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	40,364	16,034	96,974	40,280
Natural Gas Revenue [Member] | South Texas & Gulf Coast
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	56,446	69,069	161,414	245,030
Natural Gas Revenue [Member] | Rocky Mountain
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	1,162	1,595	3,846
Oil and Condensate Revenue [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	74,050	53,991	169,111	172,739
Oil and Condensate Revenue [Member] | Permian
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	563	151	816	405
Oil and Condensate Revenue [Member] | South Texas & Gulf Coast
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	73,487	53,023	167,505	169,938
Oil and Condensate Revenue [Member] | Rocky Mountain
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	$ 0	$ 817	$ 790	$ 2,396

Revenue from Contracts with C_4

Revenue from Contracts with Customers Accounts Receivable from Customers (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable	$ 179,347	$ 160,154
Accrued Income Receivable [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable	$ 120,300	$ 96,600

Divestitures, Assets Held for_3

Divestitures, Assets Held for Sale, and Acquisitions Divestitures and Assets Held for Sale (Details) $ in Thousands		Mar. 26, 2018USD ($)a	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)	Dec. 31, 2017USD ($)a
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net divestiture proceeds					$ 743,199	$ 778,365
Net gain on divestiture activity			$ 786	$ (1,895)	425,656	(131,565)
Properties held for sale, net			5,040		5,040		$ 111,700
Net Acres Held For Sale | a							112,000
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | PRB Divestiture 2018 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net acreage divested | a		112,000
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Divide County Divestiture 2018 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Income (loss) before income taxes	[1]		0	$ 7,593	(28,975)	(478,572)
Disposal Group, Held-for-sale, Not Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Properties held for sale, net			5,040		5,040		$ 111,700
Disposal Group, Held-for-sale, Not Discontinued Operations [Member] | Divide County Disposal Group [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Assets held for sale, loss (gain) on write-down						526,500
Net Divestiture Proceeds Received at Closing [Member] | Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | PRB Divestiture 2018 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net divestiture proceeds		$ 490,800
Net Divestiture Proceeds Received at Closing [Member] | Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Divide County Divestiture and Halff East Divestiture 2018 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net divestiture proceeds			$ 250,800
Estimated Net Gain [Member] | Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | PRB Divestiture 2018 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net gain on divestiture activity					410,600
Estimated Net Gain [Member] | Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Divide County Divestiture and Halff East Divestiture 2018 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net gain on divestiture activity					$ 15,400
Net Divestiture Proceeds After Final Purchase Price Adjustments [Member] | Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Non-Operated Eagle Ford Divestiture 2017 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net divestiture proceeds							744,100
Net Divestiture Proceeds After Final Purchase Price Adjustments [Member] | Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Other Divestitures 2017 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net divestiture proceeds						$ 31,000
Final Net Gain [Member] | Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Non-Operated Eagle Ford Divestiture 2017 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net gain on divestiture activity							$ 396,800
[1]	(1) Income (loss) before income taxes reflects oil, gas, and NGL production revenue, less oil, gas, and NGL production expense, depletion, depreciation, amortization, and asset retirement obligation liability accretion expense, impairment expense, and net loss on divestiture activity.

Divestitures, Assets Held for_4

Divestitures, Assets Held for Sale, and Acquisitions Acquisitions (Details) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018USD ($)a	Jun. 30, 2018USD ($)a	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)a
Business Acquisition [Line Items]
Noncash or Part Noncash Acquisition, Net Nonmonetary Assets Acquired (Liabilities Assumed)			$ 95,121
Payments to Acquire Oil and Gas Property and Equipment			$ 24,571	$ 87,389
Howard and Martin Counties Trades 2018 [Member]
Business Acquisition [Line Items]
Non-monetary Trade, Acreage Acquired | a	2,658
Non-monetary Trade, Acreage Exchanged | a	2,654
Noncash or Part Noncash Acquisition, Net Nonmonetary Assets Acquired (Liabilities Assumed)	$ 95,100
Gain or loss recognized on trade	$ 0
Howard and Martin Counties Trades 2017 [Member]
Business Acquisition [Line Items]
Non-monetary Trade, Acreage Acquired | a				7,425
Non-monetary Trade, Acreage Exchanged | a				6,725
Noncash or Part Noncash Acquisition, Net Nonmonetary Assets Acquired (Liabilities Assumed)				$ 283,700
Gain or loss recognized on trade				$ 0
Other Martin County Acquisition 2018 [Member]
Business Acquisition [Line Items]
Net Acres Acquired | a		720
Payments to Acquire Oil and Gas Property and Equipment		$ 24,600
Other Howard and Martin Counties Acquisitions 2017 [Member]
Business Acquisition [Line Items]
Net Acres Acquired | a				3,400
Payments to Acquire Oil and Gas Property and Equipment				$ 72,200

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Proceeds from Income Tax Refunds			$ 5,900
Components of the provision for income taxes
Federal	$ 0	$ 2,832	0	$ 0
State	(85)	(230)	(670)	(1,633)
Deferred portion of income tax (expense) benefit	36,833	36,668	(60,672)	67,458
Income tax (expense) benefit	$ 36,748	$ 39,270	$ (61,342)	$ 65,825
Effective tax rate	21.30%	30.60%	23.60%	32.80%
Tax Year 2017 [Member]
Federal enacted statutory income tax rate, percent			35.00%
Future tax years [Member]
Federal enacted statutory income tax rate, percent			21.00%

Long-Term Debt Revolving Credit

Long-Term Debt Revolving Credit Facility (Details) $ in Thousands		9 Months Ended
		Sep. 30, 2018USD ($)	Oct. 24, 2018USD ($)	Dec. 31, 2017USD ($)
Line of Credit Facility [Line Items]
Credit facility balance		$ 0		$ 0
Line of Credit [Member] | Borrowing Base Utilization Of Less Than 25 Percent [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage		0.375%
Line of Credit [Member] | Borrowing Base Utilization Of Less Than 25 Percent [Member] | Eurodollar [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.50%
Line of Credit [Member] | Borrowing Base Utilization Of Less Than 25 Percent [Member] | Prime Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		0.50%
Line of Credit [Member] | Borrowing Base Utilization Of 25 Percent Or More But Less Than 50 Percent [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage		0.375%
Line of Credit [Member] | Borrowing Base Utilization Of 25 Percent Or More But Less Than 50 Percent [Member] | Eurodollar [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.75%
Line of Credit [Member] | Borrowing Base Utilization Of 25 Percent Or More But Less Than 50 Percent [Member] | Prime Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		0.75%
Line of Credit [Member] | Borrowing Base Utilization Of 50 Percent Or More But Less Than 75 Percent [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage		0.50%
Line of Credit [Member] | Borrowing Base Utilization Of 50 Percent Or More But Less Than 75 Percent [Member] | Eurodollar [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		2.00%
Line of Credit [Member] | Borrowing Base Utilization Of 50 Percent Or More But Less Than 75 Percent [Member] | Prime Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.00%
Line of Credit [Member] | Borrowing Base Utilization Of 75 Percent Or More But Less Than 90 Percent [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage		0.50%
Line of Credit [Member] | Borrowing Base Utilization Of 75 Percent Or More But Less Than 90 Percent [Member] | Eurodollar [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		2.25%
Line of Credit [Member] | Borrowing Base Utilization Of 75 Percent Or More But Less Than 90 Percent [Member] | Prime Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.25%
Line of Credit [Member] | Borrowing Base Utilization Of 90 Percent Or More [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage		0.50%
Line of Credit [Member] | Borrowing Base Utilization Of 90 Percent Or More [Member] | Eurodollar [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		2.50%
Line of Credit [Member] | Borrowing Base Utilization Of 90 Percent Or More [Member] | Prime Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.50%
Line of Credit [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, maximum loan amount		$ 2,500,000
Line of credit facility, current borrowing base		1,500,000
Line of credit agreement, aggregate lender commitments		1,000,000		925,000
Credit facility balance	[1]	0		0
Letters of credit	[2]	200		200
Available borrowing capacity		999,800		924,800
Unamortized deferred financing costs		$ 6,700		$ 3,100
Line of Credit [Member] | Revolving Credit Facility [Member] | Subsequent Event [Member]
Line of Credit Facility [Line Items]
Line of credit agreement, aggregate lender commitments			$ 1,000,000
Credit facility balance			0
Letters of credit	[2]		200
Available borrowing capacity			$ 999,800
Line of Credit [Member] | Revolving Credit Facility [Member] | Maximum [Member] | 12/31/18 QE through 12/31/19 QE [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Covenant Compliance, Total Funded Debt To Adjusted EBITDAX Ratio		4.25
Line of Credit [Member] | Revolving Credit Facility [Member] | Maximum [Member] | 3/31/20 QE and Thereafter [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Covenant Compliance, Total Funded Debt To Adjusted EBITDAX Ratio		4
Line of Credit [Member] | Revolving Credit Facility [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Covenant Compliance, Adjusted Current Ratio		1
[1]	(1) Unamortized deferred financing costs attributable to the credit facility are presented as a component of other noncurrent assets on the accompanying balance sheets and totaled $6.7 million and $3.1 million as of September 30, 2018, and December 31, 2017, respectively. These costs are being amortized over the term of the credit facility on a straight-line basis.
[2]	(2) Letters of credit outstanding reduce the amount available under the credit facility on a dollar-for-dollar basis.

Long-Term Debt Senior Notes (De

Long-Term Debt Senior Notes (Details) - USD ($) $ in Thousands		Aug. 20, 2018	Jul. 16, 2018	Jun. 15, 2018	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Debt Instrument [Line Items]
Principal Amount, Net of Unamortized Deferred Financing Costs					$ 2,447,290		$ 2,447,290		$ 2,769,663
Loss on extinguishment of debt					(26,722)	$ 0	(26,722)	$ (35)
Cash paid for extinguishment of debt	[1]							13
Non-cash loss on extinguishment of debt							6,334	$ 22
Senior Notes
Debt Instrument [Line Items]
Principal Amount					2,476,796		2,476,796		2,801,392
Unamortized Deferred Financing Costs					(29,506)		(29,506)		(31,729)
Principal Amount, Net of Unamortized Deferred Financing Costs					$ 2,447,290		$ 2,447,290		2,769,663
6.50% Senior Notes due 2021
Debt Instrument [Line Items]
Senior Notes, interest rate, stated percentage					6.50%		6.50%
6.125% Senior Notes due 2022
Debt Instrument [Line Items]
Senior Notes, interest rate, stated percentage					6.125%		6.125%
6.50% Senior Notes due 2023
Debt Instrument [Line Items]
Senior Notes, interest rate, stated percentage					6.50%		6.50%
5.0% Senior Notes due 2024
Debt Instrument [Line Items]
Senior Notes, interest rate, stated percentage					5.00%		5.00%
5.625% Senior Notes due 2025
Debt Instrument [Line Items]
Senior Notes, interest rate, stated percentage					5.625%		5.625%
6.75% Senior Notes due 2026
Debt Instrument [Line Items]
Senior Notes, interest rate, stated percentage					6.75%		6.75%
Senior Notes | 6.50% Senior Notes due 2021
Debt Instrument [Line Items]
Senior Notes, interest rate, stated percentage					6.50%		6.50%
Principal Amount					$ 0		$ 0		344,611
Unamortized Deferred Financing Costs					0		0		(2,656)
Principal Amount, Net of Unamortized Deferred Financing Costs					0		$ 0		341,955
Debt Instrument, Repurchased Face Amount				$ 344,611
Debt Instrument, Redemption Price, Percentage				102.167%
Debt Instrument, Repurchased Settlement Amount			$ 355,900
Loss on extinguishment of debt					9,800
Cash paid for extinguishment of debt					7,500
Non-cash loss on extinguishment of debt					$ 2,300
Senior Notes | 6.125% Senior Notes due 2022
Debt Instrument [Line Items]
Senior Notes, interest rate, stated percentage					6.125%		6.125%
Principal Amount					$ 476,796		$ 476,796		561,796
Unamortized Deferred Financing Costs					(4,171)		(4,171)		(5,800)
Principal Amount, Net of Unamortized Deferred Financing Costs					472,625		472,625		555,996
Debt Instrument, Repurchased Face Amount					$ 85,000		$ 85,000
Senior Notes | 6.50% Senior Notes due 2023
Debt Instrument [Line Items]
Senior Notes, interest rate, stated percentage					6.50%		6.50%
Principal Amount					$ 0		$ 0		394,985
Unamortized Deferred Financing Costs					0		0		(3,707)
Principal Amount, Net of Unamortized Deferred Financing Costs					0		0		391,278
Debt Instrument, Repurchased Face Amount					$ 394,985		$ 394,985
Senior Notes | 5.0% Senior Notes due 2024
Debt Instrument [Line Items]
Senior Notes, interest rate, stated percentage					5.00%		5.00%
Principal Amount					$ 500,000		$ 500,000		500,000
Unamortized Deferred Financing Costs					(4,919)		(4,919)		(5,610)
Principal Amount, Net of Unamortized Deferred Financing Costs					$ 495,081		$ 495,081		494,390
Senior Notes | 5.625% Senior Notes due 2025
Debt Instrument [Line Items]
Senior Notes, interest rate, stated percentage					5.625%		5.625%
Principal Amount					$ 500,000		$ 500,000		500,000
Unamortized Deferred Financing Costs					(6,035)		(6,035)		(6,714)
Principal Amount, Net of Unamortized Deferred Financing Costs					$ 493,965		$ 493,965		493,286
Senior Notes | 6.75% Senior Notes due 2026
Debt Instrument [Line Items]
Senior Notes, interest rate, stated percentage					6.75%		6.75%
Principal Amount					$ 500,000		$ 500,000		500,000
Unamortized Deferred Financing Costs					(6,615)		(6,615)		(7,242)
Principal Amount, Net of Unamortized Deferred Financing Costs					$ 493,385		$ 493,385		492,758
Senior Notes | 6.625% Senior Notes due 2027
Debt Instrument [Line Items]
Senior Notes, interest rate, stated percentage					6.625%		6.625%
Principal Amount		$ 500,000			$ 500,000		$ 500,000		0
Unamortized Deferred Financing Costs					(7,766)		(7,766)		0
Principal Amount, Net of Unamortized Deferred Financing Costs					492,234		$ 492,234		$ 0
Proceeds from Debt, Net of Issuance Costs		492,100
Debt Issuance Costs, Gross		$ 7,900
Senior Notes | 6.125% Senior Notes Due 2022 and 6.50% Senior Notes Due 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Repurchased Settlement Amount					497,800
Loss on extinguishment of debt					16,900
Cash paid for extinguishment of debt					12,900
Non-cash loss on extinguishment of debt					$ 4,000
[1]	(1) Included as a component within the cash paid to repurchase Senior Notes, including premium line item on the accompanying statements of cash flows.

Long-Term Debt Senior Convertib

Long-Term Debt Senior Convertible Notes (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Debt Instrument [Line Items]
Senior Convertible Notes, net carrying amount	$ 145,662		$ 145,662		$ 139,107
1.50% Senior Convertible Notes Due 2021 [Member]
Debt Instrument [Line Items]
Senior Convertible Notes, face amount	$ 172,500		$ 172,500		172,500
Senior Convertible Notes, interest rate, stated percentage	1.50%		1.50%
Senior Convertible Notes, interest expense	$ 2,600	$ 2,500	$ 7,800	$ 7,400
Senior Convertible Notes, unamortized debt discount	(24,316)		(24,316)		(30,183)
Unamortized deferred financing costs	(2,522)		(2,522)		(3,210)
Senior Convertible Notes, net carrying amount	$ 145,662		$ 145,662		$ 139,107

Commitments (Details)

Commitments (Details) $ in Millions	Sep. 30, 2018USD ($)MMBblsBcf	Nov. 02, 2018USD ($)
Water Pipeline Commitment [Member]
Other Commitments [Line Items]
Water delivery commitments, remaining minimum contractual volumes | MMBbls	22
Water Purchase Commitment [Member]
Other Commitments [Line Items]
Water purchase commitment, minimum volume required | MMBbls	7
Gas gathering and Oil and Gas Through-put Commitments [Member]
Other Commitments [Line Items]
Contractual obligation	$ 342.2
Drilling Rig Leasing Contracts [Member] | Subsequent Event [Member]
Other Commitments [Line Items]
Contractual obligation		$ 93
Early termination penalties for rig contracts		$ 42.7
Electricity Purchase Agreement [Member]
Other Commitments [Line Items]
Contractual obligation	$ 29.9
Crude Oil Pipeline Commitment [Member]
Other Commitments [Line Items]
Oil and gas delivery commitments, remaining minimum contractual volumes | MMBbls	30
Natural Gas Pipeline Commitment [Member]
Other Commitments [Line Items]
Oil and gas delivery commitments, remaining minimum contractual volumes | Bcf	691

Compensation Plans (Details)

Compensation Plans (Details)		Sep. 30, 2018USD ($)$ / sharesshares	Sep. 30, 2018USD ($)$ / sharesshares	Jun. 30, 2018shares	Sep. 30, 2017USD ($)	Jun. 30, 2017shares	Sep. 30, 2018USD ($)shares$ / shares	Sep. 30, 2017USD ($)shares	Dec. 31, 2017$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant		5,700,000	5,700,000				5,700,000
Employee Stock Purchase Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Maximum Employee Subscription Rate		15.00%	15.00%				15.00%
Share-based Compensation Arrangement by Share-based Payment Award, Maximum Employee Subscription | $		$ 25,000	$ 25,000				$ 25,000
Share-based Compensation Arrangement by Share-based Payment Award, Purchase Price of Common Stock, Percent							85.00%
Stock Issued During Period, Shares, Employee Stock Purchase Plans							100,249	123,678
Proceeds from Issuance of Shares under Incentive and Share-based Compensation Plans, Excluding Stock Options | $							$ 1,900,000	$ 1,700,000
Director [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Issued During Period, Shares, Share-based Compensation, Gross				58,572		71,573
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Multiplier applied to PSU awards at settlement		0	0				0
Stock-based compensation expense | $			$ 3,000,000		$ 2,600,000		$ 7,700,000	6,800,000
Unrecognized stock based compensation expense | $		$ 22,900,000	$ 22,900,000				$ 22,900,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	[1]	1,776,191	1,776,191				1,776,191		1,533,491
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value | $ / shares		$ 20.66	$ 20.66				$ 20.66		$ 22.97
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	[1]						572,924
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $ / shares							$ 24.45
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	[1]						(233,102)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value | $ / shares							$ 44.25
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	[1]						(97,122)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value | $ / shares							$ 22.89
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Multiplier Assumed							1
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Granted in Period, Total Fair Value | $							$ 14,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Shares Issued in Period							0
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, Award Vesting Period		3 years
Stock-based compensation expense | $			$ 3,000,000		$ 2,900,000		$ 8,000,000	$ 7,500,000
Unrecognized stock based compensation expense | $		$ 24,100,000	$ 24,100,000				$ 24,100,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number		1,308,144	1,308,144				1,308,144		1,244,262
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value | $ / shares		$ 21.46	$ 21.46				$ 21.46		$ 20.25
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period							583,552
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $ / shares							$ 25.77
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period							(407,529)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value | $ / shares							$ 24.30
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period							(112,141)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value | $ / shares							$ 17.93
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Granted in Period, Total Fair Value | $							$ 15,000,000
Number of shares represented by each RSU		1
Stock Issued During Period, Shares, Share-based Compensation, Gross							407,529
Restricted Stock, Shares Issued Net of Shares for Tax Withholdings							291,745
Restricted Stock Units (RSUs) [Member] | Director [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						8,794
Minimum [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Multiplier applied to PSU awards at settlement		0	0				0
Maximum [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Multiplier applied to PSU awards at settlement		2	2				2
Performance Period [Member] | 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
[1]	(1) The number of awards assumes a multiplier of one. The final number of shares of common stock issued may vary depending on the three-year performance multiplier which ranges from zero to two.

Pension Benefits (Details)

Pension Benefits (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Components of Net Periodic Benefit Costs for the Pension Plans
Service cost	$ 1,683	$ 1,660	$ 5,048	$ 4,979
Interest cost	657	673	1,967	2,017
Expected return on plan assets that reduces periodic pension benefit cost	(466)	(561)	(1,397)	(1,683)
Amortization of prior service cost	4	4	13	13
Amortization of net actuarial loss	331	324	995	973
Net periodic benefit cost	$ 2,209	$ 2,100	$ 6,626	$ 6,299

Pension Benefits Pension (Detai

Pension Benefits Pension (Details) $ in Millions	9 Months Ended
	Sep. 30, 2018USD ($)
Pension Details [Abstract]
Pension Plans, Gain (Loss) Amortization Threshold	10.00%
Pension Contributions	$ 8.1

Earnings per Share (Details)

Earnings per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	2,433	0	0	78
Calculation of basic and diluted earnings per share
Net income (loss)	$ (135,923)	$ (89,112)	$ 198,675	$ (134,585)
Basic weighted-average common shares outstanding	112,107	111,575	111,836	111,366
Dilutive effect of non-vested RSUs and contingent PSUs	0	0	1,764	0
Dilutive effect of Senior Convertible Notes	0	0	0	0
Diluted weighted-average common shares outstanding	112,107	111,575	113,600	111,366
Basic net income (loss) per common share	$ (1.21)	$ (0.80)	$ 1.78	$ (1.21)
Diluted net income (loss) per common share	(1.21)	$ (0.80)	1.75	$ (1.21)
1.50% Senior Convertible Notes Due 2021 [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Debt Instrument, Convertible, Conversion Price	$ 40.50		$ 40.50

Derivative Financial Instrume_3

Derivative Financial Instruments (Details) bbl in Thousands, BTU in Billions		Nov. 02, 2018BTU$ / EnergyContent$ / Barrelsbbl	Sep. 30, 2018BTU$ / EnergyContent$ / Barrelsbbl
NYMEX Oil Swap Contract Fourth Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			1,894
Derivative, Swap Type, Average Fixed Price | $ / Barrels			49.87
NYMEX Oil Swap Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			3,733
Derivative, Swap Type, Average Fixed Price | $ / Barrels			59.80
NYMEX Oil Swap Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			2,491
Derivative, Swap Type, Average Fixed Price | $ / Barrels			65.68
NYMEX Oil Swap Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			8,118
NYMEX Oil Collar Contract Fourth Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			2,222
Derivative, Floor Price | $ / Barrels			50
Derivative, Ceiling Price | $ / Barrels			58.44
NYMEX Oil Collar Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			10,055
Derivative, Floor Price | $ / Barrels			50.59
Derivative, Ceiling Price | $ / Barrels			63.62
NYMEX Oil Collar Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			1,165
Derivative, Floor Price | $ / Barrels			55
Derivative, Ceiling Price | $ / Barrels			66.47
NYMEX Oil Collar Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			13,442
Gas Swaps Contract Fourth Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent			3.27
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU			28,204
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | BTU			(7,210)
Derivative, Swap Type, Weighted-Average Fixed Price, Purchased Volumes | $ / EnergyContent			4.27
Derivative, Nonmonetary Notional Amount, Energy Measure, Net Volumes | BTU			20,994
Derivative, Swap Type, Average Fixed Price, Net of Purchased Volumes | $ / EnergyContent			2.92
Gas Swaps Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent			3.58
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU			50,021
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | BTU			(24,415)
Derivative, Swap Type, Weighted-Average Fixed Price, Purchased Volumes | $ / EnergyContent			4.34
Derivative, Nonmonetary Notional Amount, Energy Measure, Net Volumes | BTU			25,606
Derivative, Swap Type, Average Fixed Price, Net of Purchased Volumes | $ / EnergyContent			2.85
Gas Swaps Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent			2.82
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU			2,942
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | BTU			0
Derivative, Swap Type, Weighted-Average Fixed Price, Purchased Volumes | $ / EnergyContent			0
Derivative, Nonmonetary Notional Amount, Energy Measure, Net Volumes | BTU			2,942
Derivative, Swap Type, Average Fixed Price, Net of Purchased Volumes | $ / EnergyContent			2.82
Gas Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU			81,167
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | BTU			(31,625)
Derivative, Nonmonetary Notional Amount, Energy Measure, Net Volumes | BTU			49,542
IF HSC Gas Collar Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Floor Price | $ / EnergyContent			2.50
Derivative, Ceiling Price | $ / EnergyContent			2.83
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU			14,242
WTI Midland NYMEX WTI [Member] | Oil Basis Swap Contract Fourth Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			3,327
Weighted-Average Contract Price | $ / Barrels	[1]		(1.08)
WTI Midland NYMEX WTI [Member] | Oil Basis Swap Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			11,217
Weighted-Average Contract Price | $ / Barrels	[1]		(3.36)
WTI Midland NYMEX WTI [Member] | Oil Basis Swap Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			10,960
Weighted-Average Contract Price | $ / Barrels	[1]		(1.05)
WTI Midland NYMEX WTI [Member] | Oil Basis Swap Contract 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			0
Weighted-Average Contract Price | $ / Barrels	[1]		0
WTI Midland NYMEX WTI [Member] | Oil Basis Swap Contract 2022 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			0
Weighted-Average Contract Price | $ / Barrels	[1]		0
WTI Midland NYMEX WTI [Member] | Oil Basis Swap [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			25,504
NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract Fourth Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			0
Weighted-Average Contract Price | $ / Barrels	[2]		0
NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			0
Weighted-Average Contract Price | $ / Barrels	[2]		0
NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			1,840
Weighted-Average Contract Price | $ / Barrels	[2]		(8.01)
NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			3,650
Weighted-Average Contract Price | $ / Barrels	[2]		(7.86)
NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract 2022 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			3,650
Weighted-Average Contract Price | $ / Barrels	[2]		(7.78)
NYMEX WTI ICE Brent [Member] | Oil Basis Swap [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			9,140
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract Fourth Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			1,146
Derivative, Swap Type, Average Fixed Price | $ / Barrels			11.18
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			3,533
Derivative, Swap Type, Average Fixed Price | $ / Barrels			12.31
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			539
Derivative, Swap Type, Average Fixed Price | $ / Barrels			11.13
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			5,218
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			671
Derivative, Swap Type, Average Fixed Price | $ / Barrels			24.39
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			1,980
Derivative, Swap Type, Average Fixed Price | $ / Barrels			28.89
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			2,651
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			102
Derivative, Swap Type, Average Fixed Price | $ / Barrels			35.70
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			154
Derivative, Swap Type, Average Fixed Price | $ / Barrels			35.64
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			0
Derivative, Swap Type, Average Fixed Price | $ / Barrels			0
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			256
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			76
Derivative, Swap Type, Average Fixed Price | $ / Barrels			35.07
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			117
Derivative, Swap Type, Average Fixed Price | $ / Barrels			35.70
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			0
Derivative, Swap Type, Average Fixed Price | $ / Barrels			0
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			193
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			208
Derivative, Swap Type, Average Fixed Price | $ / Barrels			50.99
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			197
Derivative, Swap Type, Average Fixed Price | $ / Barrels			50.93
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			0
Derivative, Swap Type, Average Fixed Price | $ / Barrels			0
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			405
Subsequent Event [Member] | Gas Swaps Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU		15,769
Subsequent Event [Member] | NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		900
Subsequent Event [Member] | OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		100
Derivative, Swap Type, Average Fixed Price | $ / Barrels		45.59
Subsequent Event [Member] | OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		400
Derivative, Swap Type, Average Fixed Price | $ / Barrels		40.11
Minimum [Member] | Subsequent Event [Member] | Gas Swaps Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent		2.80
Minimum [Member] | Subsequent Event [Member] | NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract 2020 [Member]
Derivative Financial Instruments
Weighted-Average Contract Price | $ / Barrels		(8.05)
Maximum [Member] | Subsequent Event [Member] | Gas Swaps Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent		3.42
Maximum [Member] | Subsequent Event [Member] | NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract 2020 [Member]
Derivative Financial Instruments
Weighted-Average Contract Price | $ / Barrels		(8.10)
[1]	(1) Represents the price differential between WTI Midland (Midland, Texas) and NYMEX WTI (Cushing, Oklahoma).
[2]	(2) Represents the price differential between NYMEX WTI (Cushing, Oklahoma) and ICE Brent (North Sea).

Derivative Financial Instrume_4

Derivative Financial Instruments Fair Value (Details) - USD ($) $ in Thousands	Sep. 30, 2018		Dec. 31, 2017
Fair value of derivative assets and liabilities
Derivative, fair value, net	$ (286,700)		$ (139,400)
Derivative assets, current	81,163		64,266
Derivative assets, noncurrent	8,853		40,362
Total derivative assets	90,016		104,628
Derivative liabilities, current	304,159		172,582
Derivatives liabilities, noncurrent	72,605		71,402
Total derivative liabilities	376,764		243,984
Derivative asset, not offset in the accompanying balance sheets	(90,016)		(100,035)
Derivative liabilities, not offset in the accompanying balance sheets	90,016		100,035
Derivative asset, fair value, net amounts	0		4,593
Derivative liabilities, fair value, net amounts	(286,748)		(143,949)
Not Designated as Hedging Instrument [Member]
Fair value of derivative assets and liabilities
Derivative assets, current	81,163		64,266
Derivative assets, noncurrent	8,853		40,362
Derivative liabilities, current	304,159		172,582
Derivatives liabilities, noncurrent	72,605		71,402
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Not Designated as Hedging Instrument [Member]
Fair value of derivative assets and liabilities
Total derivative assets	90,016	[1]	104,628	[2]
Total derivative liabilities	$ 376,764	[1]	$ 243,984	[2]
[1]	(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.
[2]	(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.

Derivative Financial Instrume_5

Derivative Financial Instruments Gains and Losses (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Derivative Instruments, (Gain) Loss [Line Items]
Derivative settlement (gain) loss	$ 40,718	$ (13,092)	$ 101,911	$ (29,402)
Net derivative (gain) loss	178,026	80,599	249,304	(89,364)
Oil Contracts [Member]
Derivative Instruments, (Gain) Loss [Line Items]
Derivative settlement (gain) loss	16,798	2,472	61,976	14,310
Net derivative (gain) loss	110,413	45,874	146,781	(41,910)
Gas Contracts [Member]
Derivative Instruments, (Gain) Loss [Line Items]
Derivative settlement (gain) loss	802	(24,088)	(4,851)	(63,345)
Net derivative (gain) loss	4,309	(6,068)	21,299	(56,574)
NGL Contracts [Member]
Derivative Instruments, (Gain) Loss [Line Items]
Derivative settlement (gain) loss	23,118	8,524	44,786	19,633
Net derivative (gain) loss	$ 63,304	$ 40,793	$ 81,224	$ 9,120

Derivative Financial Instrume_6

Derivative Financial Instruments Credit Facility and Derivative Counterparties (Details)	Sep. 30, 2018
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Percentage of Proved Property Secured for Credit Facility Borrowing	85.00%

Fair Value Measurements Fair _2

Fair Value Measurements Fair Value (Details) - USD ($) $ in Thousands	Sep. 30, 2018		Dec. 31, 2017
Assets
Derivatives	$ 90,016		$ 104,628
Liabilities
Derivatives	376,764		243,984
Not Designated as Hedging Instrument [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Assets
Derivatives	0	[1]	0	[2]
Liabilities
Derivatives	0	[1]	0	[2]
Not Designated as Hedging Instrument [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Assets
Derivatives	90,016	[1]	104,628	[2]
Liabilities
Derivatives	376,764	[1]	243,984	[2]
Not Designated as Hedging Instrument [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Assets
Derivatives	0	[1]	0	[2]
Liabilities
Derivatives	$ 0	[1]	$ 0	[2]
[1]	(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.
[2]	(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.

Fair Value Measurements Proved

Fair Value Measurements Proved and Unproved Oil and Gas Properties and Other Property and Equipment (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of Proved Oil and Gas Properties	$ 0	$ 0	$ 0	$ 0
Abandonment and impairment of unproved oil and gas properties	9,055	$ 0	26,615	157
Properties held for sale, net	5,040		5,040		$ 111,700
Properties Held-for-sale, Fair Value	5,040		5,040		0
Disposal Group, Held-for-sale, Not Discontinued Operations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Properties held for sale, net	$ 5,040		$ 5,040		$ 111,700
Divide County Disposal Group [Member] | Disposal Group, Held-for-sale, Not Discontinued Operations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Disposal Group, Not Discontinued Operation, Loss (Gain) on Write-down				$ 526,500

Fair Value Measurements Long-te

Fair Value Measurements Long-term Debt (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Aug. 20, 2018	Dec. 31, 2017
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Properties held for sale, net	$ 5,040		$ 111,700
6.50% Senior Notes due 2021
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, interest rate, stated percentage	6.50%
6.125% Senior Notes due 2022
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, interest rate, stated percentage	6.125%
6.50% Senior Notes due 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, interest rate, stated percentage	6.50%
5.0% Senior Notes due 2024
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, interest rate, stated percentage	5.00%
5.625% Senior Notes due 2025
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, interest rate, stated percentage	5.625%
6.75% Senior Notes due 2026
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, interest rate, stated percentage	6.75%
Senior Notes | 6.50% Senior Notes due 2021
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, interest rate, stated percentage	6.50%
Principal Amount	$ 0		344,611
Long-term Debt, Fair Value	$ 0		351,682
Senior Notes | 6.125% Senior Notes due 2022
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, interest rate, stated percentage	6.125%
Principal Amount	$ 476,796		561,796
Long-term Debt, Fair Value	$ 491,076		571,627
Senior Notes | 6.50% Senior Notes due 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, interest rate, stated percentage	6.50%
Principal Amount	$ 0		394,985
Long-term Debt, Fair Value	$ 0		403,434
Senior Notes | 5.0% Senior Notes due 2024
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, interest rate, stated percentage	5.00%
Principal Amount	$ 500,000		500,000
Long-term Debt, Fair Value	$ 491,000		483,440
Senior Notes | 5.625% Senior Notes due 2025
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, interest rate, stated percentage	5.625%
Principal Amount	$ 500,000		500,000
Long-term Debt, Fair Value	$ 498,125		494,355
Senior Notes | 6.75% Senior Notes due 2026
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, interest rate, stated percentage	6.75%
Principal Amount	$ 500,000		500,000
Long-term Debt, Fair Value	$ 522,150		516,350
Senior Notes | 6.625% Senior Notes due 2027
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, interest rate, stated percentage	6.625%
Principal Amount	$ 500,000	$ 500,000	0
Long-term Debt, Fair Value	$ 517,250		0
Convertible Debt [Member] | 1.50% Senior Convertible Notes Due 2021 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, interest rate, stated percentage	1.50%
Principal Amount	$ 172,500		172,500
Long-term Debt, Fair Value	$ 191,044		$ 168,291