SM Energy (SM) 10-Q 2 Aug 18 2018 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information Document - shares	6 Months Ended
	Jun. 30, 2018	Jul. 25, 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	Jun. 30, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Common Stock, Shares Outstanding		112,137,582
Entity Current Reporting Status	Yes

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) (in thousands, except share data) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018		Jun. 30, 2018		Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 615,906		$ 615,906		$ 313,943
Accounts receivable	178,682		178,682		160,154
Derivative assets	146,329		146,329		64,266
Prepaid expenses and other	14,293		14,293		10,752
Total current assets	955,210		955,210		549,115
Property and equipment (successful efforts method):
Proved oil and gas properties	6,372,956		6,372,956		6,139,379
Accumulated depletion, depreciation, and amortization	(3,041,653)		(3,041,653)		(3,171,575)
Unproved oil and gas properties	1,917,883		1,917,883		2,047,203
Wells in progress	361,238		361,238		321,347
Oil and gas properties held for sale, net	5,040		5,040		111,700
Other property and equipment, net of accumulated depreciation of $53,483 and $49,985, respectively	102,986		102,986		106,738
Total property and equipment, net	5,718,450		5,718,450		5,554,792
Noncurrent assets:
Derivative assets	31,151		31,151		40,362
Other noncurrent assets	31,674		31,674		32,507
Total noncurrent assets	62,825		62,825		72,869
Total assets	6,736,485		6,736,485		6,176,776
Current liabilities:
Accounts payable and accrued expenses	446,318		446,318		386,630
Current portion of Senior Notes, net of unamortized deferred financing costs (note 5)	342,301		342,301		0
Derivative liabilities	259,338		259,338		172,582
Total current liabilities	1,047,957		1,047,957		559,212
Noncurrent liabilities:
Revolving credit facility	0		0		0
Noncurrent portion of Senior Notes, net of unamortized deferred financing costs	2,429,994		2,429,994		2,769,663
Senior Convertible Notes, net of unamortized discount and deferred financing costs	143,430		143,430		139,107
Asset retirement obligations	87,279		87,279		103,026
Asset retirement obligations associated with oil and gas properties held for sale	0		0		11,369
Deferred income taxes	177,709		177,709		79,989
Derivative liabilities	67,583		67,583		71,402
Other noncurrent liabilities	45,906		45,906		48,400
Total noncurrent liabilities	2,951,901		2,951,901		3,222,956
Commitments and contingencies (note 6)
Stockholders’ equity:
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 111,846,998 and 111,687,016 shares, respectively	1,118		1,118		1,117
Additional paid-in capital	1,754,169		1,754,169		1,741,623
Retained earnings	997,641	[1]	997,641	[1]	665,657
Accumulated other comprehensive loss	(16,301)	[1]	(16,301)	[1]	(13,789)
Total stockholders’ equity	2,736,627		2,736,627		2,394,608
Total liabilities and stockholders’ equity	6,736,485		6,736,485		6,176,776
Exploration	14,056		27,783
6.50% Senior Notes due 2021 | Senior Notes [Member]
Current liabilities:
Current portion of Senior Notes, net of unamortized deferred financing costs (note 5)	$ 342,301		$ 342,301
Noncurrent liabilities:
Noncurrent portion of Senior Notes, net of unamortized deferred financing costs					$ 341,955
[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 Balance3

Condensed Consolidated Balance Sheets Parenthetical - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Property, Plant and Equipment, Other, Accumulated Depreciation	$ 53,483	$ 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	111,846,998	111,687,016
Common Stock, Shares, Outstanding	111,846,998	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		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Operating revenues and other income:
Oil, gas, and NGL production revenue	$ 402,558	$ 284,939	$ 785,444	$ 618,137
Net gain (loss) on divestiture activity	39,501	(167,133)	424,870	(129,670)
Other operating revenues	1,857	2,915	3,197	4,992
Total operating revenues and other income	443,916	120,721	1,213,511	493,459
Operating expenses:
Oil, gas, and NGL production expense	117,400	124,376	238,279	262,422
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	151,765	153,232	282,238	291,044
Exploration	14,056	12,983	27,783	24,800
Abandonment and impairment of unproved properties	11,935	157	17,560	157
General and administrative	28,920	28,237	56,602	57,054
Net derivative (gain) loss	63,749	(55,189)	71,278	(169,963)
Other operating expenses, net	(57)	4,251	4,555	9,110
Total operating expenses	387,768	268,047	698,295	474,624
Income (loss) from operations	56,148	(147,326)	515,216	18,835
Interest expense	(41,654)	(44,595)	(84,739)	(91,548)
Loss on extinguishment of debt	0	0	0	(35)
Other non-operating income, net	1,802	953	2,211	720
Income (loss) before income taxes	16,296	(190,968)	432,688	(72,028)
Income tax (expense) benefit	901	71,061	(98,090)	26,555
Net income (loss)	$ 17,197	$ (119,907)	$ 334,598	$ (45,473)
Basic weighted-average common shares outstanding	111,701	111,277	111,698	111,274
Diluted weighted-average common shares outstanding	113,630	111,277	113,267	111,274
Basic net income (loss) per common share	$ 0.15	$ (1.08)	$ 3	$ (0.41)
Diluted net income (loss) per common share	0.15	(1.08)	2.95	(0.41)
Dividends per common share	$ 0	$ 0	$ 0.05	$ 0.05

CONDENSED CONSOLIDATED STATEME5

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED) (in thousands) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 17,197	$ (119,907)	$ 334,598	$ (45,473)
Other comprehensive income (loss), net of tax:
Pension liability adjustment	198	124	458	(443)
Total other comprehensive income (loss), net of tax	198	124	458	(443)
Total comprehensive income (loss)	$ 17,395	$ (119,783)	$ 335,056	$ (45,916)

CONDENSED CONSOLIDATED STATEME6

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (in thousands) - USD ($) $ in Thousands		6 Months Ended
		Jun. 30, 2018	Jun. 30, 2017
Cash flows from operating activities:
Net income (loss)		$ 334,598	$ (45,473)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net (gain) loss on divestiture activity		(424,870)	129,670
Depletion, depreciation, amortization, and asset retirement obligation liability accretion		282,238	291,044
Abandonment and impairment of unproved properties		17,560	157
Stock-based compensation expense		10,676	9,813
Net derivative (gain) loss		71,278	(169,963)
Derivative settlement gain (loss)		(61,193)	16,310
Amortization of debt discount and deferred financing costs		7,750	8,679
Loss on extinguishment of debt		0	35
Deferred income taxes		97,505	(30,790)
Other, net		(2,302)	4,464
Net change working capital		(21,722)	28,182
Net cash provided by operating activities		311,518	242,128
Cash flows from investing activities:
Net proceeds from the sale of oil and gas properties		742,215	766,247
Capital expenditures		(723,319)	(366,743)
Acquisition of proved and unproved oil and gas properties		(24,615)	(88,140)
Net cash provided by (used in) investing activities		(5,719)	311,364
Cash flows from financing activities:
Proceeds from credit facility		0	406,000
Repayment of credit facility		0	(406,000)
Cash paid to repurchase Senior Notes		0	(2,344)
Cash paid for extinguishment of debt		0	(13)
Net proceeds from sale of common stock		1,881	1,738
Dividends paid		(5,584)	(5,563)
Other, net		(133)	(161)
Net cash used in financing activities		(3,836)	(6,343)
Net change in cash, cash equivalents, and restricted cash	[1]	301,963	547,149
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]	615,906	559,521
Operating activities:
Cash paid for interest, net of capitalized interest		(77,803)	(83,493)
Net cash (paid) refunded for income taxes		207	(8,220)
Investing activities:
Changes in capital expenditure accruals and other		62,167	44,770
Supplemental non-cash investing activities:
Carrying value of properties exchanged		0
Supplemental non-cash financing activities:
Non-cash (gain) loss on extinguishment of debt, net		$ 0	$ 22
[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	6 Months Ended
	Jun. 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 June 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 Immaterial Errors The accompanying unaudited condensed consolidated financial statements for the three months ended June 30, 2018, include non-cash adjustments that relate to the prior quarter. For the three months ended June 30, 2018, the net gain (loss) on divestiture activity line item on the accompanying unaudited condensed consolidated statements of operations (“accompanying statements of operations”) includes $17.7 million of loss (approximately $13.7 million , net of tax) that should have been included in the estimated non-cash write down to fair value less selling costs recorded as of March 31, 2018, for the Divide County, North Dakota assets held for sale. Additionally, for the three months ended June 30, 2018, the depletion, depreciation, amortization, and asset retirement obligation liability accretion expense line item on the accompanying statements of operations includes $6.7 million of additional expense (approximately $5.2 million , net of tax) that should have been recognized during the first quarter of 2018. Aggregated, these non-cash adjustments resulted in reported net income for the three months ended March 31, 2018, to be overstated by approximately $18.9 million (net of tax) with the corrections being recorded during the three months ended June 30, 2018, resulting in net income for the three months ended June 30, 2018, to be understated by approximately $18.9 million (net of tax). These non-cash adjustments are not deemed material with respect to the first or second quarters of 2018, or the anticipated results for fiscal year 2018. Further, these non-cash adjustments do not have an impact on the unaudited condensed consolidated financial statements for the six months ended June 30, 2018. Significant Accounting Policies The significant accounting policies followed by the Company are set forth in Note 1 - Summary of Significant Accounting Policies to 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. 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 six months ended June 30, 2017 , are summarized as follows: For the Six Months Ended June 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 $ 242,115 $ 242,128 Cash flows from investing activities: Other, net $ 3,000 N/A Net cash provided by (used in) investing activities $ 314,364 $ 311,364 Cash flows from financing activities: Cash paid for extinguishment of debt N/A $ (13 ) Net cash used in financing activities $ (6,330 ) $ (6,343 ) Net change in cash and cash equivalents $ 550,149 N/A Net change in cash, cash equivalents, and restricted cash N/A $ 547,149 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 $ 559,521 N/A Cash, cash equivalents, and restricted cash at end of period N/A $ 559,521 The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the accompanying balance sheets: As of June 30, 2018 As of December 31, 2017 (in thousands) Cash and cash equivalents $ 615,906 $ 313,943 Restricted cash — — Total cash, cash equivalents, and restricted cash $ 615,906 $ 313,943 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 six months ended June 30, 2017 , are summarized as follows: For the Three Months Ended June 30, 2017 For the Six Months Ended June 30, 2017 As Reported As Adjusted As Reported As Adjusted (in thousands) Operating expenses: Exploration $ 13,072 $ 12,983 $ 25,050 $ 24,800 General and administrative $ 28,460 $ 28,237 $ 57,684 $ 57,054 Total operating expenses $ 268,359 $ 268,047 $ 475,504 $ 474,624 Income (loss) from operations $ (147,638 ) $ (147,326 ) $ 17,955 $ 18,835 Other non-operating income, net $ 1,265 $ 953 $ 1,600 $ 720 Effective January 1, 2018, the Company early adopted 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. Under ASU 2016-02, companies are permitted to make a policy election to not recognize lease assets or liabilities when the term of the lease is less than twelve months. For agreements that contain both lease and non-lease components, companies are also permitted to make a policy election to combine both the lease and non-lease components together and account for these arrangements as a single lease. 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. Further, the Company is also evaluating policies, controls, and processes that will be necessary to support the additional accounting and disclosure requirements. The Company is also in the process of designing and implementing a lease administration system that will support the on-going maintenance and accounting for leases after adoption. The Company will adopt ASU 2016-02 on January 1, 2019, and plans on 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 is currently evaluating ASU 2018-11 as part of its overall assessment of ASU 2016-02, and will adopt ASU 2018-11 at the same time it adopts ASU 2016-02. 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 June 30, 2018 , and through the filing of this report.

Revenue from Contracts with Cus

Revenue from Contracts with Customers	6 Months Ended
	Jun. 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, the Company does not expect any additional 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 six months ended June 30, 2018 , and 2017: Permian South Texas & Gulf Coast Rocky Mountain Total Three Months Ended June 30, Three Months Ended June 30, Three Months Ended June 30, Three Months Ended June 30, 2018 2017 2018 2017 2018 2017 2018 2017 (in thousands) Oil, gas, and NGL production revenue: Oil production revenue $ 227,636 $ 78,554 $ 19,346 $ 13,072 $ 19,168 $ 37,248 $ 266,150 $ 128,874 Gas production revenue 31,734 12,937 52,235 87,760 95 1,043 84,064 101,740 NGL production revenue 129 107 52,248 53,558 (33 ) 660 52,344 54,325 Total $ 259,499 $ 91,598 $ 123,829 $ 154,390 $ 19,230 $ 38,951 $ 402,558 $ 284,939 Relative percentage 64 % 32 % 31 % 54 % 5 % 14 % 100 % 100 % ____________________________________________ Note: Amounts may not calculate due to rounding. Permian South Texas & Gulf Coast Rocky Mountain Total Six Months Ended June 30, Six Months Ended June 30, Six Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 2018 2017 2018 2017 (in thousands) Oil, gas, and NGL production revenue: Oil production revenue $ 433,430 $ 160,053 $ 38,929 $ 51,936 $ 54,851 $ 84,509 $ 527,210 $ 296,498 Gas production revenue 56,611 24,246 104,968 175,961 1,594 2,714 163,173 202,921 NGL production revenue 253 254 94,018 116,915 790 1,549 95,061 118,718 Total $ 490,294 $ 184,553 $ 237,915 $ 344,812 $ 57,235 $ 88,772 $ 785,444 $ 618,137 Relative percentage 63 % 30 % 30 % 56 % 7 % 14 % 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 and is considered the customer. Proceeds received for unprocessed gas under these arrangements are reflected as gas production revenue above 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 June 30, 2018 , and December 31, 2017, were $115.0 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 six months ended June 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	6 Months Ended
	Jun. 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 $410.1 million for the six months ended June 30, 2018 . 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 $15.7 million for the six months ended June 30, 2018 . Please refer to Note 1 - Summary of Significant Accounting Policies for a discussion of an immaterial non-cash adjustment related to the Divide County Divestiture that was recorded in the second quarter of 2018. The following table presents loss before income taxes from the Divide County, North Dakota assets sold for the three and six months ended June 30, 2018 , and 2017. The Divide County Divestiture was considered a disposal of a significant asset group. For the Three Months Ended June 30, For the Six Months Ended June 30, 2018 2017 2018 2017 (in thousands) Loss before income taxes (1) $ (17,478 ) $ (153,442 ) $ (28,975 ) $ (486,161 ) ____________________________________________ (1) 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 net divestiture proceeds received at closing of $747.4 million , and net divestiture proceeds of $744.1 million after final purchase price adjustments. The Company recorded an estimated net gain of $397.4 million for the six months ended June 30, 2017, and a final net gain of $396.8 million related to these divested assets for the year ended December 31, 2017. During the second quarter of 2017, the Company divested of assets located in Williams County, North Dakota, for net divestiture proceeds of $24.6 million . Assets Held for Sale Assets are classified as held for sale when the Company commits to a plan to sell the assets and it is probable the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and a measurement for impairment is performed to identify and expense any excess of carrying value over fair value less estimated costs to sell. When assets no longer meet the criteria of assets held for sale, they are measured at the lower of the carrying value of the assets before being classified as held for sale, adjusted for any depletion, depreciation, and amortization expense that would have been recognized, or the fair value at the date they are reclassified to assets held for use. Any gain or loss recognized on assets held for sale or on assets held for sale that are subsequently reclassified to assets held for use is reflected in the net gain (loss) on divestiture activity line item on the accompanying statements of operations. As of June 30, 2018 , there were $5.0 million of assets held for sale presented on the accompanying balance sheets. During the second quarter of 2017, the Company reclassified its retained Divide County assets previously held for sale to assets held for use. A $359.6 million write-down was recorded on these assets in the first quarter of 2017 based on the estimated fair value less selling costs as of March 31, 2017. An additional $166.9 million write-down was recorded in the second quarter of 2017 based on market conditions that existed on the date the Company made its decision to retain these assets. Acquisitions During the second quarter of 2018, the Company acquired approximately 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 first half of 2017, the Company acquired approximately 3,400 net acres of primarily unproved properties in Howard and Martin Counties, Texas, in multiple transactions for a total of $72.3 million of cash consideration, which were accounted for as asset acquisitions. Also, during the first half of 2017, the Company completed several non-monetary acreage trades of primarily unproved properties in Howard and Martin Counties, Texas, resulting in the Company acquiring approximately 6,550 net acres in exchange for approximately 5,700 net acres, with $279.8 million of carrying value attributed to the properties surrendered by the Company in such trades. These trades were recorded at carryover basis with no gain or loss recognized.

Income Taxes

Income Taxes	6 Months Ended
	Jun. 30, 2018
Income Tax Disclosure [Abstract]
Income Taxes	Note 4 - Income Taxes The income tax (expense) benefit recorded for the three and six months ended June 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 six months ended June 30, 2018 , and 2017 , consisted of the following: For the Three Months Ended For the Six Months Ended 2018 2017 2018 2017 (in thousands) Current portion of income tax (expense) benefit: Federal $ — $ 4,607 $ — $ (2,832 ) State 40 2,439 (585 ) (1,403 ) Deferred portion of income tax (expense) benefit 861 64,015 (97,505 ) 30,790 Income tax (expense) benefit $ 901 $ 71,061 $ (98,090 ) $ 26,555 Effective tax rate (5.5 )% 37.2 % 22.7 % 36.9 % 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 for the three or six months ended June 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. For the three months ended June 30, 2018, the decrease in the effective tax rate year-over-year also reflects the cumulative effects of property divestitures in higher marginal rate states in 2018. Cumulative effects of state tax rate changes are reflected in the period legislation is enacted. Excess tax benefits and deficiencies from share-based payment awards impact the Company’s effective tax rate between periods. 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. The Company is generally no longer subject to United States federal or state income tax examinations by tax authorities for years before 2013.

Long-Term Debt (Notes)

Long-Term Debt (Notes)	6 Months Ended
	Jun. 30, 2018
Debt Disclosure [Abstract]
Long-Term Debt [Text Block]	Note 5 - Long-Term Debt Credit Agreement The Company’s Fifth Amended and Restated Credit Agreement, as amended, (the “Credit Agreement”) provides for a maximum loan amount of $2.5 billion and has a maturity date of December 10, 2019 . On April 24, 2018, as part of the regular, semi-annual borrowing base redetermination process, the borrowing base and aggregate lender commitments were increased to $1.4 billion and $1.0 billion , respectively. Upon completion of the Divide County Divestiture on May 30, 2018, the Company’s borrowing base was reduced to $1.3 billion , while the aggregate lender commitments remained at $1.0 billion . Please refer to Note 3 - Divestitures, Assets Held for Sale, and Acquisitions for additional discussion on the sale of these assets. The next scheduled redetermination date is October 1, 2018 . The Company must comply with certain financial and non-financial covenants under the terms of the Credit Agreement and was in compliance with all such covenants as of June 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 as presented in Note 5 - Long-Term Debt in the 2017 Form 10-K. Eurodollar loans accrue interest at the London Interbank Offered Rate, plus the applicable margin from the utilization grid, and Alternate Base Rate and swingline loans accrue interest at the prime 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 interest expense in the accompanying statements of operations. The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Credit Agreement as of July 25, 2018 , June 30, 2018 , and December 31, 2017 : As of July 25, 2018 As of June 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 $2.4 million and $3.1 million as of June 30, 2018 , and December 31, 2017 , respectively. (2) Letters of credit outstanding reduce the amount available under the credit facility on a dollar-for-dollar basis. Senior Notes The Company’s Senior Notes consist of 6.50% Senior Notes due 2021, 6.125% Senior Notes due 2022, 6.50% Senior Notes due 2023, 5.0% Senior Notes due 2024, 5.625% Senior Notes due 2025, and 6.75% Senior Notes due 2026 (collectively referred to as “Senior Notes”). On June 15, 2018 , the Company called for redemption all of its 6.50% Senior Notes due 2021 (“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 to be redeemed (“2021 Senior Notes Redemption”). As a result of the 2021 Senior Notes Redemption, the 2021 Senior Notes, net of unamortized deferred financing costs, were classified as a current liability on the accompanying balance sheets as of June 30, 2018 . On July 16, 2018, the Company completed the 2021 Senior Notes Redemption, which resulted in the payment of total consideration, including accrued interest, of $355.9 million . The Company will record a loss on extinguishment of debt of $9.8 million for the quarter ended September 30, 2018. This amount will include $7.5 million associated with the premium paid for the 2021 Senior Notes Redemption and $2.3 million related to the acceleration of unamortized deferred financing costs. The current portion of Senior Notes, net of unamortized deferred financing costs and noncurrent portion of Senior Notes, net of unamortized deferred financing costs lines on the accompanying balance sheets as of June 30, 2018 , and December 31, 2017 , consisted of the following: As of June 30, 2018 As of December 31, 2017 Principal Amount Unamortized Deferred Financing Costs Senior Notes, Net of Unamortized Deferred Financing Costs Principal Amount Unamortized Deferred Financing Costs Senior Notes, Net of Unamortized Deferred Financing Costs (in thousands) 6.50% Senior Notes due 2021 $ 344,611 $ 2,310 $ 342,301 $ 344,611 $ 2,656 $ 341,955 6.125% Senior Notes due 2022 561,796 5,211 556,585 561,796 5,800 555,996 6.50% Senior Notes due 2023 394,985 3,342 391,643 394,985 3,707 391,278 5.0% Senior Notes due 2024 500,000 5,149 494,851 500,000 5,610 494,390 5.625% Senior Notes due 2025 500,000 6,261 493,739 500,000 6,714 493,286 6.75% Senior Notes due 2026 500,000 6,824 493,176 500,000 7,242 492,758 Total $ 2,801,392 $ 29,097 $ 2,772,295 $ 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 June 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. 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 June 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 June 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 June 30, 2018 , and 2017, respectively, and totaled $5.2 million and $4.9 million for the six months ended June 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. The Senior Convertible Notes, net of unamortized discount and deferred financing costs line on the accompanying balance sheets as of June 30, 2018 , and December 31, 2017 , consisted of the following: As of June 30, 2018 As of December 31, 2017 (in thousands) Principal amount of Senior Convertible Notes $ 172,500 $ 172,500 Unamortized debt discount (26,319 ) (30,183 ) Unamortized deferred financing costs (2,751 ) (3,210 ) Senior Convertible Notes, net of unamortized discount and deferred financing costs $ 143,430 $ 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 June 30, 2018 , and through the filing of this report.

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies [Text Block]	Note 6 - Commitments and Contingencies Commitments As of June 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 31 MMBbl of oil, 737 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 June 30, 2018 , would total approximately $360.6 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 six months of 2018 and subsequent to June 30, 2018 . As of the filing of this report, the Company’s drilling rig and completion service contract commitments totaled $103.1 million ; however, if the Company terminated these contracts immediately, it would incur penalties of $40.4 million . Additionally, as of June 30, 2018 , the Company had fixed price contracts with various third parties to purchase electricity through 2027 for a total of $30.8 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 six 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 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	6 Months Ended
	Jun. 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 June 30, 2018 , 6.8 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. For PSUs that were granted in 2015, 2016, and 2017, the performance criteria is based on a combination of the Company’s annualized Total Shareholder Return (“TSR”) for the performance period and the relative performance of the Company’s TSR compared with the annualized TSR of certain peer companies for the performance period. Compensation expense for PSUs is recognized within general and administrative expense and exploration expense over the vesting periods of the respective awards. Total compensation expense recorded for PSUs was $2.4 million and $1.7 million for the three months ended June 30, 2018 , and 2017 , respectively, and was $4.8 million and $4.2 million for the six months ended June 30, 2018 , and 2017 , respectively. As of June 30, 2018 , there was $12.4 million of total unrecognized compensation expense related to non-vested PSU awards, which is being amortized through 2020. There were no material changes to the outstanding and non-vested PSUs during the six months ended June 30, 2018 . Subsequent to June 30, 2018 , the Company granted 572,924 PSUs with a fair value of $14.0 million (“2018 PSU Grant”). The fair value of the 2018 PSU Grant was measured at the grant date using a stochastic Monte Carlo simulation using geometric Brownian motion. The number of shares of the Company’s common stock issued to settle the 2018 PSU Grant, after the completion of a three -year performance period, will range from zero to two times the number of PSUs granted on the award date, depending on the extent to which the Company has achieved certain performance criteria and to the extent the PSUs have vested. As outlined in the 2018 PSU Grant agreement, performance measurements affecting vesting are based on a combination of relative performance of the Company’s annualized TSR compared with the annualized TSR of certain peer companies over the three-year performance period, and relative performance of the Company’s debt adjusted per share cash flow growth (“DACFG”) compared with the DACFG of certain peer companies over the three-year performance period. In addition to these performance measures, the 2018 PSU Grant agreement also stipulates that if the Company’s annualized 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 peers. Compensation expense associated with the 2018 PSU Grant will be evaluated on a quarterly basis and may be adjusted depending on the likelihood of achieving certain performance goals. The 2018 PSU Grant generally vests on the third anniversary of the date of the grant. Also, subsequent to June 30, 2018 , the Company settled PSUs that were granted in 2015, with no shares issued upon settlement because the grant settled at a zero multiplier. Employee Restricted Stock Units The Company grants restricted stock units (“RSUs”) to eligible employees as part of its long-term equity incentive compensation program. Each RSU represents a right to receive one share of the Company’s common stock upon settlement of the award at the end of the specified vesting period. Compensation expense for RSUs is recognized within general and administrative expense and exploration expense over the vesting periods of the respective awards. Total compensation expense recorded for employee RSUs was $2.3 million and $2.1 million for the three months ended June 30, 2018 , and 2017 , respectively, and was $5.0 million and $4.6 million for the six months ended June 30, 2018 , and 2017 , respectively. As of June 30, 2018 , there was $12.8 million of total unrecognized compensation expense related to non-vested RSU awards, which is being amortized through 2020. There were no material changes to the outstanding and non-vested RSUs during the six months ended June 30, 2018 . Subsequent to June 30, 2018 , the Company granted 534,770 RSUs with a fair value of $13.7 million . These RSUs generally vest one-third of the total grant on each of the next three anniversary dates of the grant. Also, subsequent to June 30, 2018 , the Company settled 406,013 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 290,584 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. 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. There were 100,249 and 123,678 shares issued under the ESPP during the second quarters of 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 six months ended June 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	6 Months Ended
	Jun. 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 Six Months Ended 2018 2017 2018 2017 (in thousands) Service cost $ 1,705 $ 1,269 $ 3,365 $ 3,319 Interest cost 637 617 1,310 1,344 Expected return on plan assets that reduces periodic pension benefit cost (370 ) (563 ) (931 ) (1,122 ) Amortization of prior service cost 5 5 9 9 Amortization of net actuarial loss 340 253 664 649 Net periodic benefit cost $ 2,317 $ 1,581 $ 4,417 $ 4,199 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 $6.1 million to the Qualified Pension Plan during the six months ended June 30, 2018 .

Earnings per Share

Earnings per Share	6 Months Ended
	Jun. 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 six months ended June 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 Six Months Ended 2018 2017 2018 2017 (in thousands) Anti-dilutive — 44 — 59 The following table sets forth the calculations of basic and diluted net income (loss) per common share: For the Three Months Ended For the Six Months Ended 2018 2017 2018 2017 (in thousands, except per share data) Net income (loss) $ 17,197 $ (119,907 ) $ 334,598 $ (45,473 ) Basic weighted-average common shares outstanding 111,701 111,277 111,698 111,274 Dilutive effect of non-vested RSUs and contingent PSUs 1,929 — 1,569 — Dilutive effect of Senior Convertible Notes — — — — Diluted weighted-average common shares outstanding 113,630 111,277 113,267 111,274 Basic net income (loss) per common share $ 0.15 $ (1.08 ) $ 3.00 $ (0.41 ) Diluted net income (loss) per common share $ 0.15 $ (1.08 ) $ 2.95 $ (0.41 )

Derivative Financial Instrument

Derivative Financial Instruments	6 Months Ended
	Jun. 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 June 30, 2018 , all derivative counterparties were members of the Company’s credit facility lender group and all contracts were entered into for other-than-trading purposes. The Company’s commodity derivative contracts consist of swap and collar arrangements for oil and 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 June 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) Third quarter 2018 1,769 $ 49.77 Fourth quarter 2018 1,894 $ 49.87 2019 1,940 $ 50.70 Total 5,603 Oil Collars Contract Period NYMEX WTI Volumes Weighted- Average Floor Price Weighted- Average Ceiling Price (MBbl) (per Bbl) (per Bbl) Third quarter 2018 1,948 $ 50.00 $ 58.61 Fourth quarter 2018 2,222 $ 50.00 $ 58.44 2019 10,055 $ 50.59 $ 63.62 2020 366 $ 55.00 $ 67.01 Total 14,591 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) Third quarter 2018 3,018 $ (1.06 ) — $ — Fourth quarter 2018 3,327 $ (1.08 ) — $ — 2019 11,217 $ (3.36 ) — $ — 2020 7,250 $ (1.13 ) 1,288 $ (7.97 ) 2021 — $ — 1,460 $ (7.80 ) 2022 — $ — 274 $ (7.67 ) Total 24,812 3,022 ____________________________________________ (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) Third quarter 2018 28,218 $ 3.25 (7,480 ) $ 4.23 20,738 $ 2.90 Fourth quarter 2018 28,204 $ 3.27 (7,210 ) $ 4.27 20,994 $ 2.92 2019 41,394 $ 3.87 (24,415 ) $ 4.34 16,979 $ 2.92 Total 97,816 (39,105 ) 58,711 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 Total 14,242 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) Third quarter 2018 1,033 $ 10.99 610 $ 24.27 93 $ 35.70 70 $ 35.07 202 $ 51.13 Fourth quarter 2018 1,146 $ 11.18 671 $ 24.39 102 $ 35.70 76 $ 35.07 208 $ 50.99 2019 3,533 $ 12.31 1,503 $ 27.83 154 $ 35.64 117 $ 35.70 197 $ 50.93 2020 539 $ 11.13 — $ — — $ — — $ — — $ — Total 6,251 2,784 349 263 607 Commodity Derivative Contracts Entered Into Subsequent to June 30, 2018 Subsequent to June 30, 2018 , the Company entered into various commodity derivative contracts, as summarized below: • NYMEX WTI costless collar contracts for 2020 for a total of 0.8 MMBbl of oil production with contract floor prices of $55.00 per Bbl and contract ceiling prices ranging from $64.50 per Bbl to $67.67 per Bbl; • fixed price NYMEX WTI-ICE Brent basis swap contracts for 2020 for a total of 0.6 MMBbl of oil production at contract prices ranging from ($8.06) per Bbl to ($8.15) per Bbl; • fixed price NYMEX WTI-ICE Brent basis swap contracts for 2021 for a total of 1.8 MMBbl of oil production at contract prices ranging from ($7.75) per Bbl to ($8.00) per Bbl; • fixed price NYMEX WTI-ICE Brent basis swap contracts for 2022 for a total of 2.6 MMBbl of oil production at contract prices ranging from ($7.60) per Bbl to ($7.90) per Bbl; and • fixed price OPIS Propane Mont Belvieu Non-TET swap contracts for 2019 for a total of 0.5 MMBbl of NGL production at contract prices ranging from $32.21 per Bbl to $32.26 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 $149.4 million and $139.4 million as of June 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 June 30, 2018 As of December 31, 2017 (in thousands) Derivative assets: Current assets $ 146,329 $ 64,266 Noncurrent assets 31,151 40,362 Total derivative assets $ 177,480 $ 104,628 Derivative liabilities: Current liabilities $ 259,338 $ 172,582 Noncurrent liabilities 67,583 71,402 Total derivative liabilities $ 326,921 $ 243,984 Offsetting of Derivative Assets and Liabilities As of June 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 June 30, December 31, 2017 June 30, December 31, 2017 (in thousands) Gross amounts presented in the accompanying balance sheets $ 177,480 $ 104,628 $ (326,921 ) $ (243,984 ) Amounts not offset in the accompanying balance sheets (147,009 ) (100,035 ) 147,009 100,035 Net amounts $ 30,471 $ 4,593 $ (179,912 ) $ (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 Six Months Ended 2018 2017 2018 2017 (in thousands) Derivative settlement (gain) loss: Oil contracts $ 24,430 $ 2,754 $ 45,178 $ 11,838 Gas contracts 757 (21,751 ) (5,653 ) (39,257 ) NGL contracts 11,478 2,694 21,668 11,109 Total derivative settlement (gain) loss $ 36,665 $ (16,303 ) $ 61,193 $ (16,310 ) Net derivative (gain) loss: Oil contracts $ 22,402 $ (38,194 ) $ 36,368 $ (87,784 ) Gas contracts 7,000 (6,038 ) 16,990 (50,506 ) NGL contracts 34,347 (10,957 ) 17,920 (31,673 ) Total net derivative (gain) loss $ 63,749 $ (55,189 ) $ 71,278 $ (169,963 ) Credit Related Contingent Features As of June 30, 2018 , and through the filing of this report, all of the Company’s derivative counterparties were members of the Company’s credit facility lender group. Under the Credit Agreement and derivative contracts, the Company is required to secure mortgages on assets having a value equal to at least 90 percent of the total PV-9 of the Company’s proved oil and gas properties evaluated in the most recent reserve report.

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 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 June 30, 2018 : Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 177,480 $ — Liabilities: Derivatives (1) $ — $ 326,921 $ — __________________________________________ (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. The calculation of the discount rates is based on the best information available and the rates used ranged from 10 percent to 15 percent based on the reservoir-specific weightings of future estimated proved and unproved cash flows as of June 30, 2018 , and December 31, 2017 . The Company believes the discount rates are representative of current market conditions and considers estimates of future cash payments, reserve categories, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The prices for oil and gas are forecast based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLs are forecast using OPIS pricing, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. There were no material impairments of proved properties during the three and six months ended June 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 six months ended June 30, 2018 , the Company recorded $11.9 million and $17.6 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 or six months ended June 30, 2017 . Oil and gas properties held for sale. Proved and unproved oil and gas properties classified as held for sale, including the corresponding asset retirement obligation liability, are valued using a market approach, based on an estimated net selling price, as evidenced by the most current bid prices received from third parties, if available. If an estimated selling price is not available, the Company utilizes the various income valuation techniques discussed above. Any initial write-down and subsequent changes to the fair value less estimated cost to sell is included within the net gain (loss) on divestiture activity line item in the accompanying statements of operations. There were no material assets held for sale that were recorded at fair value as of June 30, 2018 , or as of December 31, 2017 . For the six months ended June 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 as well as in the 2017 Form 10-K for more information regarding the Company’s oil and gas properties held for sale . Long-Term Debt The following table reflects the fair value of the Senior Notes and Senior Convertible Notes measured using Level 1 inputs based on quoted secondary market trading prices. These notes were not presented at fair value on the accompanying balance sheets as of June 30, 2018 , or December 31, 2017 , as they were recorded at carrying value, net of any unamortized discounts and deferred financing costs. On July 16, 2018, the 2021 Senior Notes were redeemed. Please refer to Note 5 - Long-Term Debt for additional discussion. As of June 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 $ 352,634 $ 344,611 $ 351,682 6.125% Senior Notes due 2022 $ 561,796 $ 573,847 $ 561,796 $ 571,627 6.50% Senior Notes due 2023 $ 394,985 $ 401,380 $ 394,985 $ 403,434 5.0% Senior Notes due 2024 $ 500,000 $ 468,750 $ 500,000 $ 483,440 5.625% Senior Notes due 2025 $ 500,000 $ 485,000 $ 500,000 $ 494,355 6.75% Senior Notes due 2026 $ 500,000 $ 502,350 $ 500,000 $ 516,350 1.50% Senior Convertible Notes due 2021 $ 172,500 $ 178,446 $ 172,500 $ 168,291

Summary of Significant Accoun18

Summary of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 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 June 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.
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. The calculation of the discount rates is based on the best information available and the rates used ranged from 10 percent to 15 percent based on the reservoir-specific weightings of future estimated proved and unproved cash flows as of June 30, 2018 , and December 31, 2017 . The Company believes the discount rates are representative of current market conditions and considers estimates of future cash payments, reserve categories, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The prices for oil and gas are forecast based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLs are forecast using OPIS pricing, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. There were no material impairments of proved properties during the three and six months ended June 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 six months ended June 30, 2018 , the Company recorded $11.9 million and $17.6 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 or six months ended June 30, 2017 . Oil and gas properties held for sale. Proved and unproved oil and gas properties classified as held for sale, including the corresponding asset retirement obligation liability, are valued using a market approach, based on an estimated net selling price, as evidenced by the most current bid prices received from third parties, if available. If an estimated selling price is not available, the Company utilizes the various income valuation techniques discussed above. Any initial write-down and subsequent changes to the fair value less estimated cost to sell is included within the net gain (loss) on divestiture activity line item in the accompanying statements of operations. There were no material assets held for sale that were recorded at fair value as of June 30, 2018 , or as of December 31, 2017 . For the six months ended June 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 as well as in the 2017 Form 10-K for more information regarding the Company’s oil and gas properties held for sale .
New Accounting Pronouncements, 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. 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 six months ended June 30, 2017 , are summarized as follows: For the Six Months Ended June 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 $ 242,115 $ 242,128 Cash flows from investing activities: Other, net $ 3,000 N/A Net cash provided by (used in) investing activities $ 314,364 $ 311,364 Cash flows from financing activities: Cash paid for extinguishment of debt N/A $ (13 ) Net cash used in financing activities $ (6,330 ) $ (6,343 ) Net change in cash and cash equivalents $ 550,149 N/A Net change in cash, cash equivalents, and restricted cash N/A $ 547,149 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 $ 559,521 N/A Cash, cash equivalents, and restricted cash at end of period N/A $ 559,521 The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the accompanying balance sheets: As of June 30, 2018 As of December 31, 2017 (in thousands) Cash and cash equivalents $ 615,906 $ 313,943 Restricted cash — — Total cash, cash equivalents, and restricted cash $ 615,906 $ 313,943 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 six months ended June 30, 2017 , are summarized as follows: For the Three Months Ended June 30, 2017 For the Six Months Ended June 30, 2017 As Reported As Adjusted As Reported As Adjusted (in thousands) Operating expenses: Exploration $ 13,072 $ 12,983 $ 25,050 $ 24,800 General and administrative $ 28,460 $ 28,237 $ 57,684 $ 57,054 Total operating expenses $ 268,359 $ 268,047 $ 475,504 $ 474,624 Income (loss) from operations $ (147,638 ) $ (147,326 ) $ 17,955 $ 18,835 Other non-operating income, net $ 1,265 $ 953 $ 1,600 $ 720 Effective January 1, 2018, the Company early adopted 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. Under ASU 2016-02, companies are permitted to make a policy election to not recognize lease assets or liabilities when the term of the lease is less than twelve months. For agreements that contain both lease and non-lease components, companies are also permitted to make a policy election to combine both the lease and non-lease components together and account for these arrangements as a single lease. 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. Further, the Company is also evaluating policies, controls, and processes that will be necessary to support the additional accounting and disclosure requirements. The Company is also in the process of designing and implementing a lease administration system that will support the on-going maintenance and accounting for leases after adoption. The Company will adopt ASU 2016-02 on January 1, 2019, and plans on 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 is currently evaluating ASU 2018-11 as part of its overall assessment of ASU 2016-02, and will adopt ASU 2018-11 at the same time it adopts ASU 2016-02. 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 June 30, 2018 , and through the filing of this report.

Summary of Significant Accoun19

Summary of Significant Accounting Policies (Tables)	6 Months Ended
	Jun. 30, 2018
Accounting Policies [Abstract]
Schedule of New Accounting Pronouncements and Changes in Accounting Principles	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 six months ended June 30, 2017 , are summarized as follows: For the Six Months Ended June 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 $ 242,115 $ 242,128 Cash flows from investing activities: Other, net $ 3,000 N/A Net cash provided by (used in) investing activities $ 314,364 $ 311,364 Cash flows from financing activities: Cash paid for extinguishment of debt N/A $ (13 ) Net cash used in financing activities $ (6,330 ) $ (6,343 ) Net change in cash and cash equivalents $ 550,149 N/A Net change in cash, cash equivalents, and restricted cash N/A $ 547,149 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 $ 559,521 N/A Cash, cash equivalents, and restricted cash at end of period N/A $ 559,521 The accompanying statements of operations line items that were adjusted as a result of the adoption of ASU 2017-07 for the three and six months ended June 30, 2017 , are summarized as follows: For the Three Months Ended June 30, 2017 For the Six Months Ended June 30, 2017 As Reported As Adjusted As Reported As Adjusted (in thousands) Operating expenses: Exploration $ 13,072 $ 12,983 $ 25,050 $ 24,800 General and administrative $ 28,460 $ 28,237 $ 57,684 $ 57,054 Total operating expenses $ 268,359 $ 268,047 $ 475,504 $ 474,624 Income (loss) from operations $ (147,638 ) $ (147,326 ) $ 17,955 $ 18,835 Other non-operating income, net $ 1,265 $ 953 $ 1,600 $ 720
Schedule of cash and cash equivalents, and restricted cash	The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the accompanying balance sheets: As of June 30, 2018 As of December 31, 2017 (in thousands) Cash and cash equivalents $ 615,906 $ 313,943 Restricted cash — — Total cash, cash equivalents, and restricted cash $ 615,906 $ 313,943

Revenue from Contracts with C20

Revenue from Contracts with Customers (Tables)	6 Months Ended
	Jun. 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 six months ended June 30, 2018 , and 2017: Permian South Texas & Gulf Coast Rocky Mountain Total Three Months Ended June 30, Three Months Ended June 30, Three Months Ended June 30, Three Months Ended June 30, 2018 2017 2018 2017 2018 2017 2018 2017 (in thousands) Oil, gas, and NGL production revenue: Oil production revenue $ 227,636 $ 78,554 $ 19,346 $ 13,072 $ 19,168 $ 37,248 $ 266,150 $ 128,874 Gas production revenue 31,734 12,937 52,235 87,760 95 1,043 84,064 101,740 NGL production revenue 129 107 52,248 53,558 (33 ) 660 52,344 54,325 Total $ 259,499 $ 91,598 $ 123,829 $ 154,390 $ 19,230 $ 38,951 $ 402,558 $ 284,939 Relative percentage 64 % 32 % 31 % 54 % 5 % 14 % 100 % 100 % ____________________________________________ Note: Amounts may not calculate due to rounding. Permian South Texas & Gulf Coast Rocky Mountain Total Six Months Ended June 30, Six Months Ended June 30, Six Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 2018 2017 2018 2017 (in thousands) Oil, gas, and NGL production revenue: Oil production revenue $ 433,430 $ 160,053 $ 38,929 $ 51,936 $ 54,851 $ 84,509 $ 527,210 $ 296,498 Gas production revenue 56,611 24,246 104,968 175,961 1,594 2,714 163,173 202,921 NGL production revenue 253 254 94,018 116,915 790 1,549 95,061 118,718 Total $ 490,294 $ 184,553 $ 237,915 $ 344,812 $ 57,235 $ 88,772 $ 785,444 $ 618,137 Relative percentage 63 % 30 % 30 % 56 % 7 % 14 % 100 % 100 % ____________________________________________ Note: Amounts may not calculate due to rounding.

Divestitures, Assets Held for21

Divestitures, Assets Held for Sale, and Acquisitions (Tables)	6 Months Ended
	Jun. 30, 2018
Divestitures, Assets Held for Sale, and Acquisitions [Abstract]
Disposal Groups, Including Discontinued Operations [Table Text Block]	The following table presents loss before income taxes from the Divide County, North Dakota assets sold for the three and six months ended June 30, 2018 , and 2017. The Divide County Divestiture was considered a disposal of a significant asset group. For the Three Months Ended June 30, For the Six Months Ended June 30, 2018 2017 2018 2017 (in thousands) Loss before income taxes (1) $ (17,478 ) $ (153,442 ) $ (28,975 ) $ (486,161 ) ____________________________________________ (1) 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)	6 Months Ended
	Jun. 30, 2018
Income Tax Disclosure [Abstract]
Schedule of provision for income taxes	The provision for income taxes for the three and six months ended June 30, 2018 , and 2017 , consisted of the following: For the Three Months Ended For the Six Months Ended 2018 2017 2018 2017 (in thousands) Current portion of income tax (expense) benefit: Federal $ — $ 4,607 $ — $ (2,832 ) State 40 2,439 (585 ) (1,403 ) Deferred portion of income tax (expense) benefit 861 64,015 (97,505 ) 30,790 Income tax (expense) benefit $ 901 $ 71,061 $ (98,090 ) $ 26,555 Effective tax rate (5.5 )% 37.2 % 22.7 % 36.9 %

Long-Term Debt (Tables)

Long-Term Debt (Tables)	6 Months Ended
	Jun. 30, 2018
Debt Disclosure [Abstract]
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 July 25, 2018 , June 30, 2018 , and December 31, 2017 : As of July 25, 2018 As of June 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 $2.4 million and $3.1 million as of June 30, 2018 , and December 31, 2017 , respectively. (2) Letters of credit outstanding reduce the amount available under the credit facility on a dollar-for-dollar basis.
Schedule of Senior Notes [Table Text Block]	The current portion of Senior Notes, net of unamortized deferred financing costs and noncurrent portion of Senior Notes, net of unamortized deferred financing costs lines on the accompanying balance sheets as of June 30, 2018 , and December 31, 2017 , consisted of the following: As of June 30, 2018 As of December 31, 2017 Principal Amount Unamortized Deferred Financing Costs Senior Notes, Net of Unamortized Deferred Financing Costs Principal Amount Unamortized Deferred Financing Costs Senior Notes, Net of Unamortized Deferred Financing Costs (in thousands) 6.50% Senior Notes due 2021 $ 344,611 $ 2,310 $ 342,301 $ 344,611 $ 2,656 $ 341,955 6.125% Senior Notes due 2022 561,796 5,211 556,585 561,796 5,800 555,996 6.50% Senior Notes due 2023 394,985 3,342 391,643 394,985 3,707 391,278 5.0% Senior Notes due 2024 500,000 5,149 494,851 500,000 5,610 494,390 5.625% Senior Notes due 2025 500,000 6,261 493,739 500,000 6,714 493,286 6.75% Senior Notes due 2026 500,000 6,824 493,176 500,000 7,242 492,758 Total $ 2,801,392 $ 29,097 $ 2,772,295 $ 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 June 30, 2018 , and December 31, 2017 , consisted of the following: As of June 30, 2018 As of December 31, 2017 (in thousands) Principal amount of Senior Convertible Notes $ 172,500 $ 172,500 Unamortized debt discount (26,319 ) (30,183 ) Unamortized deferred financing costs (2,751 ) (3,210 ) Senior Convertible Notes, net of unamortized discount and deferred financing costs $ 143,430 $ 139,107

Pension Benefits (Tables)

Pension Benefits (Tables)	6 Months Ended
	Jun. 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 Six Months Ended 2018 2017 2018 2017 (in thousands) Service cost $ 1,705 $ 1,269 $ 3,365 $ 3,319 Interest cost 637 617 1,310 1,344 Expected return on plan assets that reduces periodic pension benefit cost (370 ) (563 ) (931 ) (1,122 ) Amortization of prior service cost 5 5 9 9 Amortization of net actuarial loss 340 253 664 649 Net periodic benefit cost $ 2,317 $ 1,581 $ 4,417 $ 4,199

Earnings per Share (Tables)

Earnings per Share (Tables)	6 Months Ended
	Jun. 30, 2018
Earnings Per Share [Abstract]
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share [Table Text Block]	The following table presents the weighted-average anti-dilutive securities for the periods presented: For the Three Months Ended For the Six Months Ended 2018 2017 2018 2017 (in thousands) Anti-dilutive — 44 — 59
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 Six Months Ended 2018 2017 2018 2017 (in thousands, except per share data) Net income (loss) $ 17,197 $ (119,907 ) $ 334,598 $ (45,473 ) Basic weighted-average common shares outstanding 111,701 111,277 111,698 111,274 Dilutive effect of non-vested RSUs and contingent PSUs 1,929 — 1,569 — Dilutive effect of Senior Convertible Notes — — — — Diluted weighted-average common shares outstanding 113,630 111,277 113,267 111,274 Basic net income (loss) per common share $ 0.15 $ (1.08 ) $ 3.00 $ (0.41 ) Diluted net income (loss) per common share $ 0.15 $ (1.08 ) $ 2.95 $ (0.41 )

Derivative Financial Instrume26

Derivative Financial Instruments (Tables)	6 Months Ended
	Jun. 30, 2018
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Schedule of notional amounts of outstanding derivative positions	As of June 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) Third quarter 2018 1,769 $ 49.77 Fourth quarter 2018 1,894 $ 49.87 2019 1,940 $ 50.70 Total 5,603 Oil Collars Contract Period NYMEX WTI Volumes Weighted- Average Floor Price Weighted- Average Ceiling Price (MBbl) (per Bbl) (per Bbl) Third quarter 2018 1,948 $ 50.00 $ 58.61 Fourth quarter 2018 2,222 $ 50.00 $ 58.44 2019 10,055 $ 50.59 $ 63.62 2020 366 $ 55.00 $ 67.01 Total 14,591 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) Third quarter 2018 3,018 $ (1.06 ) — $ — Fourth quarter 2018 3,327 $ (1.08 ) — $ — 2019 11,217 $ (3.36 ) — $ — 2020 7,250 $ (1.13 ) 1,288 $ (7.97 ) 2021 — $ — 1,460 $ (7.80 ) 2022 — $ — 274 $ (7.67 ) Total 24,812 3,022 ____________________________________________ (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) Third quarter 2018 28,218 $ 3.25 (7,480 ) $ 4.23 20,738 $ 2.90 Fourth quarter 2018 28,204 $ 3.27 (7,210 ) $ 4.27 20,994 $ 2.92 2019 41,394 $ 3.87 (24,415 ) $ 4.34 16,979 $ 2.92 Total 97,816 (39,105 ) 58,711 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 Total 14,242 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) Third quarter 2018 1,033 $ 10.99 610 $ 24.27 93 $ 35.70 70 $ 35.07 202 $ 51.13 Fourth quarter 2018 1,146 $ 11.18 671 $ 24.39 102 $ 35.70 76 $ 35.07 208 $ 50.99 2019 3,533 $ 12.31 1,503 $ 27.83 154 $ 35.64 117 $ 35.70 197 $ 50.93 2020 539 $ 11.13 — $ — — $ — — $ — — $ — Total 6,251 2,784 349 263 607
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 June 30, 2018 As of December 31, 2017 (in thousands) Derivative assets: Current assets $ 146,329 $ 64,266 Noncurrent assets 31,151 40,362 Total derivative assets $ 177,480 $ 104,628 Derivative liabilities: Current liabilities $ 259,338 $ 172,582 Noncurrent liabilities 67,583 71,402 Total derivative liabilities $ 326,921 $ 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 June 30, December 31, 2017 June 30, December 31, 2017 (in thousands) Gross amounts presented in the accompanying balance sheets $ 177,480 $ 104,628 $ (326,921 ) $ (243,984 ) Amounts not offset in the accompanying balance sheets (147,009 ) (100,035 ) 147,009 100,035 Net amounts $ 30,471 $ 4,593 $ (179,912 ) $ (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 Six Months Ended 2018 2017 2018 2017 (in thousands) Derivative settlement (gain) loss: Oil contracts $ 24,430 $ 2,754 $ 45,178 $ 11,838 Gas contracts 757 (21,751 ) (5,653 ) (39,257 ) NGL contracts 11,478 2,694 21,668 11,109 Total derivative settlement (gain) loss $ 36,665 $ (16,303 ) $ 61,193 $ (16,310 ) Net derivative (gain) loss: Oil contracts $ 22,402 $ (38,194 ) $ 36,368 $ (87,784 ) Gas contracts 7,000 (6,038 ) 16,990 (50,506 ) NGL contracts 34,347 (10,957 ) 17,920 (31,673 ) Total net derivative (gain) loss $ 63,749 $ (55,189 ) $ 71,278 $ (169,963 )

Fair Value Measurements Fair Va

Fair Value Measurements Fair Value Measurements (Tables)	6 Months Ended
	Jun. 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 June 30, 2018 : Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 177,480 $ — Liabilities: Derivatives (1) $ — $ 326,921 $ — __________________________________________ (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 Senior Notes and Senior Convertible Notes measured using Level 1 inputs based on quoted secondary market trading prices. These notes were not presented at fair value on the accompanying balance sheets as of June 30, 2018 , or December 31, 2017 , as they were recorded at carrying value, net of any unamortized discounts and deferred financing costs. On July 16, 2018, the 2021 Senior Notes were redeemed. Please refer to Note 5 - Long-Term Debt for additional discussion. As of June 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 $ 352,634 $ 344,611 $ 351,682 6.125% Senior Notes due 2022 $ 561,796 $ 573,847 $ 561,796 $ 571,627 6.50% Senior Notes due 2023 $ 394,985 $ 401,380 $ 394,985 $ 403,434 5.0% Senior Notes due 2024 $ 500,000 $ 468,750 $ 500,000 $ 483,440 5.625% Senior Notes due 2025 $ 500,000 $ 485,000 $ 500,000 $ 494,355 6.75% Senior Notes due 2026 $ 500,000 $ 502,350 $ 500,000 $ 516,350 1.50% Senior Convertible Notes due 2021 $ 172,500 $ 178,446 $ 172,500 $ 168,291

Summary of Significant Accoun28

Summary of Significant Accounting Policies (Details) - USD ($) $ in Thousands		3 Months Ended			6 Months Ended
		Jun. 30, 2018	Mar. 31, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Statement of Cash Flows [Abstract]
Non-cash (gain) loss on extinguishment of debt, net					$ 0	$ 22
Loss on extinguishment of debt		$ 0		$ 0	0	35
Net cash provided by operating activities					311,518	242,128
Net cash provided by (used in) investing activities					(5,719)	311,364
Cash paid for extinguishment of debt					0	(13)
Net cash used in financing activities					(3,836)	(6,343)
Net change in cash, cash equivalents, and restricted cash						547,149
Cash, cash equivalents, and restricted cash at beginning of period	[1]		$ 313,943		313,943	12,372
Cash, cash equivalents, and restricted cash at end of period	[1]	615,906		559,521	615,906	559,521
Income Statement [Abstract]
Net income (loss)		17,197		(119,907)	334,598	(45,473)
Depreciation, depletion, amortization and asset retirement liability accretion expense		151,765		153,232	282,238	291,044
Exploration		14,056		12,983	27,783	24,800
General and administrative		28,920		28,237	56,602	57,054
Total operating expenses		387,768		268,047	698,295	474,624
Income (loss) from operations		56,148		(147,326)	515,216	18,835
Other non-operating income, net		1,802		953	$ 2,211	720
Scenario, Previously Reported [Member]
Statement of Cash Flows [Abstract]
Non-cash (gain) loss on extinguishment of debt, net						22
Net cash provided by operating activities						242,115
Other, net						3,000
Net cash provided by (used in) investing activities						314,364
Net cash used in financing activities						(6,330)
Net change in cash and cash equivalents						550,149
Cash and cash equivalents at beginning of period						9,372
Cash and cash equivalents at end of period				559,521		559,521
Income Statement [Abstract]
Exploration				13,072		25,050
General and administrative				28,460		57,684
Total operating expenses				268,359		475,504
Income (loss) from operations				(147,638)		17,955
Other non-operating income, net				$ 1,265		$ 1,600
Correction of Immaterial Errors Before Tax [Member]
Income Statement [Abstract]
Assets held for sale, loss (gain) on write-down		17,700
Depreciation, depletion, amortization and asset retirement liability accretion expense		6,700
Correction of Immaterial Errors After Tax [Member]
Income Statement [Abstract]
Assets held for sale, loss (gain) on write-down		13,700
Depreciation, depletion, amortization and asset retirement liability accretion expense		5,200
Overstatement of Net Income After Tax [Member]
Income Statement [Abstract]
Net income (loss)			$ 18,900
Understatement of Net Income After Tax [Member]
Income Statement [Abstract]
Net income (loss)		$ 18,900
[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 Accoun29

Summary of Significant Accounting Policies Reconciliation (Details) - USD ($) $ in Thousands		Jan. 01, 2018	Jun. 30, 2018	Dec. 31, 2017	Jun. 30, 2017	Dec. 31, 2016
Cash and Cash Equivalents [Abstract]
Cash and cash equivalents			$ 615,906	$ 313,943
Restricted cash			0	0
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Including Disposal Group and Discontinued Operations	[1]		$ 615,906	$ 313,943	$ 559,521	$ 12,372
Accounting Standards Update 2018-02 [Member]
Prior Period Adjustments Restatement [Line Items]
Cumulative effect of accounting change		$ 3,000
[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”).

Revenue from Contracts with C30

Revenue from Contracts with Customers - Disaggregation of Revenue (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Segment Reporting Information [Line Items]
Oil production revenue	$ 266,150	$ 128,874	$ 527,210	$ 296,498
Gas production revenue	84,064	101,740	163,173	202,921
NGL production revenue	52,344	54,325	95,061	118,718
Total oil, gas, and NGL production revenue	402,558	284,939	785,444	618,137
Revenue, Remaining Performance Obligation	0		0
Permian
Segment Reporting Information [Line Items]
Oil production revenue	227,636	78,554	433,430	160,053
Gas production revenue	31,734	12,937	56,611	24,246
NGL production revenue	129	107	253	254
Total oil, gas, and NGL production revenue	259,499	91,598	490,294	184,553
South Texas & Gulf Coast
Segment Reporting Information [Line Items]
Oil production revenue	19,346	13,072	38,929	51,936
Gas production revenue	52,235	87,760	104,968	175,961
NGL production revenue	52,248	53,558	94,018	116,915
Total oil, gas, and NGL production revenue	123,829	154,390	237,915	344,812
Rocky Mountain
Segment Reporting Information [Line Items]
Oil production revenue	19,168	37,248	54,851	84,509
Gas production revenue	95	1,043	1,594	2,714
NGL production revenue	(33)	660	790	1,549
Total oil, gas, and NGL production revenue	$ 19,230	$ 38,951	$ 57,235	$ 88,772
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	64.00%	32.00%	63.00%	30.00%
Sales Revenue, Net | Geographic Concentration Risk | South Texas & Gulf Coast
Segment Reporting Information [Line Items]
Relative percentage	31.00%	54.00%	30.00%	56.00%
Sales Revenue, Net | Geographic Concentration Risk | Rocky Mountain
Segment Reporting Information [Line Items]
Relative percentage	5.00%	14.00%	7.00%	14.00%

Revenue from Contracts with C31

Revenue from Contracts with Customers Accounts Receivable from Customers (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable	$ 178,682	$ 160,154
Accrued Income Receivable [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable	$ 115,000	$ 96,600

Divestitures, Assets Held for32

Divestitures, Assets Held for Sale, and Acquisitions Divestitures and Assets Held for Sale (Details) $ in Thousands		Mar. 26, 2018USD ($)a	Mar. 10, 2017USD ($)	Jun. 30, 2018USD ($)	Jun. 30, 2017USD ($)	Mar. 31, 2017USD ($)	Jun. 30, 2018USD ($)	Jun. 30, 2017USD ($)	Dec. 31, 2017USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Non-cash (gain) loss on extinguishment of debt, net							$ 0	$ 22
Net divestiture proceeds							742,215	766,247
Net gain on divestiture activity				$ 39,501	$ (167,133)		424,870	(129,670)
Oil and gas properties held for sale, net				5,040			5,040		$ 111,700
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]
Loss before income taxes	[1]			(17,478)	(153,442)		(28,975)	(486,161)
Disposal Group, Held-for-sale, Not Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Oil and gas properties held for sale, net				5,000			5,000
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					166,900	$ 359,600		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
Net Divestiture Proceeds Received at Closing [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			$ 747,400
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							410,100
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							$ 15,700
Estimated 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								$ 397,400
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					$ 24,600
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) 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 for33

Divestitures, Assets Held for Sale, and Acquisitions Acquisitions (Details) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2018USD ($)a	Jun. 30, 2018USD ($)	Jun. 30, 2017USD ($)a
Business Acquisition [Line Items]
Payments to Acquire Oil and Gas Property and Equipment		$ 24,615	$ 88,140
Noncash or Part Noncash Acquisition, Net Nonmonetary Assets Acquired (Liabilities Assumed)		$ 0
Other Howard and Martin Counties Trades [Member]
Business Acquisition [Line Items]
Non-monetary Trade, Acreage Acquired | a			6,550
Non-monetary Trade, Acreage Exchanged | a			5,700
Noncash or Part Noncash Acquisition, Net Nonmonetary Assets Acquired (Liabilities Assumed)			$ 279,750
Gain or loss recognized on trade			0
Other Martin County Acquisition 2018 [Member]
Business Acquisition [Line Items]
Payments to Acquire Oil and Gas Property and Equipment	$ 24,600
Net Acres Acquired | a	720
Other Howard and Martin Counties Acquisitions 2017 [Member]
Business Acquisition [Line Items]
Payments to Acquire Oil and Gas Property and Equipment			$ 72,300
Net Acres Acquired | a			3,400

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Components of the provision for income taxes
Federal	$ 0	$ 4,607	$ 0	$ (2,832)
State	40	2,439	(585)	(1,403)
Deferred portion of income tax (expense) benefit	861	64,015	(97,505)	30,790
Income tax (expense) benefit	$ 901	$ 71,061	$ (98,090)	$ 26,555
Effective tax rate	(5.50%)	37.20%	22.70%	36.90%
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) - USD ($) $ in Thousands		Jul. 25, 2018	Jun. 30, 2018	Apr. 24, 2018	Dec. 31, 2017
Line of Credit Facility [Line Items]
Credit facility balance			$ 0		$ 0
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			1,300,000	$ 1,400,000
Line of credit agreement, aggregate lender commitments			1,000,000	$ 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			$ 2,400		$ 3,100
Subsequent Event [Member] | Line of Credit [Member] | Revolving Credit Facility [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
[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 $2.4 million and $3.1 million as of June 30, 2018, and December 31, 2017, respectively.
[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	Jul. 16, 2018	Jun. 15, 2018	Sep. 30, 2018	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Debt Instrument [Line Items]
Loss on extinguishment of debt				$ 0	$ 0	$ 0	$ (35)
Non-cash loss on extinguishment of debt						0	22
Cash paid for extinguishment of debt						0	$ 13
Current portion of Senior Notes, net of unamortized deferred financing costs (note 5)				342,301		342,301		$ 0
Senior Notes, net of unamortized deferred financing costs				$ 2,429,994		$ 2,429,994		2,769,663
6.50% Senior Notes due 2021
Debt Instrument [Line Items]
Senior Notes, interest rate, stated percentage				6.50%		6.50%
Unamortized Deferred Financing Costs				$ (2,310)		$ (2,310)		(2,656)
6.125% Senior Notes due 2022
Debt Instrument [Line Items]
Senior Notes, interest rate, stated percentage				6.125%		6.125%
Unamortized Deferred Financing Costs				$ (5,211)		$ (5,211)		(5,800)
6.50% Senior Notes due 2023
Debt Instrument [Line Items]
Senior Notes, interest rate, stated percentage				6.50%		6.50%
Unamortized Deferred Financing Costs				$ (3,342)		$ (3,342)		(3,707)
5.0% Senior Notes due 2024
Debt Instrument [Line Items]
Senior Notes, interest rate, stated percentage				5.00%		5.00%
Unamortized Deferred Financing Costs				$ (5,149)		$ (5,149)		(5,610)
5.625% Senior Notes due 2025
Debt Instrument [Line Items]
Senior Notes, interest rate, stated percentage				5.625%		5.625%
Unamortized Deferred Financing Costs				$ (6,261)		$ (6,261)		(6,714)
6.75% Senior Notes due 2026
Debt Instrument [Line Items]
Senior Notes, interest rate, stated percentage				6.75%		6.75%
Unamortized Deferred Financing Costs				$ (6,824)		$ (6,824)		(7,242)
Senior Notes [Member]
Debt Instrument [Line Items]
Principal Amount				2,801,392		2,801,392		2,801,392
Unamortized Deferred Financing Costs				(29,097)		(29,097)		(31,729)
Senior Notes, net of unamortized deferred financing costs				$ 2,772,295		$ 2,772,295		2,769,663
Senior Notes [Member] | 6.50% Senior Notes due 2021
Debt Instrument [Line Items]
Senior Notes, interest rate, stated percentage				6.50%		6.50%
Debt Instrument, Redemption Price, Percentage		102.167%
Principal Amount				$ 344,611		$ 344,611		344,611
Current portion of Senior Notes, net of unamortized deferred financing costs (note 5)				$ 342,301		$ 342,301
Senior Notes, net of unamortized deferred financing costs								341,955
Senior Notes [Member] | 6.125% Senior Notes due 2022
Debt Instrument [Line Items]
Senior Notes, interest rate, stated percentage				6.125%		6.125%
Principal Amount				$ 561,796		$ 561,796		561,796
Senior Notes, net of unamortized deferred financing costs				$ 556,585		$ 556,585		555,996
Senior Notes [Member] | 6.50% Senior Notes due 2023
Debt Instrument [Line Items]
Senior Notes, interest rate, stated percentage				6.50%		6.50%
Principal Amount				$ 394,985		$ 394,985		394,985
Senior Notes, net of unamortized deferred financing costs				$ 391,643		$ 391,643		391,278
Senior Notes [Member] | 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
Senior Notes, net of unamortized deferred financing costs				$ 494,851		$ 494,851		494,390
Senior Notes [Member] | 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
Senior Notes, net of unamortized deferred financing costs				$ 493,739		$ 493,739		493,286
Senior Notes [Member] | 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
Senior Notes, net of unamortized deferred financing costs				$ 493,176		$ 493,176		$ 492,758
Subsequent Event [Member] | Senior Notes [Member] | 6.50% Senior Notes due 2021
Debt Instrument [Line Items]
Debt Instrument, Repurchased Settlement Amount	$ 355,900
Loss on extinguishment of debt			$ 9,800
Non-cash loss on extinguishment of debt			2,300
Cash paid for extinguishment of debt			$ 7,500

Long-Term Debt Senior Convertib

Long-Term Debt Senior Convertible Notes (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Debt Instrument [Line Items]
Senior Convertible Notes, net carrying amount	$ 143,430		$ 143,430		$ 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	$ 5,200	$ 4,900
Senior Convertible Notes, unamortized debt discount	(26,319)		(26,319)		(30,183)
Unamortized deferred financing costs	(2,751)		(2,751)		(3,210)
Senior Convertible Notes, net carrying amount	$ 143,430		$ 143,430		$ 139,107

Commitments (Details)

Commitments (Details) MMcf in Thousands, $ in Millions	Jun. 30, 2018USD ($)MMcfMMBbls	Aug. 02, 2018USD ($)
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	$ 360.6
Drilling Rig Leasing Contracts [Member] | Subsequent Event [Member]
Other Commitments [Line Items]
Contractual obligation		$ 103.1
Early termination penalties for rig contracts		$ 40.4
Electricity Purchase Agreement [Member]
Other Commitments [Line Items]
Contractual obligation	$ 30.8
Crude Oil Pipeline Commitment [Member]
Other Commitments [Line Items]
Oil and gas delivery commitments, remaining minimum contractual volumes | MMBbls	31
Natural Gas Pipeline Commitment [Member]
Other Commitments [Line Items]
Oil and gas delivery commitments, remaining minimum contractual volumes | MMcf	737

Compensation Plans (Details)

Compensation Plans (Details)	1 Months Ended		3 Months Ended		6 Months Ended
	Aug. 02, 2018USD ($)shares	Jul. 25, 2018USD ($)shares	Jun. 30, 2018USD ($)shares	Jun. 30, 2017USD ($)shares	Jun. 30, 2018USD ($)shares	Jun. 30, 2017USD ($)shares
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			6,800,000		6,800,000
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense | $			$ 2,400,000	$ 1,700,000	$ 4,800,000	$ 4,200,000
Unrecognized stock based compensation expense | $			12,400,000		12,400,000
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense | $			2,300,000	$ 2,100,000	5,000,000	$ 4,600,000
Unrecognized stock based compensation expense | $			$ 12,800,000		$ 12,800,000
Number of shares represented by each RSU					1
Subsequent Event [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Multiplier applied to PSU awards at settlement	0
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	572,924
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
Subsequent Event [Member] | Performance Shares [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Multiplier applied to PSU awards at settlement	0
Subsequent Event [Member] | Performance Shares [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Multiplier applied to PSU awards at settlement	2
Subsequent Event [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period		534,770
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Granted in Period, Total Fair Value | $		$ 13,700,000
Stock Issued During Period, Shares, Share-based Compensation, Gross		406,013
Restricted Stock, Shares Issued Net of Shares for Tax Withholdings		290,584
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%
Share-based Compensation Arrangement by Share-based Payment Award, Maximum Employee Subscription | $			$ 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
Director [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period				8,794

Pension Benefits (Details)

Pension Benefits (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Components of Net Periodic Benefit Costs for the Pension Plans
Service cost	$ 1,705	$ 1,269	$ 3,365	$ 3,319
Interest cost	637	617	1,310	1,344
Expected return on plan assets that reduces periodic pension benefit cost	(370)	(563)	(931)	(1,122)
Amortization of prior service cost	5	5	9	9
Amortization of net actuarial loss	340	253	664	649
Net periodic benefit cost	$ 2,317	$ 1,581	$ 4,417	$ 4,199

Pension Benefits Pension (Detai

Pension Benefits Pension (Details) $ in Millions	6 Months Ended
	Jun. 30, 2018USD ($)
Pension Details [Abstract]
Pension Plans, Gain (Loss) Amortization Threshold	10.00%
Pension Contributions	$ 6.1

Earnings per Share (Details)

Earnings per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 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	0	44	0	59
Calculation of basic and diluted earnings per share
Net income (loss)	$ 17,197	$ (119,907)	$ 334,598	$ (45,473)
Basic weighted-average common shares outstanding	111,701	111,277	111,698	111,274
Dilutive effect of non-vested RSUs and contingent PSUs	1,929	0	1,569	0
Dilutive effect of Senior Convertible Notes	0	0	0	0
Diluted weighted-average common shares outstanding	113,630	111,277	113,267	111,274
Basic net income (loss) per common share	$ 0.15	$ (1.08)	$ 3	$ (0.41)
Diluted net income (loss) per common share	0.15	$ (1.08)	2.95	$ (0.41)
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 Instrume43

Derivative Financial Instruments (Details) bbl in Thousands, BTU in Billions		Aug. 02, 2018$ / Barrelsbbl	Jun. 30, 2018BTU$ / Barrels$ / EnergyContentbbl
NYMEX Oil Swap Contract Third Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			1,769
Derivative, Swap Type, Average Fixed Price			49.77
NYMEX Oil Swap Contract Fourth Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			1,894
Derivative, Swap Type, Average Fixed Price			49.87
NYMEX Oil Swap Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			1,940
Derivative, Swap Type, Average Fixed Price			50.70
NYMEX Oil Swap Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			5,603
NYMEX Oil Collar Contract Third Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			1,948
Derivative, Floor Price			50
Derivative, Ceiling Price			58.61
NYMEX Oil Collar Contract Fourth Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			2,222
Derivative, Floor Price			50
Derivative, Ceiling Price			58.44
NYMEX Oil Collar Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			10,055
Derivative, Floor Price			50.59
Derivative, Ceiling Price			63.62
NYMEX Oil Collar Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			366
Derivative, Floor Price			55
Derivative, Ceiling Price			67.01
NYMEX Oil Collar Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			14,591
Gas Swaps Contract Third Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent			3.25
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU			28,218
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | BTU			(7,480)
Derivative, Swap Type, Weighted-Average Fixed Price, Purchased Volumes | $ / EnergyContent			4.23
Derivative, Nonmonetary Notional Amount, Energy Measure, Net Volumes | BTU			20,738
Derivative, Swap Type, Average Fixed Price, Net of Purchased Volumes | $ / EnergyContent			2.90
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			3.87
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU			41,394
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			16,979
Derivative, Swap Type, Average Fixed Price, Net of Purchased Volumes | $ / EnergyContent			2.92
Gas Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU			97,816
Derivative, Nonmonetary Notional Amount, Energy Measure, Purchased Volumes | BTU			(39,105)
Derivative, Nonmonetary Notional Amount, Energy Measure, Net Volumes | BTU			58,711
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
Gas Collar Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU			14,242
WTI Midland NYMEX WTI [Member] | Oil Basis Swap Contract Third Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			3,018
Weighted-Average Contract Price	[1]		(1.06)
WTI Midland NYMEX WTI [Member] | Oil Basis Swap Contract Fourth Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			3,327
Weighted-Average Contract Price	[1]		(1.08)
WTI Midland NYMEX WTI [Member] | Oil Basis Swap Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			11,217
Weighted-Average Contract Price	[1]		(3.36)
WTI Midland NYMEX WTI [Member] | Oil Basis Swap Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			7,250
Weighted-Average Contract Price	[1]		(1.13)
WTI Midland NYMEX WTI [Member] | Oil Basis Swap Contract 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			0
Weighted-Average Contract Price	[1]		0
WTI Midland NYMEX WTI [Member] | Oil Basis Swap Contract 2022 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			0
Weighted-Average Contract Price	[1]		0
WTI Midland NYMEX WTI [Member] | Oil Basis Swap [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			24,812
NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract Third Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			0
Weighted-Average Contract Price	[2]		0
NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract Fourth Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			0
Weighted-Average Contract Price	[2]		0
NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			0
Weighted-Average Contract Price	[2]		0
NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			1,288
Weighted-Average Contract Price	[2]		(7.97)
NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			1,460
Weighted-Average Contract Price	[2]		(7.80)
NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract 2022 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			274
Weighted-Average Contract Price	[2]		(7.67)
NYMEX WTI ICE Brent [Member] | Oil Basis Swap [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			3,022
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract Third Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			1,033
Derivative, Swap Type, Average Fixed Price			10.99
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract Fourth Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			1,146
Derivative, Swap Type, Average Fixed Price			11.18
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			3,533
Derivative, Swap Type, Average Fixed Price			12.31
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			539
Derivative, Swap Type, Average Fixed Price			11.13
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			6,251
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			610
Derivative, Swap Type, Average Fixed Price			24.27
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			671
Derivative, Swap Type, Average Fixed Price			24.39
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			1,503
Derivative, Swap Type, Average Fixed Price			27.83
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			0
Derivative, Swap Type, Average Fixed Price			0
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			2,784
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			93
Derivative, Swap Type, Average Fixed Price			35.70
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			102
Derivative, Swap Type, Average Fixed Price			35.70
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			154
Derivative, Swap Type, Average Fixed Price			35.64
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			0
Derivative, Swap Type, Average Fixed Price			0
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			349
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			70
Derivative, Swap Type, Average Fixed Price			35.07
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			76
Derivative, Swap Type, Average Fixed Price			35.07
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			117
Derivative, Swap Type, Average Fixed Price			35.70
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			0
Derivative, Swap Type, Average Fixed Price			0
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			263
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			202
Derivative, Swap Type, Average Fixed Price			51.13
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter 2018 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			208
Derivative, Swap Type, Average Fixed Price			50.99
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			197
Derivative, Swap Type, Average Fixed Price			50.93
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			0
Derivative, Swap Type, Average Fixed Price			0
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl			607
Subsequent Event [Member] | NYMEX Oil Collar Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl		800
Derivative, Floor Price		55
Subsequent Event [Member] | NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl		600
Subsequent Event [Member] | NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract 2021 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl		1,800
Subsequent Event [Member] | NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract 2022 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl		2,600
Subsequent Event [Member] | OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume | bbl		500
Minimum [Member] | Subsequent Event [Member] | NYMEX Oil Collar Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Ceiling Price		64.50
Minimum [Member] | Subsequent Event [Member] | NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract 2020 [Member]
Derivative Financial Instruments
Weighted-Average Contract Price		(8.06)
Minimum [Member] | Subsequent Event [Member] | NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract 2021 [Member]
Derivative Financial Instruments
Weighted-Average Contract Price		(7.75)
Minimum [Member] | Subsequent Event [Member] | NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract 2022 [Member]
Derivative Financial Instruments
Weighted-Average Contract Price		(7.60)
Minimum [Member] | Subsequent Event [Member] | OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price		32.21
Maximum [Member] | Subsequent Event [Member] | NYMEX Oil Collar Contract 2020 [Member]
Derivative Financial Instruments
Derivative, Ceiling Price		67.67
Maximum [Member] | Subsequent Event [Member] | NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract 2020 [Member]
Derivative Financial Instruments
Weighted-Average Contract Price		(8.15)
Maximum [Member] | Subsequent Event [Member] | NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract 2021 [Member]
Derivative Financial Instruments
Weighted-Average Contract Price		(8)
Maximum [Member] | Subsequent Event [Member] | NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract 2022 [Member]
Derivative Financial Instruments
Weighted-Average Contract Price		(7.90)
Maximum [Member] | Subsequent Event [Member] | OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract 2019 [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price		32.26
[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 Instrume44

Derivative Financial Instruments Fair Value (Details) - USD ($) $ in Thousands	Jun. 30, 2018		Dec. 31, 2017
Fair value of derivative assets and liabilities
Derivative, fair value, net	$ (149,400)		$ (139,400)
Derivative assets, current	146,329		64,266
Derivative assets, noncurrent	31,151		40,362
Total derivative assets	177,480		104,628
Derivative liabilities, current	259,338		172,582
Derivatives liabilities, noncurrent	67,583		71,402
Total derivative liabilities	326,921		243,984
Derivative asset, not offset in the accompanying balance sheets	(147,009)		(100,035)
Derivative liabilities, not offset in the accompanying balance sheets	147,009		100,035
Derivative asset, fair value, net amounts	30,471		4,593
Derivative liabilities, fair value, net amounts	(179,912)		(143,949)
Not Designated as Hedging Instrument [Member]
Fair value of derivative assets and liabilities
Derivative assets, current	146,329		64,266
Derivative assets, noncurrent	31,151		40,362
Derivative liabilities, current	259,338		172,582
Derivatives liabilities, noncurrent	67,583		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	177,480	[1]	104,628	[2]
Total derivative liabilities	$ 326,921	[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 Instrume45

Derivative Financial Instruments Gains and Losses (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Derivative Instruments, Gain (Loss) [Line Items]
Derivative settlement (gain) loss	$ 36,665	$ (16,303)	$ 61,193	$ (16,310)
Net derivative (gain) loss	63,749	(55,189)	71,278	(169,963)
Oil Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative settlement (gain) loss	24,430	2,754	45,178	11,838
Net derivative (gain) loss	22,402	(38,194)	36,368	(87,784)
Gas Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative settlement (gain) loss	757	(21,751)	(5,653)	(39,257)
Net derivative (gain) loss	7,000	(6,038)	16,990	(50,506)
NGL Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative settlement (gain) loss	11,478	2,694	21,668	11,109
Net derivative (gain) loss	$ 34,347	$ (10,957)	$ 17,920	$ (31,673)

Derivative Financial Instrume46

Derivative Financial Instruments Credit Facility and Derivative Counterparties (Details)	Jun. 30, 2018
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Percentage of Proved Property Secured for Credit Facility Borrowing	90.00%

Fair Value Measurements Fair 47

Fair Value Measurements Fair Value (Details) - USD ($) $ in Thousands	Jun. 30, 2018		Dec. 31, 2017
Assets
Derivatives	$ 177,480		$ 104,628
Liabilities
Derivatives	326,921		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	177,480	[1]	104,628	[2]
Liabilities
Derivatives	326,921	[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	Jun. 30, 2018	Jun. 30, 2018	Jun. 30, 2017	Mar. 31, 2017	Jun. 30, 2018	Jun. 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		11,935	157		17,560	157
Oil and gas properties held for sale, net	$ 5,040	5,040			5,040		$ 111,700
Disposal Group, Held-for-sale, Not Discontinued Operations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Oil and gas properties held for sale, net	$ 5,000	$ 5,000			$ 5,000
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			$ 166,900	$ 359,600		$ 526,500
Oil and Gas Properties [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Period of New York Mercantile Exchange Strip Pricing Used for Price Forecast	5 years
Oil and Gas Properties [Member] | Minimum [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Discount Rate	10.00%
Oil and Gas Properties [Member] | Maximum [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Inputs, Discount Rate	15.00%

Fair Value Measurements Long-te

Fair Value Measurements Long-term Debt (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
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 [Member] | 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	$ 344,611	$ 344,611
Long-term Debt, Fair Value	$ 352,634	351,682
Senior Notes [Member] | 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	$ 561,796	561,796
Long-term Debt, Fair Value	$ 573,847	571,627
Senior Notes [Member] | 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	$ 394,985	394,985
Long-term Debt, Fair Value	$ 401,380	403,434
Senior Notes [Member] | 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	$ 468,750	483,440
Senior Notes [Member] | 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	$ 485,000	494,355
Senior Notes [Member] | 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	$ 502,350	516,350
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	$ 178,446	$ 168,291