SM Energy (SM) 10-Q 2 May 19 2019 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information Document - shares	3 Months Ended
	Mar. 31, 2019	Apr. 25, 2019
Document and Entity Information [Abstract]
Entity Registrant Name	SM Energy Co
Entity Central Index Key	0000893538
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Mar. 31, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding		112,244,545
Entity Current Reporting Status	Yes
Entity Small Business	false
Entity Emerging Growth Company	false

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) (in thousands, except share data) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 14	$ 77,965
Accounts receivable	145,299	167,536
Derivative assets	67,567	175,130
Prepaid expenses and other	8,454	8,632
Total current assets	221,334	429,263
Property and equipment (successful efforts method):
Proved oil and gas properties	7,578,976	7,278,362
Accumulated depletion, depreciation, and amortization	(3,586,650)	(3,417,953)
Unproved oil and gas properties	1,529,825	1,581,401
Wells in progress	345,507	295,529
Properties held for sale, net	0	5,280
Other property and equipment, net of accumulated depreciation of $59,720 and $57,102, respectively	86,732	88,546
Total property and equipment, net	5,954,390	5,831,165
Noncurrent assets:
Derivative assets	27,202	58,499
Other noncurrent assets	83,692	33,935
Total noncurrent assets	110,894	92,434
Total assets	6,286,618	6,352,862
Current liabilities:
Accounts payable and accrued expenses	426,550	403,199
Derivative liabilities	95,269	62,853
Other current liabilities	23,523	0
Total current liabilities	545,342	466,052
Noncurrent liabilities:
Revolving credit facility	46,500	0
Senior Notes, net of unamortized deferred financing costs	2,449,588	2,448,439
Senior Convertible Notes, net of unamortized discount and deferred financing costs	150,199	147,894
Asset retirement obligations	94,026	91,859
Deferred income taxes	176,348	223,278
Derivative liabilities	13,332	12,496
Other noncurrent liabilities	68,058	42,522
Total noncurrent liabilities	2,998,051	2,966,488
Commitments and contingencies (note 6)
Stockholders’ equity:
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued and outstanding: 112,244,545 and 112,241,966 shares, respectively	1,122	1,122
Additional paid-in capital	1,771,558	1,765,738
Retained earnings	982,662	1,165,842
Accumulated other comprehensive loss	(12,117)	(12,380)
Total stockholders' equity	2,743,225	2,920,322
Total liabilities and stockholders’ equity	$ 6,286,618	$ 6,352,862

Condensed Consolidated Balanc_2

Condensed Consolidated Balance Sheets Parenthetical - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Other property and equipment, accumulated depreciation	$ 59,720	$ 57,102
Common Stock, par value per share	$ 0.01	$ 0.01
Common Stock, Shares Authorized	200,000,000	200,000,000
Common Stock, Shares, Issued	112,244,545	112,241,966
Common Stock, Shares, Outstanding	112,244,545	112,241,966

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED) (in thousands, except per share data) - USD ($) shares in Thousands, $ in Thousands		3 Months Ended
		Mar. 31, 2019	Mar. 31, 2018
Operating revenues and other income:
Oil, gas, and NGL production revenue	[1]	$ 340,476	$ 382,886
Net gain on divestiture activity		61	385,369
Other operating revenues		393	1,340
Total operating revenues and other income		340,930	769,595
Operating expenses:
Oil, gas, and NGL production expense		121,305	120,879
Depletion, depreciation, amortization, and asset retirement obligation liability accretion		177,746	130,473
Exploration		11,348	13,727
Abandonment and impairment of unproved properties		6,338	5,625
General and administrative		32,086	27,682
Net derivative loss		177,081	7,529
Other operating expenses, net		335	4,612
Total operating expenses		526,239	310,527
Income (loss) from operations		(185,309)	459,068
Interest expense		(37,980)	(43,085)
Other non-operating income (expense), net		(317)	409
Income (loss) before income taxes		(223,606)	416,392
Income tax (expense) benefit		46,038	(98,991)
Net income (loss)		$ (177,568)	$ 317,401
Basic weighted-average common shares outstanding		112,252	111,696
Diluted weighted-average common shares outstanding		112,252	112,879
Basic net income (loss) per common share		$ (1.58)	$ 2.84
Diluted net income (loss) per common share		(1.58)	2.81
Dividends per common share		$ 0.05	$ 0.05
[1]	Note: Amounts may not calculate due to rounding.

CONDENSED CONSOLIDATED STATEM_2

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED) (in thousands) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ (177,568)	$ 317,401
Other comprehensive income, net of tax:
Pension liability adjustment	263	260
Total other comprehensive income, net of tax	263	260
Total comprehensive income (loss)	$ (177,305)	$ 317,661

CONDENSED CONSOLIDATED STATEM_3

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (in thousands) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Cash flows from operating activities:
Net income (loss)	$ (177,568)	$ 317,401
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net gain on divestiture activity	(61)	(385,369)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion	177,746	130,473
Abandonment and impairment of unproved properties	6,338	5,625
Stock-based compensation expense	5,838	5,412
Net derivative loss	177,081	7,529
Derivative settlement loss	(4,969)	(24,528)
Amortization of debt discount and deferred financing costs	3,789	3,866
Deferred income taxes	(47,003)	98,366
Other, net	(2,530)	(2,527)
Net change working capital	(20,159)	(16,113)
Net cash provided by operating activities	118,502	140,135
Cash flows from investing activities:
Net proceeds from the sale of oil and gas properties	6,114	490,780
Capital expenditures	(249,340)	(301,521)
Other, net	291	0
Net cash provided by (used in) investing activities	(242,935)	189,259
Cash flows from financing activities:
Proceeds from credit facility	172,000	0
Repayment of credit facility	(125,500)	0
Other, net	(18)	0
Net cash provided by financing activities	46,482	0
Net change in cash, cash equivalents, and restricted cash	(77,951)	329,394
Cash, cash equivalents, and restricted cash at beginning of period	77,965	313,943	$ 313,943
Cash, cash equivalents, and restricted cash at end of period	14	643,337	$ 77,965
Supplemental Cash Flow Information - Operating activities:
Cash paid for interest, net of capitalized interest	(39,957)	(40,060)
Supplemental Cash Flow Information - Investing activities:
Changes in capital expenditure accruals and other	62,185	60,299
Supplemental Cash Flow Information - Non-Cash Investing activities:
Carrying value of properties exchanged	$ 65,788	$ 0

CONDENSED CONSOLIDATED STATEM_4

CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY - USD ($) $ in Thousands	Total	Common Stock	Additional Paid-in Capital	Retained Earnings	AOCI Attributable to Parent
Cash dividends per share	$ 0.05
Balances, Common Stock, Shares, Outstanding, Beginning at Dec. 31, 2017		111,687,016
Balances, Total stockholders' equity, beginning at Dec. 31, 2017	$ 2,394,608	$ 1,117	$ 1,741,623	$ 665,657	$ (13,789)
Increase (Decrease) in Stockholders' Equity
Net income (loss)	317,401			317,401
Other comprehensive income	260				260
Cash dividends declared, $0.05 per share	(5,584)			(5,584)
Stock-based compensation expense	5,412		5,412
Other	0			1	(1)
Balances, Common Stock, Shares, Outstanding, Ending at Mar. 31, 2018		111,687,016
Balances, Total stockholders' equity, ending at Mar. 31, 2018	2,712,097	$ 1,117	1,747,035	980,444	(16,499)
Increase (Decrease) in Stockholders' Equity
Cumulative effect of accounting change	$ 0			2,969	(2,969)
Cash dividends per share	$ 0.05
Balances, Common Stock, Shares, Outstanding, Beginning at Dec. 31, 2018	112,241,966	112,241,966
Balances, Total stockholders' equity, beginning at Dec. 31, 2018	$ 2,920,322	$ 1,122	1,765,738	1,165,842	(12,380)
Increase (Decrease) in Stockholders' Equity
Net income (loss)	(177,568)			(177,568)
Other comprehensive income	263				263
Cash dividends declared, $0.05 per share	(5,612)			(5,612)
Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings (Shares)		2,579
Issuance of common stock upon vesting of RSUs, net of shares used for tax withholdings (Amount)	(18)	$ 0	(18)
Stock-based compensation expense	$ 5,838		5,838
Balances, Common Stock, Shares, Outstanding, Ending at Mar. 31, 2019	112,244,545	112,244,545
Balances, Total stockholders' equity, ending at Mar. 31, 2019	$ 2,743,225	$ 1,122	$ 1,771,558	$ 982,662	$ (12,117)

Summary of Significant Accounti

Summary of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2019
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 the Company 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 the Company’s Annual Report on Form 10-K for the year ended December 31, 2018 (the “ 2018 Form 10-K”). In the opinion of management, all adjustments, consisting of normal recurring adjustments considered necessary for a fair presentation of interim financial information, have been included. Operating results for the periods presented are not necessarily indicative of expected results for the full year. In connection with the preparation of the Company’s unaudited condensed consolidated financial statements, the Company evaluated events subsequent to the balance sheet date of March 31, 2019 , 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. Significant Accounting Policies The significant accounting policies followed by the Company are set forth in Note 1 - Summary of Significant Accounting Policies in the 2018 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 2018 Form 10-K. Recently Issued Accounting Standards In February 2016, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) No. 2016-02, Leases (Topic 842), followed by other related ASUs that provided targeted improvements and additional practical expedient options (collectively “ASU 2016-02” or “Topic 842”). The Company adopted ASU 2016-02 on January 1, 2019, using the modified retrospective method. The Company elected as part of its adoption to also use the optional transition methodology whereby previously reported periods continue to be reported in accordance with historical accounting guidance for leases that were in effect for those prior periods. Policy elections and practical expedients the Company has implemented in connection with the adoption of ASU 2016-02, include (a) excluding from the balance sheet leases with terms that are less than one year, (b) for agreements that contain both lease and non-lease components, combining these components together and accounting for them as a single lease, (c) the package of practical expedients, which among other requirements, allows the Company to avoid reassessing contracts that commenced prior to adoption that were properly evaluated under legacy GAAP, and (d) excluding land easements that existed or expired before adoption of ASU 2016-02. 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. Upon adoption on January 1, 2019, the Company recognized approximately $50.0 million in right-of-use (“ROU”) assets and related lease liabilities for its operating leases. There was no cumulative effect to retained earnings upon the adoption of this guidance. Please refer to Note 12 - Leases for additional discussion. Other than as disclosed in the 2018 Form 10-K, there are no ASUs 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 March 31, 2019 , and through the filing of this report.

Revenue from Contracts with Cus

Revenue from Contracts with Customers	3 Months Ended
	Mar. 31, 2019
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 and South Texas & Gulf Coast regions. As a result of divestiture activity in the first half of 2018, there has been no production revenue from the Rocky Mountain region after the second quarter of 2018. Oil, gas, and NGL production revenue presented within the accompanying unaudited condensed consolidated statements of operations (“accompanying statements of operations”) is reflective of the revenue generated from contracts with customers. The table below presents oil, gas, and NGL production revenue by product type for each of the Company’s operating regions for the three months ended March 31, 2019 , and 2018 : Permian South Texas & Gulf Coast Rocky Mountain Total Three Months Ended March 31, Three Months Ended March 31, Three Months Ended March 31, Three Months Ended March 31, 2019 2018 2019 2018 2019 2018 2019 2018 (in thousands) Oil production revenue $ 225,247 $ 205,794 $ 13,814 $ 19,583 $ — $ 35,683 $ 239,061 $ 261,060 Gas production revenue 15,592 24,876 49,521 52,733 — 1,500 65,113 79,109 NGL production revenue 21 124 36,281 41,770 — 823 36,302 42,717 Total $ 240,860 $ 230,794 $ 99,616 $ 114,086 $ — $ 38,006 $ 340,476 $ 382,886 Relative percentage 71 % 60 % 29 % 30 % — % 10 % 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 custody and title (“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 embedded in the price and effectively recorded as a reduction of oil, gas, and NGL production revenue. Please refer to Note 2 - Revenue from Contracts with Customers in the 2018 Form 10-K for more information regarding the types of contracts under which oil, gas, and NGL production revenue is generated. 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 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 the accounts receivable line item on the accompanying unaudited condensed consolidated balance sheets (“accompanying balance sheets”) until payment is received. The accounts receivable balances from contracts with customers within the accompanying balance sheets as of March 31, 2019 , and December 31, 2018 , were $109.4 million and $107.2 million , respectively. To estimate accounts receivable from contracts with customers, the Company uses knowledge of its properties, historical performance, contractual arrangements, index 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 during the three months ended March 31, 2019 , that related to performance obligations satisfied in prior reporting periods, was immaterial.

Divestitures, Assets Held for S

Divestitures, Assets Held for Sale, and Acquisitions	3 Months Ended
	Mar. 31, 2019
Divestitures, Assets Held for Sale, and Acquisitions [Abstract]
Divestitures, Assets Held for Sale, and Acquisitions	Note 3 - Divestitures, Assets Held for Sale, and Acquisitions Divestitures On March 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 , and recorded an estimated net gain of $409.2 million for the three months ended March 31, 2018 . After final purchase price adjustments, the Company received net divestiture proceeds of $492.2 million , and recorded a final net gain of $410.6 million related to these divested assets for the year ended December 31, 2018 . During the first quarter of 2018, the company entered into definitive agreements for the sale of its Divide County assets (the “Divide County Divestiture”) and its Halff East assets in the Midland Basin (the “Halff East Divestiture”). Certain of these assets were written down by $24.1 million during the first quarter of 2018 to reflect fair value less estimated costs to sell upon classification as held for sale. These divestitures were completed during the second quarter of 2018. Acquisitions During the first quarter of 2019 , the Company completed several non-monetary acreage trades of undeveloped properties located in Howard, Martin, and Midland Counties, Texas, resulting in the exchange of approximately 2,000 net acres, with $65.8 million of carrying value attributed to the properties surrendered by the Company. These trades were recorded at carryover basis with no gain or loss recognized. No such trades occurred during the first quarter of 2018 .

Income Taxes

Income Taxes	3 Months Ended
	Mar. 31, 2019
Income Tax Disclosure [Abstract]
Income Taxes	Note 4 - Income Taxes The income tax (expense) benefit recorded for the three months ended March 31, 2019 , and 2018 , 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, limitations on the compensation of certain covered individuals, 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 months ended March 31, 2019 , and 2018 , consisted of the following: For the Three Months Ended March 31, 2019 2018 (in thousands) Current portion of income tax (expense) benefit: Federal $ — $ — State (965 ) (625 ) Deferred portion of income tax (expense) benefit 47,003 (98,366 ) Income tax (expense) benefit $ 46,038 $ (98,991 ) Effective tax rate 20.6 % 23.8 % The change in the Company’s effective tax rate for the periods presented in the table above generally reflects 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. Future periods are not expected to reflect these differences as the Company’s current activities are occurring predominately in Texas. For years before 2015, the Company is generally no longer subject to United States federal or state income tax examinations by tax authorities.

Long-Term Debt

Long-Term Debt	3 Months Ended
	Mar. 31, 2019
Debt Disclosure [Abstract]
Long-Term Debt	Note 5 - Long-Term Debt Credit Agreement As of March 31, 2019 , the Company’s Sixth Amended and Restated Credit Agreement (the “Credit Agreement”) provided for a senior secured revolving credit facility with a maximum loan amount of $2.5 billion , an initial borrowing base of $1.5 billion , and initial aggregate lender commitments totaling $1.0 billion , which were unchanged from December 31, 2018 . On April 18, 2019 , the Company entered into the First Amendment to the Credit Agreement (the “First Amendment”) with its lenders. Pursuant to the First Amendment, and as part of the regular, semi-annual borrowing base redetermination process, the borrowing base and aggregate lender commitments were increased to $1.6 billion and $1.2 billion , respectively. The borrowing base increase was primarily driven by the increased value of the Company’s estimated proved reserves at December 31, 2018 . The next scheduled borrowing base redetermination date is October 1, 2019 . The Credit Agreement is scheduled to mature on September 28, 2023 . The maturity date could, however, occur earlier on August 16, 2022, if the Company has not completed certain repurchase, redemption, or refinancing activities associated with its 6.125% Senior Notes due 2022 (“2022 Senior Notes”), as outlined in the Credit Agreement. Please refer to Note 5 - Long-Term Debt in the 2018 Form 10-K for additional detail on the terms of the Company’s Credit Agreement. 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 March 31, 2019 , 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 Company’s 2018 Form 10-K. At the Company’s election, borrowings under the Credit Agreement may be in the form of Eurodollar, Alternate Base Rate (“ABR”), or Swingline loans. Eurodollar loans accrue interest at the London Interbank Offered Rate, plus the applicable margin from the utilization grid, and ABR and Swingline loans accrue interest at a market-based floating rate, plus the applicable margin from the utilization grid. Commitment fees are accrued on the unused portion of the aggregate lender commitment amount at rates from the utilization grid and are included in the interest expense line item on the accompanying statements of operations. The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Credit Agreement as of April 25, 2019 , March 31, 2019 , and December 31, 2018 : As of April 25, 2019 As of March 31, 2019 As of December 31, 2018 (in thousands) Credit facility balance (1) $ 40,000 $ 46,500 $ — Letters of credit (2) — — 200 Available borrowing capacity 1,160,000 953,500 999,800 Total aggregate lender commitment amount $ 1,200,000 $ 1,000,000 $ 1,000,000 ____________________________________________ (1) Unamortized deferred financing costs attributable to the credit facility are presented as a component of other noncurrent assets on the accompanying balance sheets and totaled $6.0 million and $6.4 million as of March 31, 2019 , and December 31, 2018 , respectively. These costs are being amortized over the term of the credit facility on a straight-line basis. (2) Letters of credit outstanding reduce the amount available under the credit facility on a dollar-for-dollar basis. The letter of credit outstanding as of December 31, 2018 , was released during the quarter ended March 31, 2019 . Senior Notes As of March 31, 2019 , the Company’s Senior Notes consisted of 6.125% Senior Notes due 2022, 5.0% Senior Notes due 2024, 5.625% Senior Notes due 2025, 6.75% Senior Notes due 2026, and 6.625% Senior Notes due 2027 (collectively referred to as “Senior Notes”). The Senior Notes, net of unamortized deferred financing costs line item on the accompanying balance sheets as of March 31, 2019 , and December 31, 2018 , consisted of the following: As of March 31, 2019 As of December 31, 2018 Principal Amount Unamortized Deferred Financing Costs Principal Amount, Net of Unamortized Deferred Financing Costs Principal Amount Unamortized Deferred Financing Costs Principal Amount, Net of Unamortized Deferred Financing Costs (in thousands) 6.125% Senior Notes due 2022 $ 476,796 $ 3,671 $ 473,125 $ 476,796 $ 3,921 $ 472,875 5.0% Senior Notes due 2024 500,000 4,457 495,543 500,000 4,688 495,312 5.625% Senior Notes due 2025 500,000 5,582 494,418 500,000 5,808 494,192 6.75% Senior Notes due 2026 500,000 6,198 493,802 500,000 6,407 493,593 6.625% Senior Notes due 2027 500,000 7,300 492,700 500,000 7,533 492,467 Total $ 2,476,796 $ 27,208 $ 2,449,588 $ 2,476,796 $ 28,357 $ 2,448,439 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 March 31, 2019 , 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 2018 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 March 31, 2019 , or through the filing of this report. Notwithstanding the inability to convert, the if-converted value of the Senior Convertible Notes as of March 31, 2019 , 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 $2.7 million and $2.6 million for the three months ended March 31, 2019 , and 2018 , respectively. There have been no changes to the initial net carrying amount of the equity component of the Senior Convertible Notes recorded in additional paid-in capital on the accompanying balance sheets since issuance. The Senior Convertible Notes, net of unamortized discount and deferred financing costs line on the accompanying balance sheets as of March 31, 2019 , and December 31, 2018 , consisted of the following: As of March 31, 2019 As of December 31, 2018 (in thousands) Principal amount of Senior Convertible Notes $ 172,500 $ 172,500 Unamortized debt discount (20,238 ) (22,313 ) Unamortized deferred financing costs (2,063 ) (2,293 ) Senior Convertible Notes, net of unamortized discount and deferred financing costs $ 150,199 $ 147,894 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 March 31, 2019 , and through the filing of this report. Capitalized Interest Capitalized interest costs for the Company for the three months ended March 31, 2019 , and 2018 , were $4.9 million and $4.5 million , respectively. The amount of interest the Company capitalizes generally fluctuates based on its capital program and the timing and amount of costs associated with capital projects that are considered in progress.

Commitments and Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 6 - Commitments and Contingencies Commitments Other than those items discussed below, there have been no changes in commitments through the filing of this report that differ materially from those disclosed in the 2018 Form 10-K. Please refer to Note 6 - Commitments and Contingencies in the 2018 Form 10-K for additional discussion of the Company’s commitments. Delivery and Purchase Commitments. Subsequent to March 31, 2019 , the Company executed an amendment to its existing sand sourcing agreement that created certain commitments and potential penalties which will vary based on the amount of actual sand the Company uses in well completions occurring in a particular area. This amended sand sourcing agreement expires on December 31, 2023. As of the filing of this report, potential penalties under this sand sourcing agreement range from zero to $10.0 million . The Company does not expect to incur penalties with regard to this agreement. Drilling Rig and Completion Service Contracts. The Company entered into new and amended drilling rig and well completion service contracts during the first three months of 2019 , and subsequent to March 31, 2019 . As of the filing of this report, the Company’s drilling rig and completion service contract commitments totaled $105.3 million . If all of these contracts were terminated as of the filing of this report, the Company would avoid a portion of the contractual service commitments; however, the Company would be required to pay $50.0 million in early termination fees. Excluded from these amounts are variable commitments and penalties determined by the number of completion crews the Company has in operation in a particular area under a completion service arrangement. As of the filing of this report, potential penalties under this completion service arrangement, which expires on December 31, 2023, range from zero to a maximum of $15.7 million . The Company does not expect to incur penalties with regard to its drilling rig and completion service contracts. Contingencies The Company is subject to litigation and claims arising in the ordinary course of business. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. In the opinion of management, the anticipated results of any pending litigation and claims are not expected to have a material effect on the results of operations, the financial position, or the cash flows of the Company.

Compensation Plans

Compensation Plans	3 Months Ended
	Mar. 31, 2019
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Compensation Plans	Note 7 - Compensation Plans Performance Share Units The Company grants performance share units (“PSUs”) to eligible employees as part of its long-term equity incentive compensation program. The number of shares of the Company’s common stock issued to settle PSUs ranges from zero to two times the number of PSUs awarded and is determined based on certain performance criteria over a three -year performance period. PSUs generally vest on the third anniversary of the date of the grant or upon other triggering events as set forth in the Company’s Equity Incentive Compensation Plan (“Equity Plan”). PSUs are subject to a combination of market, performance, and service vesting criteria. Awards with a market criteria component are based on annualized Total Shareholder Return (“TSR”) for the performance period and the relative performance of the Company’s TSR compared with the annualized TSR of the Company’s peer group for the performance period. Compensation expense for market-based PSUs is recognized on a straight-line basis within general and administrative expense and exploration expense over the vesting periods of the respective awards. Awards with a performance criteria component are based on relative debt adjusted per share cash flow growth (“DACFG”) compared with DACFG, as calculated by the Company, of its peer group that is evaluated over the three -year performance period. Compensation expense for performance-based PSUs will be evaluated on a quarterly basis and may be adjusted as the number of units expected to vest increases or decreases. Total compensation expense recorded for PSUs was $2.8 million and $2.4 million for the three months ended March 31, 2019 , and 2018 , respectively. As of March 31, 2019 , there was $15.9 million of total unrecognized compensation expense related to non-vested PSU awards, which is being amortized through 2021. There have been no material changes to the outstanding and non-vested PSUs during the three months ended March 31, 2019 . Employee Restricted Stock Units The Company grants restricted stock units (“RSUs”) to eligible persons as part of its long-term equity incentive compensation program. Each RSU represents a right to receive one share of the Company’s common stock upon settlement of the award at the end of the specified vesting period. Compensation expense for RSUs is recognized within general and administrative expense and exploration expense over the vesting periods of the respective awards. RSUs granted to employees generally vest one-third on each anniversary date of the grant over a three -year vesting period or upon other triggering events as set forth in the Company’s Equity Plan. Total compensation expense recorded for employee RSUs was $2.7 million for each of the three months ended March 31, 2019 , and 2018 . As of March 31, 2019 , there was $16.4 million of total unrecognized compensation expense related to non-vested RSU awards, which is being amortized through 2021. There have been no material changes to the outstanding and non-vested RSUs during the three months ended March 31, 2019 .

Pension Benefits

Pension Benefits	3 Months Ended
	Mar. 31, 2019
Defined Benefit Plan [Abstract]
Pension Benefits	Note 8 - Pension Benefits Pension Plans The Company has a non-contributory defined benefit pension plan covering employees who meet age and service requirements and who began employment with the Company prior to January 1, 2016 (the “Qualified Pension Plan”). The Company also has a supplemental non-contributory pension plan covering certain management employees (the “Nonqualified Pension Plan” and together with the Qualified Pension Plan, the “Pension Plans”). The Company froze the Pension Plans to new participants, effective as of January 1, 2016. Employees participating in the Pension Plans prior to the plans being frozen will continue to earn benefits. Components of Net Periodic Benefit Cost for the Pension Plans For the Three Months Ended March 31, 2019 2018 (in thousands) Components of net periodic benefit cost: Service cost $ 1,683 $ 1,660 Interest cost 656 673 Expected return on plan assets that reduces periodic pension benefit cost (466 ) (561 ) Amortization of prior service cost 4 4 Amortization of net actuarial loss 332 324 Net periodic benefit cost $ 2,209 $ 2,100 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. 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 (expense), net line item on the accompanying statements of operations. Contributions The Company contributed $4.3 million to the Qualified Pension Plan during the three months ended March 31, 2019 .

Earnings per Share

Earnings per Share	3 Months Ended
	Mar. 31, 2019
Earnings Per Share [Abstract]
Earnings per Share	Note 9 - Earnings Per Share Basic net income or loss per common share is calculated by dividing net income or loss available to common stockholders by the basic weighted-average number of common shares outstanding for the respective period. Diluted net income or loss per common share is calculated by dividing 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 months ended March 31, 2019 , and 2018 , and therefore the Senior Convertible Notes had no dilutive impact. Please refer to Note 9 - Earnings Per Share in the 2018 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 details the weighted-average dilutive and anti-dilutive securities for the periods presented: For the Three Months Ended March 31, 2019 2018 (in thousands) Dilutive — 1,183 Anti-dilutive 781 — The following table sets forth the calculations of basic and diluted net income (loss) per common share: For the Three Months Ended March 31, 2019 2018 (in thousands, except per share data) Net income (loss) $ (177,568 ) $ 317,401 Basic weighted-average common shares outstanding 112,252 111,696 Dilutive effect of non-vested RSUs and contingent PSUs — 1,183 Dilutive effect of Senior Convertible Notes — — Diluted weighted-average common shares outstanding 112,252 112,879 Basic net income (loss) per common share $ (1.58 ) $ 2.84 Diluted net income (loss) per common share $ (1.58 ) $ 2.81

Derivative Financial Instrument

Derivative Financial Instruments	3 Months Ended
	Mar. 31, 2019
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Derivative Financial Instruments	Note 10 - Derivative Financial Instruments Summary of Oil, Gas, and NGL Derivative Contracts in Place The Company has entered into various commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in commodity prices and the associated impact on cash flows. As of March 31, 2019 , all derivative counterparties were members of the Company’s Credit Agreement lender group and all contracts were entered into for other-than-trading purposes. The Company’s commodity derivative contracts consist of swap and collar arrangements for oil and gas production, and swap arrangements for NGL production. In a typical commodity swap agreement, if the agreed upon published third-party index price (“index price”) is lower than the swap fixed price, the Company receives the difference between the index price and the agreed upon swap fixed price. If the index price is higher than the swap fixed price, the Company pays the difference. For collar arrangements, the Company receives the difference between an agreed upon index and the floor price if the index price is below the floor price. The Company pays the difference between the agreed upon ceiling price and the index price if the index price is above the ceiling price. No amounts are paid or received if the index price is between the floor and ceiling prices. The Company has also entered into fixed price oil basis swaps in order to mitigate exposure to adverse pricing differentials between certain industry benchmark prices and the actual physical pricing points where the Company’s production volumes are sold. Currently, the Company has basis swap contracts with fixed price differentials between NYMEX WTI and WTI Midland for a portion of its Midland Basin production with sales contracts that settle at WTI Midland prices. The Company also has basis swaps with fixed price differentials between NYMEX WTI and Intercontinental Exchange Brent Crude (“ICE Brent”) for a portion of its Midland Basin oil production with sales contracts that settle at ICE Brent prices. As of March 31, 2019 , the Company had commodity derivative contracts outstanding through the fourth quarter of 2022 as summarized in the tables below. Oil Swaps Contract Period NYMEX WTI Volumes Weighted-Average Contract Price (MBbl) (per Bbl) Second quarter 2019 575 $ 55.52 Third quarter 2019 1,217 $ 61.41 Fourth quarter 2019 1,115 $ 59.97 2020 2,491 $ 65.68 Total 5,398 Oil Collars Contract Period NYMEX WTI Volumes Weighted-Average Floor Price Weighted-Average Ceiling Price (MBbl) (per Bbl) (per Bbl) Second quarter 2019 3,034 $ 52.39 $ 64.32 Third quarter 2019 2,547 $ 49.50 $ 62.64 Fourth quarter 2019 3,168 $ 50.54 $ 62.49 2020 3,405 $ 55.00 $ 63.00 Total 12,154 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) Second quarter 2019 2,571 $ (4.49 ) — $ — Third quarter 2019 3,291 $ (2.86 ) — $ — Fourth quarter 2019 3,338 $ (2.87 ) — $ — 2020 11,601 $ (1.03 ) 2,750 $ (8.03 ) 2021 3,707 $ 0.33 3,650 $ (7.86 ) 2022 — $ — 3,650 $ (7.78 ) Total 24,508 10,050 ____________________________________________ (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 IF HSC Volumes Weighted-Average Contract Price WAHA Volumes Weighted-Average Contract Price (BBtu) (per MMBtu) (BBtu) (per MMBtu) Second quarter 2019 11,177 $ 2.82 4,546 $ 0.70 Third quarter 2019 14,102 $ 2.84 4,340 $ 1.30 Fourth quarter 2019 14,433 $ 2.88 2,962 $ 1.75 2020 9,123 $ 2.98 2,060 $ 2.20 Total (1) 48,835 13,908 ____________________________________________ (1) The Company has natural gas swaps in place that settle against Inside FERC Houston Ship Channel (“IF HSC”), Inside FERC West Texas (“IF WAHA”), and Platt’s Gas Daily West Texas (“GD WAHA”). As of March 31, 2019 , total volumes for gas swaps are comprised of 78 percent IF HSC , 12 percent GD Waha , and 10 percent IF Waha . Gas Collars Contract Period IF HSC Volumes Weighted-Average Floor Price Weighted-Average Ceiling Price (BBtu) (per MMBtu) (per MMBtu) Second quarter 2019 4,358 $ 2.50 $ 2.83 Third quarter 2019 5,066 $ 2.50 $ 2.83 Fourth quarter 2019 4,818 $ 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) Second quarter 2019 877 $ 12.29 561 $ 31.32 38 $ 35.64 29 $ 35.70 49 $ 50.93 Third quarter 2019 907 $ 12.34 637 $ 31.29 39 $ 35.64 30 $ 35.70 50 $ 50.93 Fourth quarter 2019 896 $ 12.36 651 $ 31.64 39 $ 35.64 29 $ 35.70 50 $ 50.93 2020 711 $ 11.38 — $ — — $ — — $ — — $ — Total 3,391 1,849 116 88 149 Commodity Derivative Contracts Entered Into Subsequent to March 31, 2019 Subsequent to March 31, 2019 , the Company entered into various commodity derivative contracts, as summarized below: • fixed price NYMEX WTI oil swap contracts through the second quarter of 2020 for a total of 1.6 MMBbl of oil production at a weighted-average contract price of $61.49 per Bbl; • NYMEX WTI costless collar contracts through the third quarter of 2020 for a total of 1.7 MMBbl of oil production with a weighted-average contract floor price of $55.00 per Bbl and a weighted-average contract ceiling price of $65.07 per Bbl; and • fixed price OPIS Propane Mont Belvieu Non-TET swap contracts through the fourth quarter of 2020 for a total of 0.6 MMBbl of propane production at a contract price of $28.10 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 Company does not designate its derivative commodity contracts as hedging instruments. The fair value of the commodity derivative contracts was a net liability of $13.8 million at March 31, 2019 , and a net asset of $158.3 million at December 31, 2018 . The following table details the fair value of commodity derivative contracts recorded in the accompanying balance sheets, by category: As of March 31, 2019 As of December 31, 2018 (in thousands) Derivative assets: Current assets $ 67,567 $ 175,130 Noncurrent assets 27,202 58,499 Total derivative assets $ 94,769 $ 233,629 Derivative liabilities: Current liabilities $ 95,269 $ 62,853 Noncurrent liabilities 13,332 12,496 Total derivative liabilities $ 108,601 $ 75,349 Offsetting of Derivative Assets and Liabilities As of March 31, 2019 , and December 31, 2018 , 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 March 31, 2019 December 31, 2018 March 31, 2019 December 31, 2018 (in thousands) Gross amounts presented in the accompanying balance sheets $ 94,769 $ 233,629 $ (108,601 ) $ (75,349 ) Amounts not offset in the accompanying balance sheets (52,882 ) (56,041 ) 52,882 56,041 Net amounts $ 41,887 $ 177,588 $ (55,719 ) $ (19,308 ) The following table summarizes the components of the net derivative loss line item presented in the accompanying statements of operations: For the Three Months Ended March 31, 2019 2018 (in thousands) Derivative settlement (gain) loss: Oil contracts $ 1,369 $ 20,748 Gas contracts 4,134 (6,410 ) NGL contracts (534 ) 10,190 Total derivative settlement loss $ 4,969 $ 24,528 Net derivative (gain) loss: Oil contracts $ 185,797 $ 13,966 Gas contracts (6,113 ) 9,990 NGL contracts (2,603 ) (16,427 ) Total net derivative loss $ 177,081 $ 7,529 Credit Related Contingent Features As of March 31, 2019 , and through the filing of this report, all of the Company’s derivative counterparties were members of the Company’s Credit Agreement lender group. Under the Credit Agreement, the Company is required to provide mortgage liens on assets having a value equal to at least 85 percent of the total PV-9 of the Company’s proved oil and gas properties evaluated in the most recent reserve report. Collateral securing indebtedness under the Credit Agreement also secures the Company’s derivative agreement obligations.

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 2019
Fair Value Disclosures [Abstract]
Fair Value Disclosures	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 March 31, 2019 : Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 94,769 $ — Liabilities: Derivatives (1) $ — $ 108,601 $ — __________________________________________ (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, 2018 : Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 233,629 $ — Liabilities: Derivatives (1) $ — $ 75,349 $ — ____________________________________________ (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 2018 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 that associated carrying costs may not be recoverable. The Company uses Level 3 inputs and the income valuation technique to measure the fair value of proved properties through the application of discount rates and price forecasts representative of the current operating environment, as selected by the Company’s management. Unproved oil and gas properties. Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. To measure the fair value of unproved properties, the Company uses a market approach, which takes into account the following significant assumptions: remaining lease terms, future development plans, risk weighted potential resource recovery, estimated reserve values, and estimated acreage value based on price(s) received for similar, recent acreage transactions by the Company or other market participants. During the three months ended March 31, 2019 , and 2018 , the Company recorded $6.3 million and $5.6 million , respectively, in abandonment and impairment of unproved properties expense related to actual and anticipated lease expirations, as well as actual and anticipated losses on acreage due to title defects, changes in development plans, and other inherent acreage risks. Properties held for sale. Properties classified as held for sale, including any corresponding asset retirement obligation liability, are valued using a market approach, based on an estimated net selling price, as evidenced by the most current bid prices received from third parties, if available. If an estimated selling price is not available, the Company utilizes the various valuation techniques discussed above. Any initial write-down and subsequent changes to the fair value less estimated cost to sell is included within the net gain on divestiture activity line item in the accompanying statements of operations. There were $5.3 million of assets held for sale that were recorded at fair value less estimated costs to sell as of December 31, 2018 . There were no assets held for sale as of March 31, 2019 . For the three months ended March 31, 2018 , write-downs to fair value less estimated costs to sell on assets held for sale totaled $24.1 million . Please refer to Note 3 - Divestitures, Assets Held for Sale, and Acquisitions above and in the 2018 Form 10-K for more information regarding the Company’s oil and gas properties held for sale . Please refer to Note 1 – Summary of Significant Accounting Policies and Note 11 - Fair Value Measurements in the 2018 Form 10-K for more information regarding the Company’s approach in determining fair value of its properties. Long-Term Debt The following table reflects the fair value of the Company’s unsecured senior note obligations measured using Level 1 inputs based on quoted secondary market trading prices. These notes were not presented at fair value on the accompanying balance sheets as of March 31, 2019 , or December 31, 2018 , as they were recorded at carrying value, net of any unamortized discounts and deferred financing costs. Please refer to Note 5 - Long-Term Debt for additional discussion. As of March 31, 2019 As of December 31, 2018 Principal Amount Fair Value Principal Amount Fair Value (in thousands) 6.125% Senior Notes due 2022 $ 476,796 $ 477,988 $ 476,796 $ 452,336 5.0% Senior Notes due 2024 $ 500,000 $ 464,685 $ 500,000 $ 439,265 5.625% Senior Notes due 2025 $ 500,000 $ 464,820 $ 500,000 $ 436,460 6.75% Senior Notes due 2026 $ 500,000 $ 481,875 $ 500,000 $ 448,305 6.625% Senior Notes due 2027 $ 500,000 $ 476,205 $ 500,000 $ 442,500 1.50% Senior Convertible Notes due 2021 $ 172,500 $ 163,013 $ 172,500 $ 158,614

Leases

Leases	3 Months Ended
	Mar. 31, 2019
Lessee Disclosure [Abstract]
Leases	Note 12 - Leases Effective January 1, 2019, the Company adopted Topic 842, which requires lessees to recognize operating and finance leases with terms greater than 12 months on the balance sheet. The Company adopted this standard using the modified retrospective method and elected to use the optional transition methodology whereby reporting periods prior to adoption continue to be presented in accordance with legacy accounting guidance. As of March 31, 2019 , the Company did not have any agreements in place that were classified as finance leases under Topic 842. Arrangements classified as operating leases are included on the accompanying balance sheets within the other noncurrent assets, other current liabilities, and other noncurrent liabilities line items. For any agreement that contains both lease and non-lease components, such as a service arrangement that also includes an identifiable ROU asset, the Company’s policy for all asset classes is to combine lease and non-lease components together and account for the arrangement as a single lease. Aside from the recognition of ROU assets and corresponding lease liabilities on the accompanying balance sheets, Topic 842 will not have a material impact on the timing or classification of costs incurred for those agreements considered to be leases. As outlined in Topic 842, a ROU asset represents a lessee’s right to use an underlying asset for the lease term, while the associated lease liability represents the lessee’s obligations to make lease payments. At the commencement date, which is the date on which a lessor makes an underlying asset available for use by a lessee, a lease ROU asset and corresponding lease liability is recognized based on the present value of the future lease payments. The initial measurement of lease payments may also be adjusted for certain items, including options that are reasonably certain to be exercised, such as options to purchase the asset at the end of the lease term, or options to extend or early terminate the lease. Excluded from the initial measurement of a ROU asset and corresponding lease liability are certain variable lease payments, such as payments made that vary depending on actual usage or performance. The Company evaluates a contractual arrangement at its inception to determine if it is a lease or contains an identifiable lease component as defined by Topic 842. When evaluating a contract to determine appropriate classification and recognition under Topic 842, significant judgment may be necessary to determine, among other criteria, if an embedded leasing arrangement exists, the length of the term, classification as either an operating or financing lease, which options are reasonably likely to be exercised, fair value of the underlying ROU asset or assets, upfront costs, and future lease payments that are included or excluded in the initial measurement of the ROU asset. Certain assumptions and judgments made by the Company when evaluating a contract that meets the definition of a lease under Topic 842 include: • Discount Rate - Unless implicitly defined, the Company will determine the present value of future lease payments using an estimated incremental borrowing rate based on a yield curve analysis that factors in certain assumptions, including the term of the lease and credit rating of the Company at lease inception. • Lease Term - The Company evaluates each contract containing a lease arrangement at inception to determine the length of the lease term when recognizing a ROU asset and corresponding lease liability. When determining the lease term, options available to extend or early terminate the arrangement are evaluated and included when it is reasonably certain an option will be exercised. Because of the Company’s intent to maintain financial and operational flexibility, there are no available options to extend that the Company is reasonably certain it will exercise. Additionally, based on expectations for those agreements with early termination options, there are no leases in which early termination options are reasonably certain to be exercised. Currently, the Company has operating leases for asset classes that include office space, office equipment, drilling rigs, well completion agreements, midstream agreements, vehicles, and equipment rentals used in field operations. For those operating leases included on the accompanying balance sheets, which only includes leases with terms greater than 12 months at commencement, remaining lease terms range from less than one year to approximately seven years. The weighted-average lease term remaining for these leases is 3.2 years. Certain leases also contain optional extension periods that allow for terms to be extended for up to an additional 10 years. An early termination option also exists for certain leases, some of which allow for the Company to terminate a lease within one year. Exercising an early termination option may also result in an early termination penalty depending on the terms of the underlying agreement. Subsequent to initial measurement, costs associated with the Company’s operating leases are either expensed or capitalized depending on how the underlying ROU asset is utilized and in accordance with GAAP requirements. For example, costs associated with drilling rigs and completion crews that are considered ROU assets are typically capitalized as part of the development of the Company’s oil and gas properties. Please refer to Note 1 – Summary of Significant Accounting Policies in the Company’s 2018 Form 10-K for additional information on its accounting policies for oil and gas development and producing activities. When calculating the Company’s ROU asset and liability for a contractual arrangement that qualifies as an operating lease, the Company considers all of the necessary payments made or that are expected to be made upon commencement of the lease. Excluded from the initial measurement are certain variable lease payments, which for the Company’s drilling rigs, completion crews, and midstream agreements, may be a significant component of the total lease costs. For the three months ended March 31, 2019 , total costs related to operating leases, including short-term leases, and variable lease payments made for leases with initial lease terms greater than 12 months, were $175.3 million . This total does not reflect amounts that may be reimbursed by other third-parties in the normal course of business, such as non-operating working interest owners. Components of the Company’s total lease cost, whether capitalized or expensed, for the three months ended March 31, 2019 , were as follows: For the Three Months Ended March 31, 2019 (in thousands) Operating lease cost $ 8,979 Short-term lease cost (1) 134,917 Variable lease cost (2) 31,408 Total lease cost (3) $ 175,304 ____________________________________________ (1) Costs associated with short-term lease agreements relate primarily to operational activities where underlying lease terms are less than one year. This amount is significant as it includes drilling and completion activities and field equipment rentals, most of which are contracted for 12 months or less. It is expected this amount will fluctuate primarily with the number of drilling rigs and completion crews the Company is operating under short-term agreements. (2) Variable lease payments include additional payments made that were not included in the initial measurement of the ROU asset and corresponding liability for lease agreements with terms longer than 12 months. Variable lease payments relate to the actual volumes transported under certain midstream agreements, actual usage associated with drilling rigs and completion crews, and variable utility costs associated with the Company’s leased office space. Fluctuations in variable lease payments are driven by actual volumes delivered and the number of drilling rigs and completion crews operating under long-term agreements. (3) Lease costs are either expensed on the accompanying statements of operations or capitalized on the accompanying balance sheets depending on the nature and use of the underlying ROU asset. Other information related to the Company’s leases for the three months ended March 31, 2019 , was as follows: For the Three Months Ended March 31, 2019 (in thousands) Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 9,134 Right-of-use assets obtained in exchange for new operating lease liabilities $ 12,191 Maturities for the Company’s operating lease liabilities included on the accompanying balance sheets as of March 31, 2019 , were as follows: As of March 31, 2019 (in thousands) 2019 (remaining after March 31, 2019) $ 21,217 2020 16,384 2021 11,074 2022 5,123 2023 3,316 Thereafter 3,721 Total Lease payments $ 60,835 Less: Imputed interest (1) (6,339 ) Total $ 54,496 ____________________________________________ (1) The weighted-average discount rate used to determine the operating lease liability as of March 31, 2019 was 6.6 percent . Amounts recorded on the Company’s accompanying balance sheets for operating leases as of March 31, 2019 , were as follows: As of March 31, 2019 (in thousands) Other noncurrent assets $ 51,448 Other current liabilities $ 23,523 Other noncurrent liabilities $ 30,973 As of March 31, 2019 , the Company had an additional long-term operating lease arrangement for a drilling rig that commenced service in April 2019 for approximately $7.8 million with a lease term of 14 months. This agreement is not reflected in the amounts above as the commencement date was subsequent to March 31, 2019.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2019
Accounting Policies [Abstract]
Basis of Presentation, Policy [Policy Text Block]	Basis of Presentation The accompanying unaudited condensed consolidated financial statements include the accounts of the Company 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 the Company’s Annual Report on Form 10-K for the year ended December 31, 2018 (the “ 2018 Form 10-K”). In the opinion of management, all adjustments, consisting of normal recurring adjustments considered necessary for a fair presentation of interim financial information, have been included. Operating results for the periods presented are not necessarily indicative of expected results for the full year. In connection with the preparation of the Company’s unaudited condensed consolidated financial statements, the Company evaluated events subsequent to the balance sheet date of March 31, 2019 , and through the filing of this report. Certain prior period amounts have been reclassified to conform to the current presentation on the accompanying unaudited condensed consolidated financial statements.
Recently Issued Accounting Standards, Policy [Policy Text Block]	Recently Issued Accounting Standards In February 2016, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) No. 2016-02, Leases (Topic 842), followed by other related ASUs that provided targeted improvements and additional practical expedient options (collectively “ASU 2016-02” or “Topic 842”). The Company adopted ASU 2016-02 on January 1, 2019, using the modified retrospective method. The Company elected as part of its adoption to also use the optional transition methodology whereby previously reported periods continue to be reported in accordance with historical accounting guidance for leases that were in effect for those prior periods. Policy elections and practical expedients the Company has implemented in connection with the adoption of ASU 2016-02, include (a) excluding from the balance sheet leases with terms that are less than one year, (b) for agreements that contain both lease and non-lease components, combining these components together and accounting for them as a single lease, (c) the package of practical expedients, which among other requirements, allows the Company to avoid reassessing contracts that commenced prior to adoption that were properly evaluated under legacy GAAP, and (d) excluding land easements that existed or expired before adoption of ASU 2016-02. 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. Upon adoption on January 1, 2019, the Company recognized approximately $50.0 million in right-of-use (“ROU”) assets and related lease liabilities for its operating leases. There was no cumulative effect to retained earnings upon the adoption of this guidance. Please refer to Note 12 - Leases for additional discussion. Other than as disclosed in the 2018 Form 10-K, there are no ASUs 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 March 31, 2019 , and through the filing of this report.
Fair Value of Financial Instruments, Policy [Policy Text Block]	Derivatives The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivatives. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration forward commodity price curves, counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The 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 2018 Form 10-K for more information regarding the Company’s derivative instruments.
Property, Plant and Equipment, Impairment, Policy [Policy Text Block]	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 that associated carrying costs may not be recoverable. The Company uses Level 3 inputs and the income valuation technique to measure the fair value of proved properties through the application of discount rates and price forecasts representative of the current operating environment, as selected by the Company’s management. Unproved oil and gas properties. Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. To measure the fair value of unproved properties, the Company uses a market approach, which takes into account the following significant assumptions: remaining lease terms, future development plans, risk weighted potential resource recovery, estimated reserve values, and estimated acreage value based on price(s) received for similar, recent acreage transactions by the Company or other market participants. During the three months ended March 31, 2019 , and 2018 , the Company recorded $6.3 million and $5.6 million , respectively, in abandonment and impairment of unproved properties expense related to actual and anticipated lease expirations, as well as actual and anticipated losses on acreage due to title defects, changes in development plans, and other inherent acreage risks. Properties held for sale. Properties classified as held for sale, including any corresponding asset retirement obligation liability, are valued using a market approach, based on an estimated net selling price, as evidenced by the most current bid prices received from third parties, if available. If an estimated selling price is not available, the Company utilizes the various valuation techniques discussed above. Any initial write-down and subsequent changes to the fair value less estimated cost to sell is included within the net gain on divestiture activity line item in the accompanying statements of operations. There were $5.3 million of assets held for sale that were recorded at fair value less estimated costs to sell as of December 31, 2018 . There were no assets held for sale as of March 31, 2019 . For the three months ended March 31, 2018 , write-downs to fair value less estimated costs to sell on assets held for sale totaled $24.1 million . Please refer to Note 3 - Divestitures, Assets Held for Sale, and Acquisitions above and in the 2018 Form 10-K for more information regarding the Company’s oil and gas properties held for sale . Please refer to Note 1 – Summary of Significant Accounting Policies and Note 11 - Fair Value Measurements in the 2018 Form 10-K for more information regarding the Company’s approach in determining fair value of its properties.
Leases [Policy Text Block]	Arrangements classified as operating leases are included on the accompanying balance sheets within the other noncurrent assets, other current liabilities, and other noncurrent liabilities line items. For any agreement that contains both lease and non-lease components, such as a service arrangement that also includes an identifiable ROU asset, the Company’s policy for all asset classes is to combine lease and non-lease components together and account for the arrangement as a single lease. Aside from the recognition of ROU assets and corresponding lease liabilities on the accompanying balance sheets, Topic 842 will not have a material impact on the timing or classification of costs incurred for those agreements considered to be leases. As outlined in Topic 842, a ROU asset represents a lessee’s right to use an underlying asset for the lease term, while the associated lease liability represents the lessee’s obligations to make lease payments. At the commencement date, which is the date on which a lessor makes an underlying asset available for use by a lessee, a lease ROU asset and corresponding lease liability is recognized based on the present value of the future lease payments. The initial measurement of lease payments may also be adjusted for certain items, including options that are reasonably certain to be exercised, such as options to purchase the asset at the end of the lease term, or options to extend or early terminate the lease. Excluded from the initial measurement of a ROU asset and corresponding lease liability are certain variable lease payments, such as payments made that vary depending on actual usage or performance. The Company evaluates a contractual arrangement at its inception to determine if it is a lease or contains an identifiable lease component as defined by Topic 842. When evaluating a contract to determine appropriate classification and recognition under Topic 842, significant judgment may be necessary to determine, among other criteria, if an embedded leasing arrangement exists, the length of the term, classification as either an operating or financing lease, which options are reasonably likely to be exercised, fair value of the underlying ROU asset or assets, upfront costs, and future lease payments that are included or excluded in the initial measurement of the ROU asset. Certain assumptions and judgments made by the Company when evaluating a contract that meets the definition of a lease under Topic 842 include: • Discount Rate - Unless implicitly defined, the Company will determine the present value of future lease payments using an estimated incremental borrowing rate based on a yield curve analysis that factors in certain assumptions, including the term of the lease and credit rating of the Company at lease inception. • Lease Term - The Company evaluates each contract containing a lease arrangement at inception to determine the length of the lease term when recognizing a ROU asset and corresponding lease liability. When determining the lease term, options available to extend or early terminate the arrangement are evaluated and included when it is reasonably certain an option will be exercised. Because of the Company’s intent to maintain financial and operational flexibility, there are no available options to extend that the Company is reasonably certain it will exercise. Additionally, based on expectations for those agreements with early termination options, there are no leases in which early termination options are reasonably certain to be exercised.

Revenue from Contracts with C_2

Revenue from Contracts with Customers (Tables)	3 Months Ended
	Mar. 31, 2019
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue [Table Text Block]	The table below presents oil, gas, and NGL production revenue by product type for each of the Company’s operating regions for the three months ended March 31, 2019 , and 2018 : Permian South Texas & Gulf Coast Rocky Mountain Total Three Months Ended March 31, Three Months Ended March 31, Three Months Ended March 31, Three Months Ended March 31, 2019 2018 2019 2018 2019 2018 2019 2018 (in thousands) Oil production revenue $ 225,247 $ 205,794 $ 13,814 $ 19,583 $ — $ 35,683 $ 239,061 $ 261,060 Gas production revenue 15,592 24,876 49,521 52,733 — 1,500 65,113 79,109 NGL production revenue 21 124 36,281 41,770 — 823 36,302 42,717 Total $ 240,860 $ 230,794 $ 99,616 $ 114,086 $ — $ 38,006 $ 340,476 $ 382,886 Relative percentage 71 % 60 % 29 % 30 % — % 10 % 100 % 100 % ____________________________________________ Note: Amounts may not calculate due to rounding.

Income Taxes (Tables)

Income Taxes (Tables)	3 Months Ended
	Mar. 31, 2019
Income Tax Disclosure [Abstract]
Schedule of provision for income taxes [Table Text Block]	The provision for income taxes for the three months ended March 31, 2019 , and 2018 , consisted of the following: For the Three Months Ended March 31, 2019 2018 (in thousands) Current portion of income tax (expense) benefit: Federal $ — $ — State (965 ) (625 ) Deferred portion of income tax (expense) benefit 47,003 (98,366 ) Income tax (expense) benefit $ 46,038 $ (98,991 ) Effective tax rate 20.6 % 23.8 %

Long-Term Debt (Tables)

Long-Term Debt (Tables)	3 Months Ended
	Mar. 31, 2019
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 April 25, 2019 , March 31, 2019 , and December 31, 2018 : As of April 25, 2019 As of March 31, 2019 As of December 31, 2018 (in thousands) Credit facility balance (1) $ 40,000 $ 46,500 $ — Letters of credit (2) — — 200 Available borrowing capacity 1,160,000 953,500 999,800 Total aggregate lender commitment amount $ 1,200,000 $ 1,000,000 $ 1,000,000 ____________________________________________ (1) Unamortized deferred financing costs attributable to the credit facility are presented as a component of other noncurrent assets on the accompanying balance sheets and totaled $6.0 million and $6.4 million as of March 31, 2019 , and December 31, 2018 , respectively. These costs are being amortized over the term of the credit facility on a straight-line basis. (2) Letters of credit outstanding reduce the amount available under the credit facility on a dollar-for-dollar basis. The letter of credit outstanding as of December 31, 2018 , was released during the quarter ended March 31, 2019 .
Schedule of Senior Notes [Table Text Block]	The Senior Notes, net of unamortized deferred financing costs line item on the accompanying balance sheets as of March 31, 2019 , and December 31, 2018 , consisted of the following: As of March 31, 2019 As of December 31, 2018 Principal Amount Unamortized Deferred Financing Costs Principal Amount, Net of Unamortized Deferred Financing Costs Principal Amount Unamortized Deferred Financing Costs Principal Amount, Net of Unamortized Deferred Financing Costs (in thousands) 6.125% Senior Notes due 2022 $ 476,796 $ 3,671 $ 473,125 $ 476,796 $ 3,921 $ 472,875 5.0% Senior Notes due 2024 500,000 4,457 495,543 500,000 4,688 495,312 5.625% Senior Notes due 2025 500,000 5,582 494,418 500,000 5,808 494,192 6.75% Senior Notes due 2026 500,000 6,198 493,802 500,000 6,407 493,593 6.625% Senior Notes due 2027 500,000 7,300 492,700 500,000 7,533 492,467 Total $ 2,476,796 $ 27,208 $ 2,449,588 $ 2,476,796 $ 28,357 $ 2,448,439
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 March 31, 2019 , and December 31, 2018 , consisted of the following: As of March 31, 2019 As of December 31, 2018 (in thousands) Principal amount of Senior Convertible Notes $ 172,500 $ 172,500 Unamortized debt discount (20,238 ) (22,313 ) Unamortized deferred financing costs (2,063 ) (2,293 ) Senior Convertible Notes, net of unamortized discount and deferred financing costs $ 150,199 $ 147,894

Pension Benefits (Tables)

Pension Benefits (Tables)	3 Months Ended
	Mar. 31, 2019
Defined Benefit Plan [Abstract]
Components of the net periodic benefit cost for the pension plans [Table Text Block]	For the Three Months Ended March 31, 2019 2018 (in thousands) Components of net periodic benefit cost: Service cost $ 1,683 $ 1,660 Interest cost 656 673 Expected return on plan assets that reduces periodic pension benefit cost (466 ) (561 ) Amortization of prior service cost 4 4 Amortization of net actuarial loss 332 324 Net periodic benefit cost $ 2,209 $ 2,100

Earnings per Share (Tables)

Earnings per Share (Tables)	3 Months Ended
	Mar. 31, 2019
Earnings Per Share [Abstract]
Schedule of dilutive and antidilutive securities included or excluded from computation of earnings per share [Table Text Block]	The following table details the weighted-average dilutive and anti-dilutive securities for the periods presented: For the Three Months Ended March 31, 2019 2018 (in thousands) Dilutive — 1,183 Anti-dilutive 781 —
Schedule of calculations of basic and diluted net loss per common share [Table Text Block]	The following table sets forth the calculations of basic and diluted net income (loss) per common share: For the Three Months Ended March 31, 2019 2018 (in thousands, except per share data) Net income (loss) $ (177,568 ) $ 317,401 Basic weighted-average common shares outstanding 112,252 111,696 Dilutive effect of non-vested RSUs and contingent PSUs — 1,183 Dilutive effect of Senior Convertible Notes — — Diluted weighted-average common shares outstanding 112,252 112,879 Basic net income (loss) per common share $ (1.58 ) $ 2.84 Diluted net income (loss) per common share $ (1.58 ) $ 2.81

Derivative Financial Instrume_2

Derivative Financial Instruments (Tables)	3 Months Ended
	Mar. 31, 2019
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Schedule of notional amounts of outstanding derivative positions [Table Text Block]	As of March 31, 2019 , the Company had commodity derivative contracts outstanding through the fourth quarter of 2022 as summarized in the tables below. Oil Swaps Contract Period NYMEX WTI Volumes Weighted-Average Contract Price (MBbl) (per Bbl) Second quarter 2019 575 $ 55.52 Third quarter 2019 1,217 $ 61.41 Fourth quarter 2019 1,115 $ 59.97 2020 2,491 $ 65.68 Total 5,398 Oil Collars Contract Period NYMEX WTI Volumes Weighted-Average Floor Price Weighted-Average Ceiling Price (MBbl) (per Bbl) (per Bbl) Second quarter 2019 3,034 $ 52.39 $ 64.32 Third quarter 2019 2,547 $ 49.50 $ 62.64 Fourth quarter 2019 3,168 $ 50.54 $ 62.49 2020 3,405 $ 55.00 $ 63.00 Total 12,154 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) Second quarter 2019 2,571 $ (4.49 ) — $ — Third quarter 2019 3,291 $ (2.86 ) — $ — Fourth quarter 2019 3,338 $ (2.87 ) — $ — 2020 11,601 $ (1.03 ) 2,750 $ (8.03 ) 2021 3,707 $ 0.33 3,650 $ (7.86 ) 2022 — $ — 3,650 $ (7.78 ) Total 24,508 10,050 ____________________________________________ (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 IF HSC Volumes Weighted-Average Contract Price WAHA Volumes Weighted-Average Contract Price (BBtu) (per MMBtu) (BBtu) (per MMBtu) Second quarter 2019 11,177 $ 2.82 4,546 $ 0.70 Third quarter 2019 14,102 $ 2.84 4,340 $ 1.30 Fourth quarter 2019 14,433 $ 2.88 2,962 $ 1.75 2020 9,123 $ 2.98 2,060 $ 2.20 Total (1) 48,835 13,908 ____________________________________________ (1) The Company has natural gas swaps in place that settle against Inside FERC Houston Ship Channel (“IF HSC”), Inside FERC West Texas (“IF WAHA”), and Platt’s Gas Daily West Texas (“GD WAHA”). As of March 31, 2019 , total volumes for gas swaps are comprised of 78 percent IF HSC , 12 percent GD Waha , and 10 percent IF Waha . Gas Collars Contract Period IF HSC Volumes Weighted-Average Floor Price Weighted-Average Ceiling Price (BBtu) (per MMBtu) (per MMBtu) Second quarter 2019 4,358 $ 2.50 $ 2.83 Third quarter 2019 5,066 $ 2.50 $ 2.83 Fourth quarter 2019 4,818 $ 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) Second quarter 2019 877 $ 12.29 561 $ 31.32 38 $ 35.64 29 $ 35.70 49 $ 50.93 Third quarter 2019 907 $ 12.34 637 $ 31.29 39 $ 35.64 30 $ 35.70 50 $ 50.93 Fourth quarter 2019 896 $ 12.36 651 $ 31.64 39 $ 35.64 29 $ 35.70 50 $ 50.93 2020 711 $ 11.38 — $ — — $ — — $ — — $ — Total 3,391 1,849 116 88 149
Schedule of fair value of derivatives in accompanying balance sheets [Table Text Block]	The following table details the fair value of commodity derivative contracts recorded in the accompanying balance sheets, by category: As of March 31, 2019 As of December 31, 2018 (in thousands) Derivative assets: Current assets $ 67,567 $ 175,130 Noncurrent assets 27,202 58,499 Total derivative assets $ 94,769 $ 233,629 Derivative liabilities: Current liabilities $ 95,269 $ 62,853 Noncurrent liabilities 13,332 12,496 Total derivative liabilities $ 108,601 $ 75,349
Schedule of the potential effects of master netting arrangements [Table Text Block]	The following table provides a reconciliation between the gross assets and liabilities reflected on the accompanying balance sheets and the potential effects of master netting arrangements on the fair value of the Company’s commodity derivative contracts: Derivative Assets Derivative Liabilities As of As of March 31, 2019 December 31, 2018 March 31, 2019 December 31, 2018 (in thousands) Gross amounts presented in the accompanying balance sheets $ 94,769 $ 233,629 $ (108,601 ) $ (75,349 ) Amounts not offset in the accompanying balance sheets (52,882 ) (56,041 ) 52,882 56,041 Net amounts $ 41,887 $ 177,588 $ (55,719 ) $ (19,308 )
Schedule of derivative (gain) loss [Table Text Block]	The following table summarizes the components of the net derivative loss line item presented in the accompanying statements of operations: For the Three Months Ended March 31, 2019 2018 (in thousands) Derivative settlement (gain) loss: Oil contracts $ 1,369 $ 20,748 Gas contracts 4,134 (6,410 ) NGL contracts (534 ) 10,190 Total derivative settlement loss $ 4,969 $ 24,528 Net derivative (gain) loss: Oil contracts $ 185,797 $ 13,966 Gas contracts (6,113 ) 9,990 NGL contracts (2,603 ) (16,427 ) Total net derivative loss $ 177,081 $ 7,529

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2019
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 March 31, 2019 : Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 94,769 $ — Liabilities: Derivatives (1) $ — $ 108,601 $ — __________________________________________ (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, 2018 : Level 1 Level 2 Level 3 (in thousands) Assets: Derivatives (1) $ — $ 233,629 $ — Liabilities: Derivatives (1) $ — $ 75,349 $ — ____________________________________________ (1) This represents a financial asset or liability that is measured at fair value on a recurring basis.
Long Term Debt Fair Value [Table Text Block]	The following table reflects the fair value of the Company’s unsecured senior note obligations measured using Level 1 inputs based on quoted secondary market trading prices. These notes were not presented at fair value on the accompanying balance sheets as of March 31, 2019 , or December 31, 2018 , as they were recorded at carrying value, net of any unamortized discounts and deferred financing costs. Please refer to Note 5 - Long-Term Debt for additional discussion. As of March 31, 2019 As of December 31, 2018 Principal Amount Fair Value Principal Amount Fair Value (in thousands) 6.125% Senior Notes due 2022 $ 476,796 $ 477,988 $ 476,796 $ 452,336 5.0% Senior Notes due 2024 $ 500,000 $ 464,685 $ 500,000 $ 439,265 5.625% Senior Notes due 2025 $ 500,000 $ 464,820 $ 500,000 $ 436,460 6.75% Senior Notes due 2026 $ 500,000 $ 481,875 $ 500,000 $ 448,305 6.625% Senior Notes due 2027 $ 500,000 $ 476,205 $ 500,000 $ 442,500 1.50% Senior Convertible Notes due 2021 $ 172,500 $ 163,013 $ 172,500 $ 158,614

Leases (Tables)

Leases (Tables)	3 Months Ended
	Mar. 31, 2019
Lessee Disclosure [Abstract]
Components of total lease cost [Table Text Block]	Components of the Company’s total lease cost, whether capitalized or expensed, for the three months ended March 31, 2019 , were as follows: For the Three Months Ended March 31, 2019 (in thousands) Operating lease cost $ 8,979 Short-term lease cost (1) 134,917 Variable lease cost (2) 31,408 Total lease cost (3) $ 175,304 ____________________________________________ (1) Costs associated with short-term lease agreements relate primarily to operational activities where underlying lease terms are less than one year. This amount is significant as it includes drilling and completion activities and field equipment rentals, most of which are contracted for 12 months or less. It is expected this amount will fluctuate primarily with the number of drilling rigs and completion crews the Company is operating under short-term agreements. (2) Variable lease payments include additional payments made that were not included in the initial measurement of the ROU asset and corresponding liability for lease agreements with terms longer than 12 months. Variable lease payments relate to the actual volumes transported under certain midstream agreements, actual usage associated with drilling rigs and completion crews, and variable utility costs associated with the Company’s leased office space. Fluctuations in variable lease payments are driven by actual volumes delivered and the number of drilling rigs and completion crews operating under long-term agreements. (3) Lease costs are either expensed on the accompanying statements of operations or capitalized on the accompanying balance sheets depending on the nature and use of the underlying ROU asset. Other information related to the Company’s leases for the three months ended March 31, 2019 , was as follows: For the Three Months Ended March 31, 2019 (in thousands) Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 9,134 Right-of-use assets obtained in exchange for new operating lease liabilities $ 12,191
Operating lease liability maturities [Table Text Block]	Maturities for the Company’s operating lease liabilities included on the accompanying balance sheets as of March 31, 2019 , were as follows: As of March 31, 2019 (in thousands) 2019 (remaining after March 31, 2019) $ 21,217 2020 16,384 2021 11,074 2022 5,123 2023 3,316 Thereafter 3,721 Total Lease payments $ 60,835 Less: Imputed interest (1) (6,339 ) Total $ 54,496 ____________________________________________ (1) The weighted-average discount rate used to determine the operating lease liability as of March 31, 2019 was 6.6 percent .
Balance Sheet information related to operating leases [Table Text Block]	Amounts recorded on the Company’s accompanying balance sheets for operating leases as of March 31, 2019 , were as follows: As of March 31, 2019 (in thousands) Other noncurrent assets $ 51,448 Other current liabilities $ 23,523 Other noncurrent liabilities $ 30,973

Recently Issued Accounting Stan

Recently Issued Accounting Standards (Details) - USD ($) $ in Thousands	Jan. 01, 2019	Mar. 31, 2019
Lessee Disclosure [Abstract]
Right-of-use assets obtained in exchange for new operating lease liabilities	$ 50,000	$ 12,191

Disaggregation of oil, gas, and

Disaggregation of oil, gas, and NGL production revenue (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2019	Mar. 31, 2018
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	[1]	$ 340,476	$ 382,886
Relative percentage	[1]	100.00%	100.00%
Revenue, Remaining Performance Obligation, Amount		$ 0
Permian [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	[1]	240,860	$ 230,794
South Texas & Gulf Coast [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	[1]	99,616	114,086
Rocky Mountain [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	[1]	$ 0	$ 38,006
Sales Revenue, Net [Member] | Geographic Concentration Risk [Member] | Permian [Member]
Segment Reporting Information [Line Items]
Relative percentage	[1]	71.00%	60.00%
Sales Revenue, Net [Member] | Geographic Concentration Risk [Member] | South Texas & Gulf Coast [Member]
Segment Reporting Information [Line Items]
Relative percentage	[1]	29.00%	30.00%
Sales Revenue, Net [Member] | Geographic Concentration Risk [Member] | Rocky Mountain [Member]
Segment Reporting Information [Line Items]
Relative percentage	[1]	0.00%	10.00%
Oil production revenue [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	[1]	$ 239,061	$ 261,060
Oil production revenue [Member] | Permian [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		225,247	205,794
Oil production revenue [Member] | South Texas & Gulf Coast [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		13,814	19,583
Oil production revenue [Member] | Rocky Mountain [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		0	35,683
Gas production revenue [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	[1]	65,113	79,109
Gas production revenue [Member] | Permian [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		15,592	24,876
Gas production revenue [Member] | South Texas & Gulf Coast [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		49,521	52,733
Gas production revenue [Member] | Rocky Mountain [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		0	1,500
NGL production revenue [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	[1]	36,302	42,717
NGL production revenue [Member] | Permian [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		21	124
NGL production revenue [Member] | South Texas & Gulf Coast [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		36,281	41,770
NGL production revenue [Member] | Rocky Mountain [Member]
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Including Assessed Tax		$ 0	$ 823
[1]	Note: Amounts may not calculate due to rounding.

Accounts Receivable from Custom

Accounts Receivable from Customers (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Accounts Receivable [Line Items]
Accounts Receivable	$ 145,299	$ 167,536
Oil, gas, and NGL production revenue [Member]
Accounts Receivable [Line Items]
Accounts Receivable	$ 109,400	$ 107,200

Divestitures and Assets Held fo

Divestitures and Assets Held for Sale (Details) $ in Thousands	Mar. 26, 2018a	Mar. 31, 2019USD ($)	Mar. 31, 2018USD ($)	Dec. 31, 2018USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net divestiture proceeds		$ 6,114	$ 490,780
Net gain on divestiture activity		$ 61	385,369
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
Net divestiture proceeds			490,800	$ 492,200
Net gain on divestiture activity			409,200	$ 410,600
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]
Write-down of disposal group			$ 24,100

Acquisitions (Details)

Acquisitions (Details)	3 Months Ended
	Mar. 31, 2019USD ($)a	Mar. 31, 2018USD ($)
Nonmonetary Transaction [Line Items]
Carrying value of properties exchanged	$ 65,788,000	$ 0
Howard, Martin, and Midland Counties Trades 2019 [Member]
Nonmonetary Transaction [Line Items]
Net acres exchanged | a	2,000
Carrying value of properties exchanged	$ 65,800,000
Basis of accounting for assets exchanged	carryover
Gain (loss) recognized on trade	$ 0

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Components of the provision for income taxes
Federal	$ 0	$ 0
State	(965)	(625)
Deferred portion of income tax (expense) benefit	47,003	(98,366)
Income tax (expense) benefit	$ 46,038	$ (98,991)
Effective tax rate	20.60%	23.80%

Revolving Credit Facility (Deta

Revolving Credit Facility (Details) - USD ($) $ in Thousands		Apr. 25, 2019	Apr. 18, 2019	Mar. 31, 2019	Dec. 31, 2018
Line of Credit Facility [Line Items]
Credit facility balance				$ 46,500	$ 0
Line of Credit | Revolving Credit Facility
Line of Credit Facility [Line Items]
Line of credit agreement, maximum loan amount				2,500,000
Line of credit facility, current borrowing base				1,500,000
Line of credit agreement, aggregate lender commitments				1,000,000	1,000,000
Credit facility balance	[1]			46,500	0
Letters of credit	[2]			0	200
Available borrowing capacity				953,500	999,800
Unamortized deferred financing costs				$ 6,000	$ 6,400
Line of Credit | Revolving Credit Facility | Subsequent Event [Member]
Line of Credit Facility [Line Items]
Line of credit facility, current borrowing base			$ 1,600,000
Line of credit agreement, aggregate lender commitments		$ 1,200,000	$ 1,200,000
Credit facility balance		40,000
Letters of credit	[2]	0
Available borrowing capacity		$ 1,160,000
[1]	(1) Unamortized deferred financing costs attributable to the credit facility are presented as a component of other noncurrent assets on the accompanying balance sheets and totaled $6.0 million and $6.4 million as of March 31, 2019, and December 31, 2018, respectively. These costs are being amortized over the term of the credit facility on a straight-line basis.
[2]	(2) Letters of credit outstanding reduce the amount available under the credit facility on a dollar-for-dollar basis. The letter of credit outstanding as of December 31, 2018, was released during the quarter ended March 31, 2019.

Senior Notes (Details)

Senior Notes (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Senior Notes [Line Items]
Principal Amount, Net of Unamortized Deferred Financing Costs	$ 2,449,588		$ 2,448,439
Interest Costs Capitalized	$ 4,900	$ 4,500
6.125% Senior Notes due 2022 [Member]
Senior Notes [Line Items]
Senior Notes, interest rate, stated percentage	6.125%
Principal Amount	$ 476,796		476,796
Unamortized Deferred Financing Costs	(3,671)		(3,921)
Principal Amount, Net of Unamortized Deferred Financing Costs	$ 473,125		472,875
5.0% Senior Notes due 2024 [Member]
Senior Notes [Line Items]
Senior Notes, interest rate, stated percentage	5.00%
Principal Amount	$ 500,000		500,000
Unamortized Deferred Financing Costs	(4,457)		(4,688)
Principal Amount, Net of Unamortized Deferred Financing Costs	$ 495,543		495,312
5.625% Senior Notes due 2025 [Member]
Senior Notes [Line Items]
Senior Notes, interest rate, stated percentage	5.625%
Principal Amount	$ 500,000		500,000
Unamortized Deferred Financing Costs	(5,582)		(5,808)
Principal Amount, Net of Unamortized Deferred Financing Costs	$ 494,418		494,192
6.75% Senior Notes due 2026 [Member]
Senior Notes [Line Items]
Senior Notes, interest rate, stated percentage	6.75%
Principal Amount	$ 500,000		500,000
Unamortized Deferred Financing Costs	(6,198)		(6,407)
Principal Amount, Net of Unamortized Deferred Financing Costs	$ 493,802		493,593
6.625% Senior Notes due 2027 [Member]
Senior Notes [Line Items]
Senior Notes, interest rate, stated percentage	6.625%
Principal Amount	$ 500,000		500,000
Unamortized Deferred Financing Costs	(7,300)		(7,533)
Principal Amount, Net of Unamortized Deferred Financing Costs	492,700		492,467
Senior Notes
Senior Notes [Line Items]
Principal Amount	2,476,796		2,476,796
Unamortized Deferred Financing Costs	(27,208)		(28,357)
Principal Amount, Net of Unamortized Deferred Financing Costs	$ 2,449,588		$ 2,448,439

Senior Convertible Notes (Detai

Senior Convertible Notes (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Senior Convertibles Notes [Line Items]
Senior Convertible Notes, net carrying amount	$ 150,199		$ 147,894
1.50% Senior Convertible Notes Due 2021 [Member]
Senior Convertibles Notes [Line Items]
Senior Convertible Notes, principal amount	$ 172,500		172,500
Senior Convertible Notes, interest rate, stated percentage	1.50%
Senior Convertible Notes, interest expense	$ 2,700	$ 2,600
Senior Convertible Notes, unamortized debt discount	(20,238)		(22,313)
Senior Convertible Notes, unamortized deferred financing costs	(2,063)		(2,293)
Senior Convertible Notes, net carrying amount	$ 150,199		$ 147,894

Commitments (Details)

Commitments (Details) - Subsequent Event [Member] $ in Millions	May 02, 2019USD ($)
Drilling Rig Leasing Contracts [Member]
Commitments and Contingencies [Line Items]
Contractual obligation	$ 105.3
Early termination penalties for rig contracts	50
Minimum [Member] | Sand Sourcing Commitment [Member]
Commitments and Contingencies [Line Items]
Potential penalty for not meeting minimum sand sourcing requirements	0
Minimum [Member] | Completion Service Commitment [Member]
Commitments and Contingencies [Line Items]
Potential penalty for not meeting minimum completion service arrangement requirements	0
Maximum [Member] | Sand Sourcing Commitment [Member]
Commitments and Contingencies [Line Items]
Potential penalty for not meeting minimum sand sourcing requirements	10
Maximum [Member] | Completion Service Commitment [Member]
Commitments and Contingencies [Line Items]
Potential penalty for not meeting minimum completion service arrangement requirements	$ 15.7

Compensation Plans (Details)

Compensation Plans (Details) $ in Millions	Mar. 31, 2019USD ($)	Dec. 31, 2018	Mar. 31, 2019USD ($)shares	Mar. 31, 2018USD ($)
Performance Shares (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation arrangement by share-based payment award, award vesting period		3 years
Stock-based compensation expense			$ 2.8	$ 2.4
Unrecognized stock based compensation expense	$ 15.9		15.9
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation arrangement by share-based payment award, award vesting period	3 years
Stock-based compensation expense			2.7	$ 2.7
Unrecognized stock based compensation expense	$ 16.4		$ 16.4
Number of shares represented by each RSU | shares			1
Minimum [Member] | Performance Shares (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Multiplier applied to PSU awards at settlement		0
Maximum [Member] | Performance Shares (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Multiplier applied to PSU awards at settlement		2

Pension Benefits (Details)

Pension Benefits (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Components of Net Periodic Benefit Costs for the Pension Plans
Service cost	$ 1,683	$ 1,660
Interest cost	656	673
Expected return on plan assets that reduces periodic pension benefit cost	(466)	(561)
Amortization of prior service cost	4	4
Amortization of net actuarial loss	332	324
Net periodic benefit cost	$ 2,209	$ 2,100

Pension (Details)

Pension (Details) $ in Millions	3 Months Ended
	Mar. 31, 2019USD ($)
Pension Details [Abstract]
Pension plans, net gain (loss) amortization threshold	10.00%
Pension contributions	$ 4.3

Earnings per Share (Details)

Earnings per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Dilutive securities included in earnings per share	0	1,183
Anti-dilutive securities excluded from earnings per share	781	0
Calculation of basic and diluted earnings per share
Net income (loss)	$ (177,568)	$ 317,401
Basic weighted-average common shares outstanding	112,252	111,696
Dilutive effect of non-vested RSUs and contingent PSUs	0	1,183
Dilutive effect of Senior Convertible Notes	0	0
Diluted weighted-average common shares outstanding	112,252	112,879
Basic net income (loss) per common share	$ (1.58)	$ 2.84
Diluted net income (loss) per common share	(1.58)	$ 2.81
1.50% Senior Convertible Notes Due 2021 [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Senior Convertible Notes, conversion price	$ 40.50

Derivative Financial Instrume_3

Derivative Financial Instruments (Details) bbl in Thousands, BTU in Billions		May 02, 2019$ / Barrelsbbl	Mar. 31, 2019BTU$ / EnergyContent$ / Barrelsbbl
NYMEX Oil Swap Contract Second Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			575
Derivative, Swap Type, Average Fixed Price | $ / Barrels			55.52
NYMEX Oil Swap Contract Third Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			1,217
Derivative, Swap Type, Average Fixed Price | $ / Barrels			61.41
NYMEX Oil Swap Contract Fourth Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			1,115
Derivative, Swap Type, Average Fixed Price | $ / Barrels			59.97
NYMEX Oil Swap Contract, Year 2 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			2,491
Derivative, Swap Type, Average Fixed Price | $ / Barrels			65.68
NYMEX Oil Swap Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			5,398
NYMEX Oil Collar Contract Second Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			3,034
Derivative, Weighted- Average Floor Price | $ / Barrels			52.39
Derivative, Weighted-Average Ceiling Price | $ / Barrels			64.32
NYMEX Oil Collar Contract Third Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			2,547
Derivative, Weighted- Average Floor Price | $ / Barrels			49.50
Derivative, Weighted-Average Ceiling Price | $ / Barrels			62.64
NYMEX Oil Collar Contract Fourth Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			3,168
Derivative, Weighted- Average Floor Price | $ / Barrels			50.54
Derivative, Weighted-Average Ceiling Price | $ / Barrels			62.49
NYMEX Oil Collar Contract, Year 2 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			3,405
Derivative, Weighted- Average Floor Price | $ / Barrels			55
Derivative, Weighted-Average Ceiling Price | $ / Barrels			63
NYMEX Oil Collar Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			12,154
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 Second Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			2,571
Derivative, Weighted-Average Contract Price | $ / Barrels	[1]		(4.49)
WTI Midland NYMEX WTI [Member] | Oil Basis Swap Contract Third Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			3,291
Derivative, Weighted-Average Contract Price | $ / Barrels	[1]		(2.86)
WTI Midland NYMEX WTI [Member] | Oil Basis Swap Contract Fourth Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			3,338
Derivative, Weighted-Average Contract Price | $ / Barrels	[1]		(2.87)
WTI Midland NYMEX WTI [Member] | Oil Basis Swap Contract, Year 2 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			11,601
Derivative, Weighted-Average Contract Price | $ / Barrels	[1]		(1.03)
WTI Midland NYMEX WTI [Member] | Oil Basis Swap Contract, Year 3 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			3,707
Derivative, Weighted-Average Contract Price | $ / Barrels	[1]		0.33
WTI Midland NYMEX WTI [Member] | Oil Basis Swap Contract, Year 4 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			0
Derivative, Weighted-Average Contract Price | $ / Barrels	[1]		0
WTI Midland NYMEX WTI [Member] | Oil Basis Swap [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			24,508
NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract Second Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			0
Derivative, Weighted-Average Contract Price | $ / Barrels	[2]		0
NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract Third Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			0
Derivative, Weighted-Average Contract Price | $ / Barrels	[2]		0
NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract Fourth Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			0
Derivative, Weighted-Average Contract Price | $ / Barrels	[2]		0
NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract, Year 2 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			2,750
Derivative, Weighted-Average Contract Price | $ / Barrels	[2]		(8.03)
NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract, Year 3 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			3,650
Derivative, Weighted-Average Contract Price | $ / Barrels	[2]		(7.86)
NYMEX WTI ICE Brent [Member] | Oil Basis Swap Contract, Year 4 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			3,650
Derivative, Weighted-Average Contract Price | $ / Barrels	[2]		(7.78)
NYMEX WTI ICE Brent [Member] | Oil Basis Swap [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			10,050
IF HSC [Member]
Derivative Financial Instruments
Index percent of natural gas fixed swaps			78.00%
IF HSC [Member] | Gas Swaps Contract Second Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent			2.82
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU			11,177
IF HSC [Member] | Gas Swaps Contract Third Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent			2.84
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU			14,102
IF HSC [Member] | Gas Swaps Contract Fourth Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent			2.88
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU			14,433
IF HSC [Member] | Gas Swaps Contract, Year 2 [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent			2.98
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU			9,123
IF HSC [Member] | Gas Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU	[3]		48,835
IF HSC [Member] | Gas Collar Contract Second Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Weighted- Average Floor Price | $ / EnergyContent			2.50
Derivative, Weighted-Average Ceiling Price | $ / EnergyContent			2.83
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU			4,358
IF HSC [Member] | Gas Collar Contract Third Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Weighted- Average Floor Price | $ / EnergyContent			2.50
Derivative, Weighted-Average Ceiling Price | $ / EnergyContent			2.83
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU			5,066
IF HSC [Member] | Gas Collar Contract Fourth Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Weighted- Average Floor Price | $ / EnergyContent			2.50
Derivative, Weighted-Average Ceiling Price | $ / EnergyContent			2.83
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU			4,818
WAHA [Member] | Gas Swaps Contract Second Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent			0.70
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU			4,546
WAHA [Member] | Gas Swaps Contract Third Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent			1.30
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU			4,340
WAHA [Member] | Gas Swaps Contract Fourth Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent			1.75
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU			2,962
WAHA [Member] | Gas Swaps Contract, Year 2 [Member]
Derivative Financial Instruments
Derivative, Swap Type, Average Fixed Price | $ / EnergyContent			2.20
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU			2,060
WAHA [Member] | Gas Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU	[3]		13,908
GD Waha [Member]
Derivative Financial Instruments
Index percent of natural gas fixed swaps			12.00%
IF Waha [Member]
Derivative Financial Instruments
Index percent of natural gas fixed swaps			10.00%
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract Second Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			877
Derivative, Swap Type, Average Fixed Price | $ / Barrels			12.29
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract Third Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			907
Derivative, Swap Type, Average Fixed Price | $ / Barrels			12.34
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract Fourth Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			896
Derivative, Swap Type, Average Fixed Price | $ / Barrels			12.36
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contract, Year 2 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			711
Derivative, Swap Type, Average Fixed Price | $ / Barrels			11.38
OPIS Ethane Purity Mont Belvieu [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			3,391
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Second Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			561
Derivative, Swap Type, Average Fixed Price | $ / Barrels			31.32
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			637
Derivative, Swap Type, Average Fixed Price | $ / Barrels			31.29
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			651
Derivative, Swap Type, Average Fixed Price | $ / Barrels			31.64
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract, Year 2 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			0
Derivative, Swap Type, Average Fixed Price | $ / Barrels			0
OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			1,849
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Second Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			38
Derivative, Swap Type, Average Fixed Price | $ / Barrels			35.64
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			39
Derivative, Swap Type, Average Fixed Price | $ / Barrels			35.64
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			39
Derivative, Swap Type, Average Fixed Price | $ / Barrels			35.64
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contract, Year 2 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			0
Derivative, Swap Type, Average Fixed Price | $ / Barrels			0
OPIS Normal Butane Mont Belvieu Non-TET [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			116
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Second Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			29
Derivative, Swap Type, Average Fixed Price | $ / Barrels			35.70
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			30
Derivative, Swap Type, Average Fixed Price | $ / Barrels			35.70
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			29
Derivative, Swap Type, Average Fixed Price | $ / Barrels			35.70
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contract, Year 2 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			0
Derivative, Swap Type, Average Fixed Price | $ / Barrels			0
OPIS Isobutane Mont Belvieu Non-TET [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			88
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract Second Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			49
Derivative, Swap Type, Average Fixed Price | $ / Barrels			50.93
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract Third Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			50
Derivative, Swap Type, Average Fixed Price | $ / Barrels			50.93
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract Fourth Quarter of Current Fiscal Year [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			50
Derivative, Swap Type, Average Fixed Price | $ / Barrels			50.93
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contract, Year 2 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			0
Derivative, Swap Type, Average Fixed Price | $ / Barrels			0
OPIS Natural Gasoline Mont Belvieu Non-TET [Member] | NGL Swaps Contracts [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume			149
Subsequent Event [Member] | NYMEX Oil Swap Contract, Year 2 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		1,600
Derivative, Swap Type, Average Fixed Price | $ / Barrels		61.49
Subsequent Event [Member] | NYMEX Oil Collar Contract, Year 2 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		1,700
Derivative, Weighted- Average Floor Price | $ / Barrels		55
Derivative, Weighted-Average Ceiling Price | $ / Barrels		65.07
Subsequent Event [Member] | OPIS Propane Mont Belvieu Non-TET [Member] | NGL Swaps Contract, Year 2 [Member]
Derivative Financial Instruments
Derivative, Nonmonetary Notional Amount, Volume		600
Derivative, Swap Type, Average Fixed Price | $ / Barrels		28.10
[1]	(1) Represents the price differential between WTI Midland (Midland, Texas) and NYMEX WTI (Cushing, Oklahoma).
[2]	(2) Represents the price differential between NYMEX WTI (Cushing, Oklahoma) and ICE Brent (North Sea).
[3]	(1) The Company has natural gas swaps in place that settle against Inside FERC Houston Ship Channel (“IF HSC”), Inside FERC West Texas (“IF WAHA”), and Platt’s Gas Daily West Texas (“GD WAHA”). As of March 31, 2019, total volumes for gas swaps are comprised of 78 percent IF HSC, 12 percent GD Waha, and 10 percent IF Waha.

Derivative Financial Instrume_4

Derivative Financial Instruments Fair Value (Details) - USD ($) $ in Thousands	Mar. 31, 2019		Dec. 31, 2018
Fair value of derivative assets and liabilities
Derivative, fair value, net	$ (13,800)		$ 158,300
Derivative assets, current	67,567		175,130
Derivative assets, noncurrent	27,202		58,499
Total derivative assets	94,769		233,629
Derivative liabilities, current	95,269		62,853
Derivatives liabilities, noncurrent	13,332		12,496
Total derivative liabilities	108,601		75,349
Derivative asset, not offset in the accompanying balance sheets	(52,882)		(56,041)
Derivative liabilities, not offset in the accompanying balance sheets	52,882		56,041
Derivative asset, fair value, net amounts	41,887		177,588
Derivative liabilities, fair value, net amounts	(55,719)		(19,308)
Not Designated as Hedging Instrument [Member]
Fair value of derivative assets and liabilities
Derivative assets, current	67,567		175,130
Derivative assets, noncurrent	27,202		58,499
Derivative liabilities, current	95,269		62,853
Derivatives liabilities, noncurrent	13,332		12,496
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	94,769	[1]	233,629	[2]
Total derivative liabilities	$ 108,601	[1]	$ 75,349	[2]
[1]	(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.
[2]	(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.

Derivative Financial Instrume_5

Derivative Financial Instruments Gains and Losses (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Derivative Instruments, (Gain) Loss [Line Items]
Derivative settlement (gain) loss	$ 4,969	$ 24,528
Net derivative (gain) loss	177,081	7,529
Oil Contracts [Member]
Derivative Instruments, (Gain) Loss [Line Items]
Derivative settlement (gain) loss	1,369	20,748
Net derivative (gain) loss	185,797	13,966
Gas Contracts [Member]
Derivative Instruments, (Gain) Loss [Line Items]
Derivative settlement (gain) loss	4,134	(6,410)
Net derivative (gain) loss	(6,113)	9,990
NGL Contracts [Member]
Derivative Instruments, (Gain) Loss [Line Items]
Derivative settlement (gain) loss	(534)	10,190
Net derivative (gain) loss	$ (2,603)	$ (16,427)

Credit Facility and Derivative

Credit Facility and Derivative Counterparties (Details)	Mar. 31, 2019
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Percentage of Proved Property Secured for Credit Facility Borrowing	85.00%

Fair Value (Details)

Fair Value (Details) - USD ($) $ in Thousands	Mar. 31, 2019		Dec. 31, 2018
Assets
Derivatives	$ 94,769		$ 233,629
Liabilities
Derivatives	108,601		75,349
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	94,769	[1]	233,629	[2]
Liabilities
Derivatives	108,601	[1]	75,349	[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.

Proved and Unproved Oil and Gas

Proved and Unproved Oil and Gas Properties and Other Property and Equipment (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Abandonment and impairment of unproved properties	$ 6,338	$ 5,625
Properties held for sale, fair value			$ 5,300
Properties held for sale, net	$ 0		$ 5,280
Divide County Divestiture and Halff East Divestiture 2018 [Member] | Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Write-down of disposal group		$ 24,100

Long-term Debt (Details)

Long-term Debt (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
6.125% Senior Notes due 2022 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Principal Amount	$ 476,796	$ 476,796
Long-term Debt, Fair Value	$ 477,988	452,336
Senior Notes, interest rate, stated percentage	6.125%
5.0% Senior Notes due 2024 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Principal Amount	$ 500,000	500,000
Long-term Debt, Fair Value	$ 464,685	439,265
Senior Notes, interest rate, stated percentage	5.00%
5.625% Senior Notes due 2025 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Principal Amount	$ 500,000	500,000
Long-term Debt, Fair Value	$ 464,820	436,460
Senior Notes, interest rate, stated percentage	5.625%
6.75% Senior Notes due 2026 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Principal Amount	$ 500,000	500,000
Long-term Debt, Fair Value	$ 481,875	448,305
Senior Notes, interest rate, stated percentage	6.75%
6.625% Senior Notes due 2027 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Principal Amount	$ 500,000	500,000
Long-term Debt, Fair Value	$ 476,205	442,500
Senior Notes, interest rate, stated percentage	6.625%
1.50% Senior Convertible Notes Due 2021 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Principal Amount	$ 172,500	172,500
Long-term Debt, Fair Value	$ 163,013	$ 158,614
Senior Notes, interest rate, stated percentage	1.50%

Lease Parameter (Details)

Lease Parameter (Details)	Mar. 31, 2019
Lessee, Lease, Description [Line Items]
Weighted-average remaining lease term	3 years 2 months 12 days
Optional extension period	10 years
Minimum [Member]
Lessee, Lease, Description [Line Items]
Remaining lease term	1 year
Maximum [Member]
Lessee, Lease, Description [Line Items]
Remaining lease term	7 years

Components of total lease cost

Components of total lease cost (Details) - USD ($) $ in Thousands		Jan. 01, 2019	Mar. 31, 2019
Lessee Disclosure [Abstract]
Total lease cost	[1]		$ 175,304
Operating lease cost			8,979
Short-term lease cost	[2]		134,917
Variable lease cost	[3]		31,408
Operating cash flows from operating leases			9,134
Right-of-use assets obtained in exchange for new operating lease liabilities		$ 50,000	$ 12,191
[1]	(3) Lease costs are either expensed on the accompanying statements of operations or capitalized on the accompanying balance sheets depending on the nature and use of the underlying ROU asset.
[2]	(1) Costs associated with short-term lease agreements relate primarily to operational activities where underlying lease terms are less than one year. This amount is significant as it includes drilling and completion activities and field equipment rentals, most of which are contracted for 12 months or less. It is expected this amount will fluctuate primarily with the number of drilling rigs and completion crews the Company is operating under short-term agreements.
[3]	(2) Variable lease payments include additional payments made that were not included in the initial measurement of the ROU asset and corresponding liability for lease agreements with terms longer than 12 months. Variable lease payments relate to the actual volumes transported under certain midstream agreements, actual usage associated with drilling rigs and completion crews, and variable utility costs associated with the Company’s leased office space. Fluctuations in variable lease payments are driven by actual volumes delivered and the number of drilling rigs and completion crews operating under long-term agreements.

Operating lease liability matur

Operating lease liability maturities (Details) $ in Thousands	Mar. 31, 2019USD ($)
Lessee Disclosure [Abstract]
Operating lease liability payments, due 2019 (remaining after March 31, 2019)	$ 21,217
Operating lease liability payments, due 2020	16,384
Operating lease liability payments, due 2021	11,074
Operating lease liability payments, due 2022	5,123
Operating lease liability payments, due 2023	3,316
Operating lease liability payments, due thereafter	3,721
Total lease payments	60,835
Imputed interest	(6,339)	[1]
Total operating lease liability	$ 54,496
Weighted-average discount rate	6.60%
Operating lease not yet commenced, amount	$ 7,800
Operating lease not yet commenced, term	14 months
[1]	(1) The weighted-average discount rate used to determine the operating lease liability as of March 31, 2019 was 6.6 percent.

Balance Sheet information relat

Balance Sheet information related to operating leases (Details) $ in Thousands	Mar. 31, 2019USD ($)
Lessee Disclosure [Abstract]
Other noncurrent assets, portion related to ROU assets	$ 51,448
Other current liabilities, portion related to operating leases	23,523
Other noncurrent liabilities, portion related to operating leases	$ 30,973