Continental Resources Inc (CLR) 10-K 21 Feb 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2017	Jan. 31, 2018	Jun. 30, 2017
Entity Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Trading Symbol	CLR
Entity Registrant Name	CONTINENTAL RESOURCES, INC
Entity Central Index Key	732,834
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		375,215,902
Entity Public Float			$ 2.8

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 43,902	$ 16,643
Receivables:
Crude oil and natural gas sales	671,665	404,750
Affiliated parties	63	99
Joint interest and other, net	426,585	364,850
Derivative assets	2,603	4,061
Inventories	97,406	111,987
Prepaid expenses and other	9,501	10,843
Total current assets	1,251,725	913,233
Net property and equipment, based on successful efforts method of accounting	12,933,789	12,881,227
Other noncurrent assets	14,137	17,316
Total assets	14,199,651	13,811,776
Current liabilities:
Accounts payable trade	692,908	476,342
Revenues and royalties payable	374,831	217,425
Payables to affiliated parties	143	148
Accrued liabilities and other	260,074	176,770
Derivative liabilities	0	59,489
Current portion of long-term debt	2,286	2,219
Total current liabilities	1,330,242	932,393
Long-term debt, net of current portion	6,351,405	6,577,697
Other noncurrent liabilities:
Deferred income tax liabilities, net	1,259,558	1,890,305
Asset retirement obligations, net of current portion	111,794	94,436
Noncurrent derivative liabilities	0	0
Other noncurrent liabilities	15,449	14,949
Total other noncurrent liabilities	1,386,801	1,999,690
Commitments and contingencies (Note 10)
Shareholders’ equity:
Preferred stock, $0.01 par value; 25,000,000 shares authorized; no shares issued and outstanding	0	0
Common stock, $0.01 par value; 1,000,000,000 shares authorized; 375,219,769 shares issued and outstanding at December 31, 2017; 374,492,357 shares issued and outstanding at December 31, 2016	3,752	3,745
Additional paid-in capital	1,409,326	1,375,290
Accumulated other comprehensive loss	307	(260)
Retained earnings	3,717,818	2,923,221
Total shareholders’ equity	5,131,203	4,301,996
Total liabilities and shareholders’ equity	$ 14,199,651	$ 13,811,776

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2017	Dec. 31, 2016
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	25,000,000	25,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Common stock, shares authorized	1,000,000,000	1,000,000,000
Common stock, shares issued	375,219,769	374,492,357
Common stock, outstanding	375,219,769	374,492,357

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues:
Crude oil and natural gas sales	$ 2,982,966	$ 2,026,958	$ 2,551,131
Crude oil and natural gas sales to affiliates	0	0	1,400
Gain (loss) on crude oil and natural gas derivatives, net	91,647	(71,859)	91,085
Crude oil and natural gas service operations	46,215	25,174	36,551
Total revenues	3,120,828	1,980,273	2,680,167
Operating costs and expenses:
Production expenses	324,214	289,289	347,243
Production expenses to affiliates	0	0	1,654
Production taxes	208,278	142,388	200,637
Exploration expenses	12,393	16,972	19,413
Crude oil and natural gas service operations	16,880	11,386	17,337
Depreciation, depletion, amortization and accretion	1,674,901	1,708,744	1,749,056
Property impairments	237,370	237,292	402,131
General and administrative expenses	191,706	169,580	189,846
Litigation settlement	59,600	0	0
Net gain on sale of assets and other	(53,915)	(307,844)	(23,149)
Total operating costs and expenses	2,671,427	2,267,807	2,904,168
Income (loss) from operations	449,401	(287,534)	(224,001)
Other income (expense):
Interest expense	(294,495)	(320,562)	(313,079)
Loss on extinguishment of debt	(554)	(26,055)	0
Other	1,715	1,697	1,995
Total other income (expense)	(293,334)	(344,920)	(311,084)
Income (loss) before income taxes	156,067	(632,454)	(535,085)
Benefit for income taxes	633,380	232,775	181,417
Net income (loss)	$ 789,447	$ (399,679)	$ (353,668)
Basic net income (loss) per share (in dollars per share)	$ 2.13	$ (1.08)	$ (0.96)
Diluted net income (loss) per share (in dollars per share)	$ 2.11	$ (1.08)	$ (0.96)
Foreign currency translation adjustments	$ 567	$ 3,094	$ (2,969)
Other Comprehensive Income (Loss), Net of Tax	567	3,094	(2,969)
Comprehensive Income (Loss)	$ 790,014	$ (396,585)	$ (356,637)

Consolidated Statements of Shar

Consolidated Statements of Shareholders' Equity - USD ($) $ in Thousands	Total	Common stock	Additional paid-in capital	Accumulated Other Comprehensive Loss	Retained earnings
Balance at Dec. 31, 2014	$ 4,967,844	$ 3,720	$ 1,287,941	$ (385)	$ 3,676,568
Balance, shares at Dec. 31, 2014		372,005,502
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(353,668)				(353,668)
Other Comprehensive Income (Loss), Net of Tax	(2,969)			(2,969)
Stock-based compensation	51,817		51,817
Excess Tax Benefit from Share-based Compensation	13,177		13,177
Restricted stock:
Issued	15	$ 15	0
Issued, shares		1,462,534
Repurchased and canceled	(7,313)	$ (2)	(7,311)
Repurchased and canceled, shares		(172,786)
Forfeited	(3)	$ (3)
Forfeited, shares		(336,170)
Balance at Dec. 31, 2015	4,668,900	$ 3,730	1,345,624	(3,354)	3,322,900
Balance, shares at Dec. 31, 2015		372,959,080
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(399,679)				(399,679)
Other Comprehensive Income (Loss), Net of Tax	3,094			3,094
Stock-based compensation	48,084		48,084
Excess Tax Benefit from Share-based Compensation	(9,828)		(9,828)
Restricted stock:
Issued	20	$ 20	0
Issued, shares		2,064,508
Repurchased and canceled	(8,593)	$ (3)	(8,590)
Repurchased and canceled, shares		(337,981)
Forfeited	(2)	$ (2)
Forfeited, shares		(193,250)
Balance at Dec. 31, 2016	$ 4,301,996	$ 3,745	1,375,290	(260)	2,923,221
Balance, shares at Dec. 31, 2016	374,492,357	374,492,357
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	$ 789,447				789,447
Other Comprehensive Income (Loss), Net of Tax	567			567
Stock-based compensation	45,854		45,854
Restricted stock:
Issued	16	$ 16	0
Issued, shares		1,585,870
Repurchased and canceled	(11,821)	$ (3)	(11,818)
Repurchased and canceled, shares		(259,729)
Forfeited	(6)	$ (6)
Forfeited, shares		(598,729)
Cumulative Effect on Retained Earnings, Net of Tax	5,150				5,150
Balance at Dec. 31, 2017	$ 5,131,203	$ 3,752	$ 1,409,326	$ 307	$ 3,717,818
Balance, shares at Dec. 31, 2017	375,219,769	375,219,769

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash flows from operating activities:
Net income (loss)	$ 789,447	$ (399,679)	$ (353,668)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion, amortization and accretion	1,670,838	1,709,567	1,746,454
Property impairments	237,370	237,292	402,131
Non-cash (gain) loss on derivatives, net	(58,031)	156,621	(21,532)
Stock-based compensation	45,868	48,098	51,834
Tax benefit from US tax reform legislation	(713,655)	0	0
Provision (benefit) for deferred income taxes from operations	88,056	(209,836)	(181,441)
Tax deficiency (benefit) from stock-based compensation	0	9,828	(13,177)
Dry hole costs	176	4,866	8,381
Litigation settlement	59,600	0	0
Net gain on sale of assets and other	(55,124)	(304,489)	(23,149)
Loss on extinguishment of debt	554	26,055	0
Other, net	12,592	9,812	12,646
Changes in assets and liabilities:
Accounts receivable	(329,811)	(158,383)	524,973
Inventories	14,517	(17,836)	7,997
Other current assets	1,038	968	65,493
Accounts payable trade	137,339	(14,404)	(201,434)
Revenues and royalties payable	158,982	30,455	(85,754)
Accrued liabilities and other	21,368	(883)	(84,056)
Other noncurrent assets and liabilities	(2,018)	(2,133)	1,403
Net cash provided by operating activities	2,079,106	1,125,919	1,857,101
Cash flows from investing activities:
Exploration and development	(1,931,942)	(1,154,131)	(3,042,747)
Purchase of producing crude oil and natural gas properties	(8,446)	(5,008)	(557)
Purchase of other property and equipment	(12,810)	(5,375)	(36,951)
Proceeds from sale of assets	144,353	631,549	34,008
Net cash used in investing activities	(1,808,845)	(532,965)	(3,046,247)
Cash flows from financing activities:
Credit facility borrowings	1,302,000	1,691,000	2,001,000
Repayment of credit facility	(2,019,000)	(1,639,000)	(1,313,000)
Proceeds from issuance of Senior Notes	990,000	0	0
Redemption of Senior Notes	0	(600,000)	0
Premium on redemption of Senior Notes	0	(19,168)	0
Proceeds from other debt	0	0	500,000
Repayment of other debt	(502,214)	(2,144)	(2,078)
Debt issuance costs	(1,999)	(40)	(4,597)
Repurchase of restricted stock for tax withholdings	(11,821)	(8,593)	(7,313)
Tax (deficiency) benefit from stock-based compensation	0	(9,828)	13,177
Net cash (used in) provided by financing activities	(243,034)	(587,773)	1,187,189
Effect of exchange rate on cash and cash equivalents	32	(1)	(10,961)
Net change in cash and cash equivalents	27,259	5,180	(12,918)
Cash and cash equivalents at beginning of period	16,643	11,463	24,381
Cash and cash equivalents at end of period	$ 43,902	$ 16,643	$ 11,463

Organization and Summary of Sig

Organization and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Summary of Significant Accounting Policies	Organization and Summary of Significant Accounting Policies Description of the Company Continental Resources, Inc. (the “Company”) was originally formed in 1967 and is incorporated under the laws of the State of Oklahoma. The Company’s principal business is crude oil and natural gas exploration, development and production with properties primarily located in the North, South, and East regions of the United States. The North region consists of properties north of Kansas and west of the Mississippi River and includes North Dakota Bakken, Montana Bakken, and the Red River units. The South region includes all properties south of Nebraska and west of the Mississippi River including various plays in the SCOOP (South Central Oklahoma Oil Province) and STACK (Sooner Trend Anadarko Canadian Kingfisher) areas of Oklahoma. The East region is primarily comprised of undeveloped leasehold acreage east of the Mississippi River with no significant drilling or production operations. A substantial portion of the Company’s operations is located in the North region, with that region comprising approximately 59% of the Company’s crude oil and natural gas production and approximately 69% of its crude oil and natural gas revenues for the year ended December 31, 2017 . The Company’s principal producing properties in the North region are located in the Bakken field of North Dakota and Montana. As of December 31, 2017 , approximately 50% of the Company’s estimated proved reserves were located in the North region. In recent years, the Company has significantly expanded its operations in the South region with its increased activity in the SCOOP and STACK plays. The South region comprised approximately 41% of the Company’s crude oil and natural gas production, 31% of its crude oil and natural gas revenues, and 50% of its estimated proved reserves as of and for the year ended December 31, 2017 . For the year ended December 31, 2017 , crude oil accounted for approximately 57% of the Company’s total production and approximately 78% of its crude oil and natural gas revenues. Crude oil represents approximately 48% of the Company’s estimated proved reserves as of December 31, 2017 . Basis of presentation of consolidated financial statements The consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are 100% owned, after all significant intercompany accounts and transactions have been eliminated upon consolidation. Use of estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure and estimation of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Actual results may differ from those estimates. The most significant estimates and assumptions impacting reported results are estimates of the Company’s crude oil and natural gas reserves, which are used to compute depreciation, depletion, amortization and impairment of proved crude oil and natural gas properties. Revenue recognition Crude oil and natural gas sales result from interests owned by the Company in crude oil and natural gas properties. Sales of crude oil and natural gas produced from crude oil and natural gas operations are recognized when the product is delivered to the purchaser and title transfers to the purchaser. Payment is generally received one to three months after the sale has occurred. The Company uses the sales method of accounting for natural gas imbalances in those circumstances where it has under-produced or over-produced its ownership percentage in a property. Under this method, a receivable or payable is recognized only to the extent an imbalance cannot be recouped from the reserves in the underlying properties. The Company’s aggregate imbalance positions at December 31, 2017 and 2016 were not material. New accounting rules governing the recognition and presentation of revenues went into effect on January 1, 2018. See the subsequent section titled " New accounting pronouncements not yet adopted at December 31, 2017–Revenue recognition and presentation" for discussion of the expected impact of the new rules on the Company's future financial statements. Cash and cash equivalents The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The Company maintains its cash and cash equivalents in accounts that may not be federally insured. As of December 31, 2017 , the Company had cash deposits in excess of federally insured amounts of approximately $42.5 million . The Company has not experienced any losses in such accounts and believes it is not exposed to significant credit risk in this area. Accounts receivable The Company operates exclusively in crude oil and natural gas exploration and production related activities. Receivables arising from crude oil and natural gas sales and joint interest receivables are generally unsecured. Accounts receivable are due within 30 days and are considered delinquent after 60 days. The Company determines its allowance for doubtful accounts by considering a number of factors, including the length of time accounts are past due, the Company’s history of losses, and the customer or working interest owner’s ability to pay. The Company writes off specific receivables when they become noncollectable and any payments subsequently received on those receivables are credited to the allowance for doubtful accounts. Write-offs of noncollectable receivables have historically not been material. The Company’s allowance for doubtful accounts totaled $2.2 million and $3.0 million as of December 31, 2017 and 2016 , respectively, which is included in “Receivables — Joint interest and other, net” on the consolidated balance sheets. Concentration of credit risk The Company is subject to credit risk resulting from the concentration of its crude oil and natural gas receivables with several significant purchasers. For the year ended December 31, 2017 , sales to the Company’s two largest purchasers accounted for approximately 11% and 11% , respectively, of the Company’s total crude oil and natural gas sales. No other purchaser accounted for more than 10% of the Company’s total crude oil and natural gas sales for 2017 . The Company does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers in various regions. Inventories Inventory is comprised of crude oil held in storage or as line fill in pipelines and tubular goods and equipment to be used in the Company’s exploration and development activities. Crude oil inventories are valued at the lower of cost or market primarily using the first-in, first-out inventory method. Tubular goods and equipment are valued primarily using a weighted average cost method applied to specific classes of inventory items. The components of inventory as of December 31, 2017 and 2016 consisted of the following: December 31, In thousands 2017 2016 Tubular goods and equipment $ 14,946 $ 15,243 Crude oil 82,460 96,744 Total $ 97,406 $ 111,987 Crude oil and natural gas properties The Company uses the successful efforts method of accounting for crude oil and natural gas properties whereby costs incurred to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, to drill and equip development wells, and expenditures for enhanced recovery operations are capitalized. Geological and geophysical costs, seismic costs incurred for exploratory projects, lease rentals and costs associated with unsuccessful exploratory wells or projects are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. To the extent a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between capitalized development costs and exploration expense. Maintenance, repairs and costs of injection are expensed as incurred, except that the costs of replacements or renewals that expand capacity or improve production are capitalized. Under the successful efforts method of accounting, the Company capitalizes exploratory drilling costs on the balance sheet pending determination of whether the well has found proved reserves in economically producible quantities. The Company capitalizes costs associated with the acquisition or construction of support equipment and facilities with the drilling and development costs to which they relate. If proved reserves are found by an exploratory well, the associated capitalized costs become part of well equipment and facilities. However, if proved reserves are not found, the capitalized costs associated with the well are expensed, net of any salvage value. Production expenses are those costs incurred by the Company to operate and maintain its crude oil and natural gas properties and associated equipment and facilities. Production expenses include but are not limited to labor costs to operate the Company’s properties, repairs and maintenance, waste water disposal costs, utility costs, certain workover-related costs, and materials and supplies utilized in the Company’s operations. Service property and equipment Service property and equipment consist primarily of automobiles and aircraft; machinery and equipment; gathering and recycling systems; storage tanks; office and computer equipment, software, furniture and fixtures; and buildings and improvements. Major renewals and replacements are capitalized and stated at cost, while maintenance and repairs are expensed as incurred. Depreciation and amortization of service property and equipment are provided in amounts sufficient to expense the cost of depreciable assets to operations over their estimated useful lives using the straight-line method. The estimated useful lives of service property and equipment are as follows: Service property and equipment Useful Lives In Years Automobiles and aircraft 5-10 Machinery and equipment 6-10 Gathering and recycling systems 15-30 Storage tanks 10-30 Office and computer equipment, software, furniture and fixtures 3-25 Buildings and improvements 4-40 Depreciation, depletion and amortization Depreciation, depletion and amortization of capitalized drilling and development costs of producing crude oil and natural gas properties, including related support equipment and facilities, are computed using the unit-of-production method on a field basis based on total estimated proved developed reserves. Amortization of producing leaseholds is based on the unit-of-production method using total estimated proved reserves. In arriving at rates under the unit-of-production method, the quantities of recoverable crude oil and natural gas reserves are established based on estimates made by the Company’s internal geologists and engineers and external independent reserve engineers. Upon sale or retirement of properties, the cost and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss, if any, is recognized. Unit of production rates are revised whenever there is an indication of a need, but at least in conjunction with semi-annual reserve reports. Revisions are accounted for prospectively as changes in accounting estimates. Asset retirement obligations The Company accounts for its asset retirement obligations by recording the fair value of a liability for an asset retirement obligation in the period in which a legal obligation is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the capitalized asset retirement costs are charged to expense through the depreciation, depletion and amortization of crude oil and natural gas properties and the liability is accreted to the expected future abandonment cost ratably over the related asset’s life. The Company’s primary asset retirement obligations relate to future plugging and abandonment costs and related disposal of facilities on its crude oil and natural gas properties. The following table summarizes the changes in the Company’s future abandonment liabilities from January 1, 2015 through December 31, 2017 : In thousands 2017 2016 2015 Asset retirement obligations at January 1 $ 96,178 $ 102,909 $ 76,708 Accretion expense 5,886 6,086 4,740 Revisions (1) 7,801 (12,755 ) 15,068 Plus: Additions for new assets 6,884 2,692 7,404 Less: Plugging costs and sold assets (2,343 ) (2,754 ) (1,011 ) Total asset retirement obligations at December 31 $ 114,406 $ 96,178 $ 102,909 Less: Current portion of asset retirement obligations at December 31 (2) 2,612 1,742 1,658 Non-current portion of asset retirement obligations at December 31 $ 111,794 $ 94,436 $ 101,251 (1) Revisions primarily represent changes in the present value of liabilities resulting from changes in estimated costs and economic lives of producing properties. (2) Balance is included in the caption “Accrued liabilities and other” in the consolidated balance sheets. As of December 31, 2017 and 2016 , net property and equipment on the consolidated balance sheets included $40.3 million and $34.0 million , respectively, of net asset retirement costs. Asset impairment Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter. The estimated future cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value. Non-producing crude oil and natural gas properties primarily consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Impairment losses for non-producing properties are recognized by amortizing the portion of the properties’ costs which management estimates will not be transferred to proved properties over the lives of the leases based on drilling plans, experience of successful drilling, and the average holding period. The Company’s impairment assessments are affected by economic factors such as the results of exploration activities, commodity price outlooks, anticipated drilling programs, remaining lease terms, and potential shifts in business strategy employed by management. Debt issuance costs Costs incurred in connection with the execution of the Company’s note payable and revolving credit facility and any amendments thereto are capitalized and amortized over the terms of the arrangements on a straight-line basis, the use of which approximates the effective interest method. Costs incurred upon the issuances of the Company’s various senior notes (collectively, the “Notes”) were capitalized and are being amortized over the terms of the Notes using the effective interest method. The Company had aggregate capitalized costs of $58.2 million and $55.9 million (net of accumulated amortization of $65.9 million and $56.8 million ) relating to its long-term debt at December 31, 2017 and 2016 , respectively. Unamortized capitalized costs associated with the Company’s Notes and note payable totaled $55.0 million and $50.4 million at December 31, 2017 and 2016 , respectively, and are reflected as a reduction of “Long-term debt, net of current portion” on the consolidated balance sheets. The increase in 2017 resulted from the capitalization of costs incurred in connection with the Company’s issuance of 4.375% Senior Notes due 2028 as discussed in Note 7. Long-Term Debt . Unamortized capitalized costs associated with the Company’s revolving credit facility totaled $3.2 million and $5.5 million at December 31, 2017 and 2016 , respectively, and are reflected in “Other noncurrent assets” on the consolidated balance sheets. For the years ended December 31, 2017 , 2016 and 2015 , the Company recognized amortization expense associated with capitalized debt issuance costs of $9.1 million , $9.8 million and $8.9 million , respectively, which are reflected in “Interest expense” on the consolidated statements of comprehensive income (loss). Derivative instruments The Company recognizes its derivative instruments on the balance sheet as either assets or liabilities measured at fair value with such amounts classified as current or long-term based on contractual settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the changes in fair value in the consolidated statements of comprehensive income (loss). Gains and losses on crude oil and natural gas derivatives are reflected in the caption “ Gain (loss) on crude oil and natural gas derivatives, net .” Gains and losses on diesel fuel derivatives are reflected in the caption “Operating costs and expenses—Net gain on sale of assets and other.” Fair value of financial instruments The Company’s financial instruments consist primarily of cash, trade receivables, trade payables, derivative instruments and long-term debt. See Note 6. Fair Value Measurements for a discussion of the methods used to determine fair value for the Company’s financial instruments and the quantification of fair value for its derivatives and long-term debt obligations at December 31, 2017 and 2016 . Income taxes Income taxes are accounted for using the liability method under which deferred income taxes are recognized for the future tax effects of temporary differences between financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year-end. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. On December 22, 2017, the Tax Cuts and Jobs Act (the "Tax Reform Act") was signed into law, which among other things reduces the federal corporate income tax rate from 35% to 21% effective January 1, 2018. In accordance with U.S. GAAP, the Company remeasured its deferred income tax assets and liabilities as of December 31, 2017 to reflect the reduced tax rate. See Note 8. Income Taxes for further discussion of the Tax Reform Act and its impact on the Company's financial statements as of and for the year ended December 31, 2017 . The Company’s policy is to recognize penalties and interest related to unrecognized tax benefits, if any, in income tax expense. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized. The Company recorded valuation allowances of $0.4 million , $1.0 million , and $13.5 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively, against deferred tax assets associated with operating loss carryforwards generated by its Canadian subsidiary for which the Company does not expect to realize a benefit. Earnings per share Basic net income (loss) per share is computed by dividing net income (loss) by the weighted-average number of shares outstanding for the period. In periods where the Company has net income, diluted earnings per share reflects the potential dilution of non-vested restricted stock awards, which are calculated using the treasury stock method. The following table presents the calculation of basic and diluted weighted average shares outstanding and net income (loss) per share for the years ended December 31, 2017 , 2016 and 2015 . Year ended December 31, In thousands, except per share data 2017 2016 2015 Net income (loss) (numerator) (1) $ 789,447 $ (399,679 ) $ (353,668 ) Weighted average shares (denominator): Weighted average shares - basic 371,066 370,380 369,540 Non-vested restricted stock (2) 2,702 — — Weighted average shares - diluted 373,768 370,380 369,540 Net income (loss) per share: (1) Basic $ 2.13 $ (1.08 ) $ (0.96 ) Diluted $ 2.11 $ (1.08 ) $ (0.96 ) (1) The Company’s remeasurement of its deferred income tax assets and liabilities in response to the enactment of the Tax Reform Act in December 2017 resulted in a one-time decrease in income tax expense and corresponding increase in net income of approximately $713.7 million ( $1.92 per basic share and $1.91 per diluted share) for the year ended December 31, 2017 . See Note 8. Income Taxes for further discussion. Additionally, 2017 results include a $59.6 million pre-tax loss accrual recognized in conjunction with a litigation settlement as discussed in Note 10. Commitments and Contingencies , which resulted in an after-tax decrease in 2017 net income of $37.0 million ( $0.10 per basic and diluted share). (2) For the years ended December 31, 2016 and 2015, the Company had a net loss and therefore the potential dilutive effect of approximately 2,303,000 and 1,567,000 weighted average non-vested restricted shares, respectively, were not included in the calculation of diluted net loss per share because to do so would have been anti-dilutive to the computations. Foreign currency translation In 2014, the Company initiated exploratory drilling activities in Canada through a 100%-owned Canadian subsidiary. The Company’s operations in Canada are currently immaterial. The Company has designated the Canadian dollar as the functional currency for its Canadian operations. Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in “Accumulated other comprehensive income (loss)” within shareholders’ equity on the consolidated balance sheets. Adoption of new accounting pronouncements Stock-based compensation – In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting , which changes how companies account for certain aspects of share-based payment awards, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. The Company adopted the new standard on January 1, 2017 as required. The impact of adoption is described below. ASU 2016-09 removes the requirement to delay recognition of an excess tax benefit until it reduces current taxes payable. An excess tax benefit (tax deficiency) arises when stock-based compensation expense recognized in an entity’s tax return exceeds (is less than) the expense recognized in an entity’s financial statements. Under the new standard, effective January 1, 2017 excess tax benefits are recorded when they arise. This change was required to be applied on a modified retrospective basis by recording a cumulative effect adjustment to opening retained earnings upon adoption to account for previously unrecognized excess tax benefits. The Company’s cumulative effect adjustment recorded under the new standard resulted in a $5.2 million increase in retained earnings and corresponding decrease in deferred income tax liabilities at January 1, 2017. Additionally, under ASU 2016-09 companies no longer record excess tax benefits and deficiencies in additional paid-in capital. Instead, excess tax benefits and deficiencies are recognized as income tax benefit or expense in the income statement, effective January 1, 2017 on a prospective basis. This is expected to result in increased volatility in income tax expense/benefit and corresponding variations in the relationship between income tax expense/benefit and pre-tax income/loss from period to period. The Company recognized $3.9 million ( $0.01 per basic and diluted share) of tax deficiencies from stock-based compensation as income tax expense for the year ended December 31, 2017 under the new standard, which is reflected in “Benefit for income taxes” in the consolidated statements of comprehensive income (loss). ASU 2016-09 also removed the requirement that entities present excess tax benefits and deficiencies as offsetting cash flows from financing and operating activities in the statement of cash flows. Instead, ASU 2016-09 requires cash flows related to excess tax benefits and deficiencies be classified as operating activities in the same manner as other cash flows related to income taxes. The Company has elected to apply this guidance on a prospective basis. Accordingly, the cash flow presentation of excess tax benefits and deficiencies in periods prior to January 1, 2017 has not been adjusted to conform to current period presentation. The Company has elected to continue its historical accounting practice of estimating forfeitures in determining the amount of stock-based compensation expense to recognize. Therefore, the adoption of ASU 2016-09 does not have an impact on the amount of stock-based compensation expense to be recognized by the Company on non-vested restricted stock awards. Business combinations – In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business , which changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities is deemed to be a business. Determining whether a transferred set constitutes a business is important because the accounting for a business combination differs from that of an asset acquisition. The definition of a business also affects the accounting for dispositions. Under the new standard, when substantially all of the fair value of assets acquired is concentrated in a single asset, or a group of similar assets, the assets acquired would not represent a business and business combination accounting would not be required. The new standard may result in more transactions being accounted for as asset acquisitions rather than business combinations. The standard is effective for interim and annual periods beginning after December 15, 2017 and shall be applied prospectively. The Company early adopted ASU 2017-01 as of January 1, 2017, which had no significant impact on the Company’s financial statements as of and for the year ended December 31, 2017. New accounting pronouncements not yet adopted at December 31, 2017 Revenue recognition and presentation – In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) , which generally requires an entity to identify performance obligations in its contracts, estimate the amount of consideration to be received in the transaction price, allocate the transaction price to each separate performance obligation, and recognize revenue as obligations are satisfied. Additionally, the standard requires expanded disclosures related to revenue recognition. Subsequent to the issuance of ASU 2014-09, the FASB issued various clarifications and interpretive guidance to assist entities with implementation efforts, including guidance pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis. Under this guidance, an entity generally shall record revenue on a gross basis if it controls a promised good or service before transferring it to a customer, whereas an entity shall record revenue on a net basis if its role is to arrange for another entity to provide the goods or services to a customer. Significant judgment may be required in some circumstances to determine whether gross or net presentation is appropriate. ASU 2014-09 and related interpretive guidance is effective for interim and annual periods beginning after December 15, 2017 and allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. The Company adopted the standard on January 1, 2018 using the modified retrospective approach, which had no cumulative effect impact on retained earnings upon adoption. The standard is not expected to have a material effect on the timing of the Company’s revenue recognition or its financial position, results of operations, net income, or cash flows, but will impact the Company’s revenue-related disclosures and internal controls over financial reporting beginning January 1, 2018. Additionally, the standard will impact the Company's future presentation of revenues and expenses under the gross-versus-net presentation guidance. Historically, the Company has generally presented its revenues net of transportation costs. The new guidance will result in future revenues and associated transportation expenses for certain of the Company’s operated properties being reported on a gross basis beginning January 1, 2018. The changes from net to gross presentation will result in an increase in revenues and a corresponding increase in separately reported transportation expenses, with no net effect on the Company’s results of operations, net income, or cash flows. For the year ended December 31, 2017 , the Company had approximately $201.5 million of transportation–related charges on operated properties included in “Crude oil and natural gas sales” on the consolidated statements of comprehensive income (loss). This amount is not necessarily indicative of amounts to be expected in future periods. The Company is not able to estimate the impact on the presentation of its future revenues and expenses under the new guidance due to uncertainties with respect to future sales volumes, service costs, locations of producing properties, sales destinations, transportation methods utilized, and changes in the nature, timing, and extent of its arrangements from period to period. Leases – In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) , which requires companies to recognize a right of use asset and related liability on the balance sheet for the rights and obligations arising from leases with durations greater than 12 months. The standard is effective for interim and annual reporting periods beginning after December 15, 2018 and requires adoption by application of a modified retrospective transition approach. The Company continues to evaluate the impact of ASU 2016-02 on its financial statements, accounting policies and internal controls and is in the process of developing systems and processes to identify, classify, and account for leases within the scope of the new guidance and to comply with the related disclosure requirements. Standard setting guidance and interpretations continue to evolve and are being monitored for applicability and impact to the Company’s business and industry. Based on an initial review of the new guidance and the Company’s current commitments, the Company anticipates it may be required to recognize lease assets and liabilities related to drilling rig commitments, certain equipment rentals and leases, certain surface use agreements, and potentially certain firm transportation agreements, as well as other arrangements, the effect of which cannot be estimated at this time. Credit losses – In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments . This standard changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. The standard is effective for interim and annual periods beginning after December 15, 2019 and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. The Company continues to evaluate the new standard and is unable to estimate its financial statement impact at this time. Historically, the Company’s credit losses on crude oil and natural gas sales receivables and joint interest receivables have been immaterial.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2017
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	Supplemental Cash Flow Information The following table discloses supplemental cash flow information about cash paid for interest and income tax payments and refunds. Also disclosed is information about investing activities that affects recognized assets and liabilities but does not result in cash receipts or payments. Year ended December 31, In thousands 2017 2016 2015 Supplemental cash flow information: Cash paid for interest $ 281,058 $ 316,116 $ 301,743 Cash paid for income taxes 2 2 30 Cash received for income tax refunds 257 174 61,403 Non-cash investing activities: Asset retirement obligation additions and revisions, net 14,685 (10,063 ) 22,472 As of December 31, 2017 and 2016 , the Company had $302.8 million and $223.6 million , respectively, of accrued capital expenditures included in “Net property and equipment” and “Accounts payable trade” in the consolidated balance sheets.

Net Property and Equipment

Net Property and Equipment	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment, Net [Abstract]
Net Property and Equipment	Net Property and Equipment Net property and equipment includes the following at December 31, 2017 and 2016 . December 31, In thousands 2017 2016 Proved crude oil and natural gas properties $ 21,362,199 $ 19,802,395 Unproved crude oil and natural gas properties 365,413 429,562 Service properties, equipment and other 290,111 301,788 Total property and equipment 22,017,723 20,533,745 Accumulated depreciation, depletion and amortization (9,083,934 ) (7,652,518 ) Net property and equipment $ 12,933,789 $ 12,881,227

Accrued Liabilities and Other

Accrued Liabilities and Other	12 Months Ended
	Dec. 31, 2017
Accrued Liabilities and Other Liabilities [Abstract]
Accrued Liabilities and Other	Accrued Liabilities and Other Accrued liabilities and other includes the following at December 31, 2017 and 2016 : December 31, In thousands 2017 2016 Prepaid advances from joint interest owners $ 34,511 $ 57,861 Accrued compensation 65,308 38,046 Accrued production taxes, ad valorem taxes and other non-income taxes 40,611 22,053 Accrued interest 55,282 52,657 Accrued litigation settlement (see Note 10) 59,600 — Current portion of asset retirement obligations 2,612 1,742 Other 2,150 4,411 Accrued liabilities and other $ 260,074 $ 176,770

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	Derivative Instruments Crude oil and natural gas derivatives The Company may utilize crude oil and natural gas swap and collar derivative contracts to economically hedge against the variability in cash flows associated with future sales of crude oil and natural gas production. While the use of these derivative instruments limits the downside risk of adverse price movements, their use also limits future revenues from upward price movements. The Company recognizes all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The Company has not designated its crude oil and natural gas derivative instruments as hedges for accounting purposes and, as a result, marks such derivative instruments to fair value and recognizes the changes in fair value in the consolidated statements of comprehensive income (loss) under the caption “ Gain (loss) on crude oil and natural gas derivatives, net .” The estimated fair value of derivative contracts is based upon various factors, including commodity exchange prices, over-the-counter quotations, and, in the case of collars and written call options, volatility, the risk-free interest rate, and the time to expiration. The calculation of the fair value of collars and written call options requires the use of an option-pricing model. See Note 6. Fair Value Measurements . With respect to a crude oil or natural gas fixed price swap contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the swap price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. For a crude oil or natural gas collar contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price. Neither party is required to make a payment to the other party if the settlement price for any settlement period is between the floor price and the ceiling price. At December 31, 2017 , the Company had outstanding natural gas derivative contracts as set forth in the table below. The volumes reflected below represent an aggregation of multiple derivative contracts having similar remaining durations expected to be realized ratably over the indicated 2018 period. At December 31, 2017 the Company had no outstanding crude oil derivative contracts. Period and Type of Contract MMBtus Swaps Weighted Average Price January 2018 - March 2018 Swaps - Henry Hub 6,300,000 $ 3.28 Crude oil and natural gas derivative gains and losses Cash receipts and payments in the following table reflect the gain or loss on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price of matured contracts. Non-cash gains and losses below represent the change in fair value of derivative instruments which continue to be held at period end, if any, and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period. Year ended December 31, In thousands 2017 2016 2015 Cash received (paid) on derivatives: Natural gas fixed price swaps $ 40,095 $ 88,823 $ 39,670 Natural gas collars (10,539 ) — 29,883 Cash received on derivatives, net 29,556 88,823 69,553 Non-cash gain (loss) on derivatives: Crude oil written call options — 38 4,715 Natural gas fixed price swaps 18,960 (120,784 ) 41,828 Natural gas collars 43,131 (39,936 ) (25,011 ) Non-cash gain (loss) on derivatives, net 62,091 (160,682 ) 21,532 Gain (loss) on crude oil and natural gas derivatives, net $ 91,647 $ (71,859 ) $ 91,085 Diesel fuel derivatives The Company previously entered into diesel fuel swap derivative contracts, all of which matured on or before December 31, 2017, to economically hedge against the variability in cash flows associated with future purchases of diesel fuel for use in drilling activities. With respect to the diesel fuel swap contracts, the counterparty was required to make a payment to the Company if the settlement price for any settlement period was greater than the swap price, and the Company was required to make a payment to the counterparty if the settlement price for any settlement period was less than the swap price. The diesel fuel swap contracts were settled based upon reported NYMEX settlement prices for New York Harbor ultra-low sulfur diesel fuel. The Company recognized its diesel fuel derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The estimated fair value was based upon various factors, including commodity exchange prices, over-the-counter quotations, the risk-free interest rate, and time to expiration. The Company did not designate its diesel fuel derivative instruments as hedges for accounting purposes and, as a result, marked the derivative instruments to fair value and recognized the changes in fair value in the consolidated statements of comprehensive income (loss) under the caption “Operating costs and expenses—Net gain on sale of assets and other.” Cash receipts in the following table reflect gains on diesel fuel derivatives which matured during the period, calculated as the difference between the contract price and the market settlement price of matured contracts. Non-cash gains and losses below represent the change in fair value of diesel fuel derivatives held at period end, if any, and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period. Year ended December 31, In thousands 2017 2016 Cash received on diesel fuel derivatives $ 2,845 $ 699 Non-cash gain (loss) on diesel fuel derivatives (4,060 ) 4,060 Gain (loss) on diesel fuel derivatives, net $ (1,215 ) $ 4,759 Balance sheet offsetting of derivative assets and liabilities The Company’s derivative contracts are recorded at fair value in the consolidated balance sheets under the captions “Derivative assets”, “Noncurrent derivative assets”, “Derivative liabilities”, and “Noncurrent derivative liabilities”, as applicable. Derivative assets and liabilities with the same counterparty that are subject to contractual terms which provide for net settlement are reported on a net basis in the consolidated balance sheets. The following table presents the gross amounts of recognized crude oil, natural gas, and diesel fuel derivative assets and liabilities, as applicable, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the consolidated balance sheets for the periods presented, all at fair value. December 31, In thousands 2017 2016 Commodity derivative assets: Gross amounts of recognized assets $ 2,603 $ 4,061 Gross amounts offset on balance sheet — — Net amounts of assets on balance sheet 2,603 4,061 Commodity derivative liabilities: Gross amounts of recognized liabilities — (59,489 ) Gross amounts offset on balance sheet — — Net amounts of liabilities on balance sheet $ — $ (59,489 ) The following table reconciles the net amounts disclosed above to the individual financial statement line items in the consolidated balance sheets. December 31, In thousands 2017 2016 Derivative assets $ 2,603 $ 4,061 Noncurrent derivative assets — — Net amounts of assets on balance sheet 2,603 4,061 Derivative liabilities — (59,489 ) Noncurrent derivative liabilities — — Net amounts of liabilities on balance sheet — (59,489 ) Total derivative assets (liabilities), net $ 2,603 $ (55,428 )

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements The Company follows a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows: • Level 1: Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. • Level 2: Observable market-based inputs or unobservable inputs corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. • Level 3: Unobservable inputs not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value. A financial instrument’s categorization within the hierarchy is based upon the lowest level of input that is significant to the fair value measurement. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the hierarchy. As Level 1 inputs generally provide the most reliable evidence of fair value, the Company uses Level 1 inputs when available. The Company’s policy is to recognize transfers between the hierarchy levels as of the beginning of the reporting period in which the event or change in circumstances caused the transfer. Assets and liabilities measured at fair value on a recurring basis The Company’s derivative instruments are reported at fair value on a recurring basis. In determining the fair values of swap contracts, a discounted cash flow method is used due to the unavailability of relevant comparable market data for the Company’s exact contracts. The discounted cash flow method estimates future cash flows based on quoted market prices for forward commodity prices and a risk-adjusted discount rate. The fair values of swap contracts are calculated mainly using significant observable inputs (Level 2). Calculation of the fair values of collars requires the use of an industry-standard option pricing model that considers various inputs including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. These assumptions are observable in the marketplace or can be corroborated by active markets or broker quotes and are therefore designated as Level 2 within the valuation hierarchy. The Company’s calculation of fair value for each of its derivative positions is compared to the counterparty valuation for reasonableness. The following tables summarize the valuation of financial instruments by pricing levels that were accounted for at fair value on a recurring basis as of December 31, 2017 and 2016 . Fair value measurements at December 31, 2017 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets: Swaps $ — $ 2,603 $ — $ 2,603 Total $ — $ 2,603 $ — $ 2,603 Fair value measurements at December 31, 2016 using: In thousands Level 1 Level 2 Level 3 Total Derivative liabilities: Swaps $ — $ (12,297 ) $ — $ (12,297 ) Collars — (43,131 ) — (43,131 ) Total $ — $ (55,428 ) $ — $ (55,428 ) Assets measured at fair value on a nonrecurring basis Certain assets are reported at fair value on a nonrecurring basis in the consolidated financial statements. The following methods and assumptions were used to estimate the fair values for those assets. Asset impairments – Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter. The estimated future cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value. Risk-adjusted probable and possible reserves may be taken into consideration when determining estimated future net cash flows and fair value when such reserves exist and are economically recoverable. Due to the unavailability of relevant comparable market data, a discounted cash flow method is used to determine the fair value of proved properties. The discounted cash flow method estimates future cash flows based on the Company’s estimates of future crude oil and natural gas production, commodity prices based on commodity futures price strips adjusted for differentials, operating costs, and a risk-adjusted discount rate. The fair value of proved crude oil and natural gas properties is calculated using significant unobservable inputs (Level 3). The following table sets forth quantitative information about the significant unobservable inputs used by the Company at December 31, 2017 to calculate the fair value of proved crude oil and natural gas properties using a discounted cash flow method. Unobservable Input Assumption Future production Future production estimates for each property Forward commodity prices Forward NYMEX strip prices through 2022 (adjusted for differentials), escalating 3% per year thereafter Operating costs Estimated costs for the current year, escalating 3% per year thereafter Productive life of field Ranging from 1 to 38 years Discount rate 10% Unobservable inputs to the fair value assessment are reviewed quarterly and are revised as warranted based on a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Fair value measurements of proved properties are reviewed and approved by certain members of the Company’s management. For the year ended December 31, 2017 , the Company determined the carrying amounts of certain proved properties were not recoverable from future cash flows, and therefore, were impaired. Impairments of proved properties amounted to $82.3 million for 2017 , which reflect fair value adjustments in the Arkoma Woodford field ( $81.2 million ) and various non-core areas in the North and South regions ( $1.1 million ). The impaired properties were written down to their estimated fair value at the time of impairment of approximately $72 million . Certain unproved crude oil and natural gas properties were impaired during the years ended December 31, 2017 , 2016 , and 2015 , reflecting recurring amortization of undeveloped leasehold costs on properties the Company expects will not be transferred to proved properties over the lives of the leases based on drilling plans, experience of successful drilling, and the average holding period. The following table sets forth the non-cash impairments of both proved and unproved properties for the indicated periods. Proved and unproved property impairments are recorded under the caption “Property impairments” in the consolidated statements of comprehensive income (loss). Year ended December 31, In thousands 2017 2016 2015 Proved property impairments $ 82,340 $ 2,895 $ 138,878 Unproved property impairments 155,030 234,397 263,253 Total $ 237,370 $ 237,292 $ 402,131 Financial instruments not recorded at fair value The following table sets forth the estimated fair values of financial instruments that are not recorded at fair value in the consolidated financial statements. December 31, 2017 December 31, 2016 In thousands Carrying Amount Fair Value Carrying Amount Fair Value Debt: Revolving credit facility (1) $ 188,000 $ 188,000 $ 905,000 $ 905,000 Term loan (1) — — 498,865 500,000 Note payable 9,974 9,900 12,176 10,200 5% Senior Notes due 2022 1,997,576 2,040,000 1,997,188 2,020,400 4.5% Senior Notes due 2023 1,486,690 1,526,800 1,484,524 1,474,800 3.8% Senior Notes due 2024 992,036 988,800 990,964 929,400 4.375% Senior Notes due 2028 (1) 988,061 987,200 — — 4.9% Senior Notes due 2044 691,354 679,900 691,199 607,600 Total debt $ 6,353,691 $ 6,420,600 $ 6,579,916 $ 6,447,400 (1) In December 2017, the Company issued $1.0 billion of 4.375% Senior Notes due 2028 and used the proceeds therefrom to repay in full and terminate its term loan and to repay a portion of the borrowings outstanding under its revolving credit facility. See Note 7. Long-Term Debt for further discussion. The fair values of revolving credit facility borrowings and the term loan approximate carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and are classified as Level 2 in the fair value hierarchy. The fair value of the note payable is determined using a discounted cash flow approach based on the interest rate and payment terms of the note payable and an assumed discount rate. The fair value of the note payable is significantly influenced by the discount rate assumption, which is derived by the Company and is unobservable. Accordingly, the fair value of the note payable is classified as Level 3 in the fair value hierarchy. The fair values of the 5% Senior Notes due 2022 (“2022 Notes”), the 4.5% Senior Notes due 2023 (“2023 Notes”), the 3.8% Senior Notes due 2024 (“2024 Notes”), the 4.375% Senior Notes due 2028 (“2028 Notes”), and the 4.9% Senior Notes due 2044 (“2044 Notes”) are based on quoted market prices and, accordingly, are classified as Level 1 in the fair value hierarchy. The carrying values of all classes of cash and cash equivalents, trade receivables, and trade payables are considered to be representative of their respective fair values due to the short term maturities of those instruments.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $44.3 million and $37.3 million at December 31, 2017 and 2016 , respectively, consists of the following. December 31, In thousands 2017 2016 Revolving credit facility $ 188,000 $ 905,000 Term loan — 498,865 Note payable 9,974 12,176 5% Senior Notes due 2022 1,997,576 1,997,188 4.5% Senior Notes due 2023 1,486,690 1,484,524 3.8% Senior Notes due 2024 992,036 990,964 4.375% Senior Notes due 2028 988,061 — 4.9% Senior Notes due 2044 691,354 691,199 Total debt 6,353,691 6,579,916 Less: Current portion of long-term debt 2,286 2,219 Long-term debt, net of current portion $ 6,351,405 $ 6,577,697 Revolving credit facility The Company has an unsecured revolving credit facility, maturing on May 16, 2019, with aggregate commitments totaling $2.75 billion at December 31, 2017 . Credit facility borrowings bear interest at market-based interest rates plus a margin based on the terms of the borrowing and the credit ratings assigned to the Company’s senior, unsecured, long-term indebtedness. The weighted-average interest rate on outstanding credit facility borrowings at December 31, 2017 was 3.19% . The Company had approximately $2.56 billion of borrowing availability on its revolving credit facility at December 31, 2017 and incurs commitment fees based on currently assigned credit ratings of 0.30% per annum on the daily average amount of unused borrowing availability under its revolving credit facility. The revolving credit facility contains certain restrictive covenants including a requirement that the Company maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. This ratio represents the ratio of net debt (calculated as total face value of debt plus outstanding letters of credit less cash and cash equivalents) divided by the sum of net debt plus total shareholders’ equity plus, to the extent resulting in a reduction of total shareholders’ equity, the amount of any non-cash impairment charges incurred, net of any tax effect, after June 30, 2014. The Company was in compliance with the revolving credit facility covenants at December 31, 2017 . Senior notes In December 2017, the Company issued $1.0 billion of 4.375% Senior Notes due 2028 and received total net proceeds of $990 million after deducting the initial purchasers' fees. The 2028 Notes were sold at par in a private placement transaction exempt from the registration requirements of the Securities Act to qualified institutional buyers in reliance on Rule 144A of the Securities Act. The Company used the net proceeds from the offering to repay in full and terminate its $500 million term loan and to repay a portion of the borrowings outstanding under its revolving credit facility. In connection with the issuance of the 2028 Notes, the Company entered into a registration rights agreement with the initial purchasers dated December 8, 2017 to allow holders of the unregistered 2028 Notes to exchange them for registered notes that have substantially identical terms. The Company agreed to use reasonable efforts to cause the exchange to be completed within 400 days after the issuance of the 2028 Notes. The Company is required to pay additional interest if it fails to comply with its obligations to register the 2028 Notes within the specified time period, whereby the interest rate would be increased by 1.0% per annum during the period in which a registration default is in effect. The Company expects to comply with the terms of the registration rights agreement and complete the exchange of the 2028 Notes within the 400 day period. The following table summarizes the face values, maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding senior note obligations at December 31, 2017 . 2022 Notes (1) 2023 Notes 2024 Notes 2028 Notes 2044 Notes Face value (in thousands) $2,000,000 $1,500,000 $1,000,000 $1,000,000 $700,000 Maturity date Sep 15, 2022 April 15, 2023 June 1, 2024 January 15, 2028 June 1, 2044 Interest payment dates March 15, Sep 15 April 15, Oct 15 June 1, Dec 1 Jan 15, July 15 June 1, Dec 1 Make-whole redemption period (2) — Jan 15, 2023 Mar 1, 2024 Oct 15, 2027 Dec 1, 2043 (1) The Company has the option to redeem all or a portion of its 2022 Notes at the decreasing redemption prices specified in the indenture related to the 2022 Notes plus any accrued and unpaid interest to the date of redemption. (2) At any time prior to the indicated dates, the Company has the option to redeem all or a portion of its senior notes of the applicable series at the “make-whole” redemption prices or amounts specified in the respective senior note indentures plus any accrued and unpaid interest to the date of redemption. On or after these dates, the Company may redeem all or a portion of its senior notes at a redemption price equal to 100% of the principal amount of the senior notes being redeemed plus any accrued and unpaid interest to the date of redemption. The Company’s senior notes are not subject to any mandatory redemption or sinking fund requirements. The indentures governing the Company’s senior notes contain covenants that, among other things, limit the Company’s ability to create liens securing certain indebtedness, enter into certain sale-leaseback transactions, or consolidate, merge or transfer certain assets. The senior note covenants are subject to a number of important exceptions and qualifications. The Company was in compliance with these covenants at December 31, 2017 . Three of the Company’s subsidiaries, Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC, and The Mineral Resources Company, which have no material assets or operations, fully and unconditionally guarantee the senior notes on a joint and several basis. The Company’s other subsidiaries, the value of whose assets and operations are minor, do not guarantee the senior notes. 2016 Redemptions of Senior Notes In November 2016, the Company redeemed its then outstanding 7.375% Senior Notes due 2020 (“2020 Notes”) and 7.125% Senior Notes due 2021 (“2021 Notes”). The redemption price for the 2020 Notes was equal to 102.458% of the $200 million principal amount plus accrued and unpaid interest to the redemption date in accordance with the terms of the 2020 Notes and related indenture. The redemption price for the 2021 Notes was equal to 103.563% of the $400 million principal amount plus accrued and unpaid interest to the redemption date in accordance with the terms of the 2021 Notes and related indenture. The aggregate of the principal amounts, redemption premiums, and accrued interest paid upon redemption of the 2020 Notes and 2021 Notes was $623.9 million . The Company funded the redemptions using borrowings under its revolving credit facility. The Company recognized a pre-tax loss totaling $26.1 million related to the redemptions, which included the call premiums and write-off of deferred financing costs and unaccreted debt discounts associated with the notes and is reflected under the caption “Loss on extinguishment of debt” in the consolidated statements of comprehensive income (loss) for the year ended December 31, 2016. Term loan In November 2015, the Company borrowed $500 million under a three-year term loan agreement which was scheduled to mature on November 4, 2018. In December 2017, the Company repaid in full and terminated the term loan using a portion of the proceeds from its issuance of 2028 Notes as described above. The Company recognized a pre-tax loss on extinguishment of $0.6 million related to the termination, representing the write-off of deferred financing costs associated with the term loan. Note payable In February 2012, 20 Broadway Associates LLC, a 100% owned subsidiary of the Company, borrowed $22 million under a 10 -year amortizing term loan secured by the Company’s corporate office building in Oklahoma City, Oklahoma. The loan bears interest at a fixed rate of 3.14% per annum. Principal and interest are payable monthly through the loan’s maturity date of February 26, 2022 . Accordingly, approximately $2.3 million is reflected as a current liability under the caption “Current portion of long-term debt” in the consolidated balance sheets as of December 31, 2017 .

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes On December 22, 2017, the Tax Reform Act was signed into law. The new legislation contains several key changes to U.S. corporate tax laws that are expected to impact the Company, including a reduction of the corporate income tax rate from 35% to 21%, effective January 1, 2018. The new legislation also includes a variety of other changes such as the repeal of the alternative minimum tax, the introduction of new limitations on the tax deductibility of net operating losses, interest expenses, and executive compensation expenses, the acceleration of expensing of certain qualified property, and the introduction of new laws governing taxation of foreign earnings of U.S. entities, among others. U.S. GAAP (Accounting Standards Codification Topic 740, Income Taxes ) requires entities to recognize the effect of tax law changes in the reporting period that includes the enactment date. The income tax accounting effect of a change in tax law includes, for example, remeasuring deferred tax assets and liabilities at a new tax rate and evaluating whether a valuation allowance is needed for deferred tax assets. In response to the enactment of the Tax Reform Act, the Securities and Exchange Commission issued guidance in Staff Accounting Bulletin No. 118 ("SAB 118") to assist entities in applying ASC 740 to the new tax law. SAB 118 allows entities to record estimated provisional amounts during a measurement period in circumstances where an entity does not have the necessary information in reasonable detail to complete its accounting for a tax law change under ASC 740 prior to the issuance of its financial statements. In accordance with ASC 740, the Company remeasured its deferred tax assets and liabilities as of December 31, 2017 to reflect the reduction in the corporate tax rate from 35% to 21%. This remeasurement resulted in a $713.7 million decrease in net deferred income tax liabilities and corresponding decrease in income tax expense as of and for the year ended December 31, 2017 , which is reflected in the tables below. The Company also reassessed the realizability of its deferred tax assets, taking into consideration how the new tax law impacts future taxable income, and has recorded such assets at realizable value at December 31, 2017 . The Company's accounting for the effects of the tax rate change on its deferred tax balances as well as other relevant aspects of the Tax Reform Act is complete and no provisional amounts have been recorded as allowed under SAB 118. The items comprising the Company's benefit for income taxes are as follows for the periods presented: Year ended December 31, In thousands 2017 2016 2015 Current income tax (provision) benefit: United States federal (1) $ 7,781 $ 22,941 $ — Various states — (2 ) (24 ) Total current income tax (provision) benefit 7,781 22,939 (24 ) Deferred income tax (provision) benefit: United States federal - taxation on operations (81,054 ) 182,422 140,578 United States federal - effect of US tax reform 713,655 — — Various states (7,002 ) 27,414 40,863 Total deferred income tax benefit 625,599 209,836 181,441 Benefit for income taxes $ 633,380 $ 232,775 $ 181,417 (1) The current federal income tax benefits for the years ended December 31, 2017 and 2016 represent alternative minimum tax refunds. The benefit for income taxes differs from the amount computed by applying the United States statutory federal income tax rate to income (loss) before income taxes. The sources and tax effects of the difference are as follows: Year ended December 31, 2017 2016 2015 In thousands, except rates Amount Rate Amount Rate Amount Rate Expected income tax (provision) benefit based on US statutory tax rate of 35% $ (54,623 ) 35.0 % $ 221,359 35.0 % $ 187,280 35.0 % State income taxes, net of federal benefit (4,682 ) 3.0 % 18,829 3.0 % 16,219 3.0 % Effect of US tax reform legislation 713,655 (457.3 %) — — % — — % Tax deficiency from stock-based compensation (1) (3,932 ) 2.5 % — — % — — % Canadian valuation allowance (2) (404 ) 0.3 % (1,044 ) (0.2 %) (13,503 ) (2.5 %) Effect of differing statutory tax rate in Canada (194 ) 0.1 % (481 ) (0.1 %) (5,239 ) (1.0 %) Non-deductible compensation (13,813 ) 8.9 % (3,471 ) (0.5 %) (1,488 ) (0.3 %) Other, net (2,627 ) 1.7 % (2,417 ) (0.4 %) (1,852 ) (0.3 %) Benefit for income taxes $ 633,380 (405.8 %) $ 232,775 36.8 % $ 181,417 33.9 % (1) The Company recognized $3.9 million of tax deficiencies from stock-based compensation as income tax expense for the year ended December 31, 2017 in accordance with ASU 2016-09 as discussed in Note 1. Organization and Summary of Significant Accounting Policies–Adoption of new accounting pronouncements . (2) Represents valuation allowances recognized against all deferred tax assets associated with operating loss carryforwards generated by the Company's Canadian operations during the respective periods for which the Company does not expect to realize a benefit. The components of the Company’s deferred tax assets and deferred tax liabilities as of December 31, 2017 and 2016 are reflected in the table below. December 31, In thousands 2017 2016 Deferred tax assets United States net operating loss carryforwards $ 604,423 $ 478,975 Canadian net operating loss carryforwards 19,341 18,936 Alternative minimum tax carryforwards 7,781 16,663 Equity compensation 12,962 32,924 Non-cash losses on derivatives — 21,064 Other 21,885 11,466 Total deferred tax assets 666,392 580,028 Canadian valuation allowance (19,341 ) (18,936 ) Total deferred tax assets, net of valuation allowance 647,051 561,092 Deferred tax liabilities Property and equipment (1,903,451 ) (2,448,450 ) Other (3,158 ) (2,947 ) Total deferred tax liabilities (1,906,609 ) (2,451,397 ) Deferred income tax liabilities, net $ (1,259,558 ) $ (1,890,305 ) As of December 31, 2017 , the Company had federal and state net operating loss carryforwards of $2.39 billion and $3.40 billion , respectively. The federal net operating loss carryforward will begin expiring in 2033 . The Company’s net operating loss carryforward in Oklahoma totaled $2.17 billion at December 31, 2017 , which will begin to expire in 2027. The Company’s net operating loss carryforward in North Dakota totaled $1.07 billion at December 31, 2017 , which will begin to expire in 2033. The Company has alternative minimum tax credit carryforwards of $7.8 million that are refundable by 2021. Any available statutory depletion carryforwards will be recognized when realized. The Company files income tax returns in the U.S. federal, U.S. state and Canadian jurisdictions. With few exceptions, the Company is no longer subject to U.S. federal, state and local income tax examinations by tax authorities for years prior to 2014. The Company recorded valuation allowances of $0.4 million , $1.0 million and $13.5 million against Canadian deferred tax assets for the years ended December 31, 2017 , 2016 and 2015, respectively. The Company's cumulative valuation allowance was $19.3 million as of December 31, 2017 . Our Canadian subsidiary has generated operating loss carryforwards for which we do not believe we will realize a benefit. The amount of deferred tax assets considered realizable, however, could change if our subsidiary generates taxable income.

Lease Commitments

Lease Commitments	12 Months Ended
	Dec. 31, 2017
Leases [Abstract]
Lease Commitments	Lease Commitments The Company’s operating lease obligations primarily represent leases for land and road use, office buildings and equipment, communication towers, and field equipment. Lease payments associated with operating leases for the years ended December 31, 2017 , 2016 and 2015 were $1.9 million , $4.4 million and $9.6 million , respectively, a portion of which was capitalized and/or billed to other interest owners. At December 31, 2017 , the minimum future rental commitments under operating leases having lease terms in excess of one year are reflected in the table below. New accounting rules will go into effect for reporting periods beginning after December 15, 2018 that will impact the Company's accounting for leases. See Note 1. Organization and Summary of Significant Accounting Policies–New accounting pronouncements not yet adopted at December 31, 2017–Leases for further discussion. In thousands Total amount 2018 $ 1,656 2019 958 2020 817 2021 645 2022 620 Thereafter 7,208 Total obligations $ 11,904

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Included below is a discussion of various future commitments of the Company as of December 31, 2017 . The commitments under these arrangements are not recorded in the accompanying consolidated balance sheets. Drilling commitments – As of December 31, 2017 , the Company has drilling rig contracts with various terms extending to February 2020 to ensure rig availability in its key operating areas. Future commitments as of December 31, 2017 total approximately $104 million , of which $73 million is expected to be incurred in 2018, $30 million in 2019 and $1 million in 2020. A portion of these future costs will be borne by other interest owners. Transportation and processing commitments – The Company has entered into transportation and processing commitments to guarantee capacity on crude oil and natural gas pipelines and natural gas processing facilities. The commitments, which have varying terms extending as far as 2028, require the Company to pay per-unit transportation or processing charges regardless of the amount of capacity used. Future commitments remaining as of December 31, 2017 under the arrangements amount to approximately $1.43 billion , of which $197 million is expected to be incurred in 2018, $216 million in 2019, $186 million in 2020, $168 million in 2021, $166 million in 2022, and $497 million thereafter. A portion of these future costs will be borne by other interest owners. The Company is not committed under the above contracts to deliver fixed and determinable quantities of crude oil or natural gas in the future. Litigation – In November 2010, a putative class action was filed in the District Court of Blaine County, Oklahoma by Billy J. Strack and Daniela A. Renner as trustees of certain named trusts and on behalf of other similarly situated parties against the Company. The Petition, as amended, alleged the Company improperly deducted post-production costs from royalties paid to plaintiffs and other royalty interest owners from crude oil and natural gas wells located in Oklahoma. The plaintiffs alleged a number of claims, including breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and sought recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the proposed class. The Company denied all allegations and denied that the case was properly brought as a class action. On June 11, 2015, the trial court certified a “hybrid” class requested by plaintiffs over the objections of the Company. The Company appealed the trial court’s class certification order. On February 8, 2017, the Oklahoma Court of Civil Appeals reversed the trial court’s ruling on certification and remanded the case for further proceedings. The plaintiffs filed a Petition for Rehearing which was denied by the Oklahoma Court of Civil Appeals. Plaintiffs then filed a Petition for Writ of Certiorari on May 23, 2017 to the Oklahoma Supreme Court, which was denied on October 2, 2017. On October 10, 2017, Plaintiffs filed with the trial court a “Second Amended and Renewed Motion for Class Action Certification and Request that the Court to Set a Briefing Schedule Related to Class Certification.” During the litigation the Company was not able to estimate a reasonably possible loss or range of loss or what impact, if any, the ultimate resolution of the action would have on its financial condition, results of operations or cash flows due to the preliminary status of the matter, the complexity and number of legal and factual issues presented by the matter and uncertainties with respect to, among other things, the nature of the claims and defenses, the existence and the potential size of the class, the scope and types of the properties and agreements involved, the production years involved, and the ultimate potential outcome of the matter. The Company further disclosed that it was reasonably possible one or more events could occur in the near term that could impact the Company’s ability to estimate the potential effect of this matter if any, on its financial condition, results of operations or cash flows. During the litigation the Company also disclosed plaintiffs alleged underpayments in excess of $200 million as damages, which may increase with the passage of time, a majority of which would be comprised of interest. After certification of the case as a class action was reversed the parties continued settlement negotiations. Due to the uncertainty of and burdens of litigation, on February 16, 2018, the Company reached a settlement in connection with this matter. Under the settlement, if approved by the court, the Company will make payments and incur costs associated with the settlement of approximately $59.6 million . The Company has accrued a loss for such amount, which is included in “Accrued liabilities and other” on the consolidated balance sheets and “Litigation settlement” in the consolidated statements of comprehensive income (loss) as of and for the year ended December 31, 2017. The District Court of Garfield County, Oklahoma must approve the settlement. The Company is involved in various other legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, disputes with tax authorities and other matters. While the outcome of these legal matters cannot be predicted with certainty, the Company does not expect them to have a material effect on its financial condition, results of operations or cash flows. As of December 31, 2017 and 2016 , the Company had recorded a liability in the consolidated balance sheets under the caption “Other noncurrent liabilities” of $7.6 million and $6.5 million , respectively, for various matters, none of which are believed to be individually significant. Environmental risk – Due to the nature of the crude oil and natural gas business, the Company is exposed to possible environmental risks. The Company is not aware of any material environmental issues or claims.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions The Company historically sold a portion of its natural gas production to Hiland Partners, LP and its subsidiaries (“Hiland”). Hiland was controlled by the Company's principal shareholder through February 13, 2015, at which time it was sold to an unaffiliated third party. As a result of the sale, the prior related party relationship between the Company and Hiland terminated as of February 13, 2015. For the year ended December 31, 2015, sales to Hiland amounted to $1.4 million , net of transportation and processing costs, which is included in the caption “Crude oil and natural gas sales to affiliates” in the consolidated statements of comprehensive income (loss). The Company capitalized costs of $0.1 million and $2.6 million in 2016 and 2015 , respectively, associated with drilling rig services and demobilization of a drilling rig provided by an affiliate. Hiland historically provided field services such as compression, purchases of residue fuel gas and reclaimed crude oil, and reimbursements of generator rentals and fuel. Production and other expenses attributable to these transactions with Hiland prior to its sale were $1.7 million for the year ended December 31, 2015. The total amount paid to these affiliates, a portion of which was billed to other interest owners, was $0.1 million and $7.7 million for the years ended December 31, 2016 and 2015 , respectively. No amounts were due to these affiliates at December 31, 2017 and 2016 related to the transactions. Certain officers of the Company own or control entities that own working and royalty interests in wells operated by the Company. The Company paid revenues to these affiliates, including royalties, of $0.5 million , $0.4 million , and $0.7 million and received payments from these affiliates of $0.3 million , $0.3 million , and $0.5 million during the years ended December 31, 2017 , 2016 , and 2015 , respectively, relating to the operations of the respective properties. At December 31, 2017 and 2016 , approximately $58,000 and $90,000 was due from these affiliates, respectively, and approximately $48,000 and $45,000 was due to these affiliates, respectively, relating to these transactions. The Company allows certain affiliates to use its corporate aircraft and crews and has used the aircraft of those same affiliates from time to time in order to facilitate efficient transportation of Company personnel. The rates charged between the parties vary by type of aircraft used. In 2016, the Company also purchased an existing prepaid maintenance account from an affiliate for use in major engine overhaul to be applied as needed for corporate aircrafts. For usage during 2017 , 2016 , and 2015 , the Company charged affiliates approximately $19,400 , $9,500 , and $9,600 , respectively, for use of its corporate aircraft crews, fuel, and reimbursement of expenses and received approximately $18,600 , $6,800 , and $33,000 from affiliates in 2017 , 2016 , and 2015 , respectively. The Company was charged approximately $460,000 , $292,000 , and $236,000 , respectively, by affiliates for use of their aircraft and reimbursement of expenses during 2017 , 2016 (including the prepayment), and 2015 and paid $368,000 , $195,000 , and $221,000 to the affiliates in 2017 , 2016 , and 2015 , respectively. At December 31, 2017 and 2016 , approximately $4,200 and $3,400 was due from an affiliate, respectively, and approximately $92,000 and $97,000 was due to an affiliate, respectively, relating to these transactions. The Company incurred costs for various field projects that had been ongoing with an entity that became an affiliate of the Company in the third quarter of 2014. During the fourth quarter of 2015, the affiliate relationship terminated. The total amount invoiced and capitalized for 2015 associated with the projects was $8.8 million . The total amount paid, a portion of which was billed to other interest owners, was $9.2 million for 2015.

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-Based Compensation	Stock-Based Compensation On January 1, 2017, the Company adopted ASU 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting . See Note 1. Organization and Summary of Significant Accounting Policies—Adoption of new accounting pronouncements for a discussion of the impact of adoption. The Company has granted restricted stock to employees and directors pursuant to the Continental Resources, Inc. 2013 Long-Term Incentive Plan (“2013 Plan”) as discussed below. The Company’s associated compensation expense, which is included in the caption “General and administrative expenses” in the consolidated statements of comprehensive income (loss), was $45.9 million , $48.1 million , and $51.8 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. In May 2013, the Company adopted the 2013 Plan and reserved 19,680,072 shares of common stock that may be issued pursuant to the plan. As of December 31, 2017 , the Company had 14,538,540 shares of common stock available for long-term incentive awards to employees and directors under the 2013 Plan. Restricted stock is awarded in the name of the recipient and constitutes issued and outstanding shares of the Company’s common stock for all corporate purposes during the period of restriction and, except as otherwise provided under the 2013 Plan or agreement relevant to a given award, includes the right to vote the restricted stock and to receive dividends, subject to forfeiture. Restricted stock grants generally vest over periods ranging from one to three years. A summary of changes in non-vested restricted shares from December 31, 2014 to December 31, 2017 is presented below. Number of Weighted Non-vested restricted shares at December 31, 2014 2,678,764 $ 49.40 Granted 1,462,534 46.65 Vested (555,517 ) 48.07 Forfeited (336,170 ) 51.23 Non-vested restricted shares at December 31, 2015 3,249,611 $ 48.20 Granted 2,064,508 22.36 Vested (1,207,235 ) 41.27 Forfeited (193,250 ) 39.79 Non-vested restricted shares at December 31, 2016 3,913,634 $ 37.12 Granted 1,585,870 44.58 Vested (874,665 ) 57.36 Forfeited (598,729 ) 37.34 Non-vested restricted shares at December 31, 2017 4,026,110 $ 35.63 The grant date fair value of restricted stock represents the closing market price of the Company’s common stock on the date of grant. Compensation expense for a restricted stock grant is determined at the grant date fair value and is recognized over the vesting period as services are rendered by employees and directors. The Company estimates the number of forfeitures expected to occur in determining the amount of stock-based compensation expense to recognize. There are no post-vesting restrictions related to the Company’s restricted stock. The fair value at the vesting date of restricted stock that vested during 2017 , 2016 and 2015 was $39.8 million , $30.0 million and $23.6 million , respectively. As of December 31, 2017 , there was approximately $58 million of unrecognized compensation expense related to non-vested restricted stock. This expense is expected to be recognized over a weighted average period of 1.2 years.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income Accumulated Other Comprehensive Income (Loss) (Notes)	12 Months Ended
	Dec. 31, 2017
Statement of Comprehensive Income [Abstract]
Comprehensive Income (Loss) Note [Text Block]	Accumulated Other Comprehensive Income (Loss) Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in “Accumulated other comprehensive income (loss)” within shareholders’ equity on the consolidated balance sheets and “Other comprehensive income (loss), net of tax” in the consolidated statements of comprehensive income (loss). The following table summarizes the change in accumulated other comprehensive income (loss) for the years ended December 31, 2017 , 2016 , and 2015 : Year ended December 31, In thousands 2017 2016 2015 Beginning accumulated other comprehensive loss, net of tax $ (260 ) $ (3,354 ) $ (385 ) Foreign currency translation adjustments 567 3,094 (2,969 ) Income taxes (1) — — — Other comprehensive income (loss), net of tax 567 3,094 (2,969 ) Ending accumulated other comprehensive income (loss), net of tax $ 307 $ (260 ) $ (3,354 ) (1) A valuation allowance has been recognized against all deferred tax assets associated with losses generated by the Company’s Canadian operations, thereby resulting in no income taxes on other comprehensive income (loss).

Property Dispositions

Property Dispositions	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Property Acquisitions and Dispositions	Property Dispositions 2017 In September 2017, the Company sold non-strategic properties in the Arkoma Woodford area for cash proceeds of $65.3 million . The sale included approximately 26,000 net acres of leasehold in Atoka, Coal, Hughes, and Pittsburg Counties of Oklahoma and producing properties with production totaling approximately 1,700 barrels of oil equivalent per day. In connection with the transaction, the Company recognized a pre-tax loss of $3.5 million for the year ended December 31, 2017. The disposed properties represented an immaterial portion of the Company’s proved reserves. In September 2017, the Company reached an agreement to sell non-core leasehold in the STACK play in Blaine County, Oklahoma for cash proceeds totaling $63.5 million . A portion of the transaction closed in September 2017, resulting in the receipt of proceeds amounting to $3.6 million and the recognition of a $3.3 million pre-tax gain on sale in the 2017 third quarter. The remainder of the transaction was completed in October 2017 at which time the Company received the remaining $59.9 million of proceeds and recognized an additional pre-tax gain of approximately $53.6 million , which is reflected in fourth quarter 2017 results. The disposed properties represented an immaterial portion of the Company’s production and proved reserves. In September 2017, the Company sold certain oil-loading facilities in Oklahoma for $7.2 million and recognized a $4.2 million pre-tax gain for the year ended December 31, 2017 associated with the transaction. 2016 In October 2016, the Company sold approximately 30,000 net acres of non-strategic leasehold in the SCOOP play in Oklahoma for cash proceeds totaling $295.6 million . The leasehold was located primarily in the eastern portion of the SCOOP play and included producing properties with production totaling approximately 700 barrels of oil equivalent per day. In connection with the transaction, the Company recognized a pre-tax gain of $201.0 million . The disposed properties represented an immaterial portion of the Company’s proved reserves. In September 2016, the Company sold non-strategic properties in North Dakota and Montana for cash proceeds totaling $214.8 million , with no gain or loss recognized. The sale included approximately 68,000 net acres of leasehold primarily in western Williams County, North Dakota, and approximately 12,000 net acres of leasehold in Roosevelt County, Montana. The sale also included producing properties with production totaling approximately 2,700 barrels of oil equivalent per day. The disposed properties represented an immaterial portion of the Company’s proved reserves. In April 2016, the Company sold approximately 132,000 net acres of undeveloped leasehold acreage in Wyoming for cash proceeds totaling $110.0 million . In connection with the transaction, the Company recognized a pre-tax gain of $96.9 million . The disposed properties had no production or proved reserves. 2015 During the year ended December 31, 2015, the Company sold certain non-strategic properties in various areas for cash proceeds totaling $34.0 million . The proceeds primarily related to the disposition of certain non-producing leasehold acreage in Oklahoma for $25.9 million in May 2015. The Company recognized a pre-tax gain on the transaction of $20.5 million . The disposed properties represented an immaterial portion of the Company’s leasehold acreage.

Crude Oil and Natural Gas Prope

Crude Oil and Natural Gas Property Information	12 Months Ended
	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Crude Oil and Natural Gas Property Information	Crude Oil and Natural Gas Property Information The tables reflected below represent consolidated figures for the Company and its subsidiaries. In 2014, the Company initiated exploratory drilling activities in Canada. Through December 31, 2017, those drilling activities have not had a material impact on the Company’s total capital expenditures, production, and revenues. Accordingly, the results of operations, costs incurred, and capitalized costs associated with the Canadian operations have not been shown separately from the consolidated figures in the tables below. The following table sets forth the Company’s consolidated results of operations from crude oil and natural gas producing activities for the years ended December 31, 2017 , 2016 and 2015 . Year ended December 31, In thousands 2017 2016 2015 Crude oil and natural gas sales $ 2,982,966 $ 2,026,958 $ 2,552,531 Production expenses (324,214 ) (289,289 ) (348,897 ) Production taxes (208,278 ) (142,388 ) (200,637 ) Exploration expenses (12,393 ) (16,972 ) (19,413 ) Depreciation, depletion, amortization and accretion (1,652,180 ) (1,679,485 ) (1,722,336 ) Property impairments (237,370 ) (237,292 ) (402,131 ) Income tax benefit (1) 504,475 126,794 33,680 Results from crude oil and natural gas producing activities $ 1,053,006 $ (211,674 ) $ (107,203 ) (1) Income taxes reflect the application of a combined federal and state tax rate of 38% on pre-tax income and losses generated by operations in the United States. Additionally, the 2017 period includes a $713.7 million income tax benefit recognized upon the Company’s remeasurement of its deferred income tax assets and liabilities in response to the enactment of the Tax Reform Act in December 2017. See Note 8. Income Taxes for further discussion. Costs incurred in crude oil and natural gas activities Costs incurred, both capitalized and expensed, in connection with the Company’s consolidated crude oil and natural gas acquisition, exploration and development activities for the years ended December 31, 2017 , 2016 and 2015 are presented below: Year ended December 31, In thousands 2017 2016 2015 Property acquisition costs: Proved $ 8,446 $ 5,008 $ 557 Unproved 220,875 149,962 168,492 Total property acquisition costs 229,321 154,970 169,049 Exploration Costs 123,461 182,355 241,523 Development Costs 1,695,954 767,148 2,148,530 Total $ 2,048,736 $ 1,104,473 $ 2,559,102 Costs incurred above include asset retirement costs and revisions thereto of $15.3 million , ($9.6) million and $22.8 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. Aggregate capitalized costs Aggregate capitalized costs relating to the Company’s consolidated crude oil and natural gas producing activities and related accumulated depreciation, depletion and amortization as of December 31, 2017 and 2016 are as follows: December 31, In thousands 2017 2016 Proved crude oil and natural gas properties $ 21,362,199 $ 19,802,395 Unproved crude oil and natural gas properties 365,413 429,562 Total 21,727,612 20,231,957 Less accumulated depreciation, depletion and amortization (8,971,935 ) (7,553,255 ) Net capitalized costs $ 12,755,677 $ 12,678,702 Under the successful efforts method of accounting, the costs of drilling an exploratory well are capitalized pending determination of whether proved reserves can be attributed to the discovery. When initial drilling operations are complete, management attempts to determine whether the well has discovered crude oil and natural gas reserves and, if so, whether those reserves can be classified as proved reserves. Often, the determination of whether proved reserves can be recorded under SEC guidelines cannot be made when drilling is completed. In those situations where management believes that economically producible hydrocarbons have not been discovered, the exploratory drilling costs are reflected on the consolidated statements of comprehensive income (loss) as dry hole costs, a component of “Exploration expenses”. Where sufficient hydrocarbons have been discovered to justify further exploration or appraisal activities, exploratory drilling costs are deferred under the caption “Net property and equipment” on the consolidated balance sheets pending the outcome of those activities. On a quarterly basis, operating and financial management review the status of all deferred exploratory drilling costs in light of ongoing exploration activities—in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts. If management determines that future appraisal drilling or development activities are not likely to occur, any associated exploratory well costs are expensed in that period of determination. The following table presents the amount of capitalized exploratory drilling costs pending evaluation at December 31 for each of the last three years and changes in those amounts during the years then ended: Year ended December 31, In thousands 2017 2016 2015 Balance at January 1 $ 34,852 $ 59,397 $ 93,421 Additions to capitalized exploratory well costs pending determination of proved reserves 79,451 123,980 132,806 Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves (81,035 ) (141,941 ) (160,779 ) Capitalized exploratory well costs charged to expense (1,912 ) (6,584 ) (6,051 ) Balance at December 31 $ 31,356 $ 34,852 $ 59,397 Number of gross wells 37 54 73 As of December 31, 2017 , the Company had no significant exploratory drilling costs that were suspended one year beyond the completion of drilling.

Supplemental Crude Oil and Natu

Supplemental Crude Oil and Natural Gas Information (Unaudited)	12 Months Ended
	Dec. 31, 2017
Supplemental Crude Oil and Natural Gas Information [Abstract]
Supplemental Crude Oil and Natural Gas Information (Unaudited)	Supplemental Crude Oil and Natural Gas Information (Unaudited) The table below shows estimates of proved reserves prepared by the Company’s internal technical staff and independent external reserve engineers in accordance with SEC definitions. Ryder Scott Company, L.P. prepared reserve estimates for properties comprising approximately 96% , 99% , and 98% of the Company's total proved reserves as of December 31, 2017 , 2016 , and 2015 , respectively. Remaining reserve estimates were prepared by the Company’s internal technical staff. All proved reserves stated herein are located in the United States. No proved reserves have been included for the Company’s Canadian operations as of December 31, 2017 , 2016 , and 2015 . Proved reserves are estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be economically producible in future periods from known reservoirs under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured, and estimates of engineers other than the Company’s might differ materially from the estimates set forth herein. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Periodic revisions to the estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Accordingly, reserve estimates may differ significantly from the quantities of crude oil and natural gas ultimately recovered. Reserves at December 31, 2017 , 2016 and 2015 were computed using the 12-month unweighted average of the first-day-of-the-month commodity prices as required by SEC rules. Natural gas imbalance receivables and payables for each of the three years ended December 31, 2017 , 2016 and 2015 were not material and have not been included in the reserve estimates. Proved crude oil and natural gas reserves Changes in proved reserves were as follows for the periods presented: Crude Oil Natural Gas Total Proved reserves as of December 31, 2014 866,360 2,908,386 1,351,091 Revisions of previous estimates (246,840 ) (302,143 ) (297,198 ) Extensions, discoveries and other additions 134,764 710,453 253,173 Production (53,517 ) (164,454 ) (80,926 ) Sales of minerals in place (253 ) (456 ) (329 ) Purchases of minerals in place — — — Proved reserves as of December 31, 2015 700,514 3,151,786 1,225,811 Revisions of previous estimates (99,966 ) (63,057 ) (110,474 ) Extensions, discoveries and other additions 97,587 911,062 249,430 Production (46,850 ) (195,240 ) (79,390 ) Sales of minerals in place (8,057 ) (14,733 ) (10,513 ) Purchases of minerals in place — — — Proved reserves as of December 31, 2016 643,228 3,789,818 1,274,864 Revisions of previous estimates (77,779 ) (25,390 ) (82,012 ) Extensions, discoveries and other additions 129,895 661,867 240,206 Production (50,536 ) (228,159 ) (88,562 ) Sales of minerals in place (4,365 ) (64,989 ) (15,197 ) Purchases of minerals in place 506 7,134 1,696 Proved reserves as of December 31, 2017 640,949 4,140,281 1,330,995 Revisions of previous estimates. Revisions represent changes in previous reserve estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices and differentials, operating costs or development costs. In 2017 , the Company continued to refine its capital program to focus on areas that provide the greatest opportunities to achieve operating efficiencies and cost reductions, to convert undeveloped acreage to acreage held by production, and to improve hydrocarbon recoveries, cash flows and rates of return using optimized completions. As part of this effort, the Company shifted a portion of its 2017 spending away from the SCOOP and Bakken plays to areas in the emerging STACK play that offered more advantageous opportunities and rates of return in the 2017 commodity price environment. This shift in strategy coupled with the Company's increased emphasis on balancing capital spending with cash flows altered the timing and extent of previous development plans in certain areas and resulted in the removal of 41 MMBo and 290 Bcf (totaling 89 MMBoe) of PUD reserves no longer scheduled to be developed within five years from the date of initial booking. Commodity prices increased on average in 2017 relative to 2016 in response to improving domestic and global supply and demand fundamentals and other factors. The 12-month average first-day-of-the-month price for crude oil increased 20% from $42.75 per Bbl for 2016 to $51.34 per Bbl for 2017 , while the 12-month average first-day-of-the-month price for natural gas increased 20% from $2.49 per MMBtu for 2016 to $2.98 per MMBtu for 2017 . These changes increased the economic lives of certain producing properties and caused certain previously uneconomic projects to become economic, which had a favorable impact on the Company’s proved reserve estimates, resulting in upward revisions of 29 MMBo and 78 Bcf (totaling 42 MMBoe) in 2017 . Additionally, changes in anticipated production performance on certain properties resulted in 59 MMBo of downward revisions to crude oil reserves and 173 Bcf of upward revisions to natural gas reserves (netting to 30 MMBoe of downward revisions) in 2017 . Further, changes in ownership interests, operating costs, and other factors during the year resulted in 7 MMBo of downward revisions to crude oil reserves and 11 Bcf of upward revisions to natural gas reserves (netting to 5 MMBoe of downward revisions) in 2017 . Extensions, discoveries and other additions . These are additions to proved reserves resulting from (1) extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery and (2) discovery of new fields with proved reserves or of new reservoirs of proved reserves in old fields. Extensions, discoveries and other additions for each of the three years reflected in the table above were primarily due to increases in proved reserves associated with our successful drilling and completion activities in the Bakken, SCOOP, and STACK plays. Proved reserve additions in the Bakken totaled 106 MMBo and 253 Bcf (totaling 148 MMBoe) and reserve additions in SCOOP totaled 16 MMBo and 224 Bcf (totaling 53 MMBoe) for the year ended December 31, 2017 . Additionally, 2017 extensions and discoveries were impacted by successful drilling and completion results in the STACK play, resulting in proved reserve additions of 8 MMBo and 185 Bcf (totaling 39 MMBoe) in 2017 . Sales of minerals in place. These are reductions to proved reserves resulting from the disposition of properties during a period. See Note 14. Property Dispositions for a discussion of notable dispositions. Purchases of minerals in place. These are additions to proved reserves resulting from the acquisition of properties during a period. There were no significant acquisitions in the three years reflected in the table above. The following reserve information sets forth the estimated quantities of proved developed and proved undeveloped crude oil and natural gas reserves of the Company as of December 31, 2017 , 2016 and 2015 : December 31, 2017 2016 2015 Proved Developed Reserves Crude oil (MBbl) 318,707 290,210 326,798 Natural Gas (MMcf) 1,699,161 1,370,620 1,190,343 Total (MBoe) 601,901 518,646 525,188 Proved Undeveloped Reserves Crude oil (MBbl) 322,242 353,018 373,716 Natural Gas (MMcf) 2,441,120 2,419,198 1,961,443 Total (MBoe) 729,094 756,218 700,623 Total Proved Reserves Crude oil (MBbl) 640,949 643,228 700,514 Natural Gas (MMcf) 4,140,281 3,789,818 3,151,786 Total (MBoe) 1,330,995 1,274,864 1,225,811 Proved developed reserves are reserves expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are reserves expected to be recovered from new wells on undrilled acreage or from existing wells that require relatively major capital expenditures to recover. Natural gas is converted to barrels of crude oil equivalent using a conversion factor of six thousand cubic feet per barrel of crude oil based on the average equivalent energy content of natural gas compared to crude oil. Standardized measure of discounted future net cash flows relating to proved crude oil and natural gas reserves The standardized measure of discounted future net cash flows presented in the following table was computed using the 12-month unweighted average of the first-day-of-the-month commodity prices, the costs in effect at December 31 of each year and a 10% discount factor. The Company cautions that actual future net cash flows may vary considerably from these estimates. Although the Company’s estimates of total proved reserves, development costs and production rates were based on the best available information, the development and production of the crude oil and natural gas reserves may not occur in the periods assumed. Actual prices realized, costs incurred and production quantities may vary significantly from those used. Therefore, the estimated future net cash flow computations should not be considered to represent the Company’s estimate of the expected revenues or the current value of existing proved reserves. The following table sets forth the standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves as of December 31, 2017 , 2016 and 2015 . December 31, In thousands 2017 2016 2015 Future cash inflows $ 42,574,897 $ 31,008,587 $ 36,551,672 Future production costs (11,159,362 ) (9,175,410 ) (10,869,493 ) Future development and abandonment costs (6,487,097 ) (6,452,647 ) (6,935,958 ) Future income taxes (1) (3,488,755 ) (3,018,839 ) (3,717,612 ) Future net cash flows 21,439,683 12,361,691 15,028,609 10% annual discount for estimated timing of cash flows (10,969,506 ) (6,851,468 ) (8,552,325 ) Standardized measure of discounted future net cash flows $ 10,470,177 $ 5,510,223 $ 6,476,284 (1) Estimated future income taxes were calculated by applying existing statutory tax rates, including any known future changes, to the estimated pre-tax net cash flows related to proved crude oil and natural gas reserves, giving effect to any permanent taxable differences and tax credits, less the tax basis of the properties involved. The U.S. federal statutory tax rate utilized in estimating future income taxes was 21% at December 31, 2017 and 35% at December 31, 2016 and 2015. The weighted average crude oil price (adjusted for location and quality differentials) utilized in the computation of future cash inflows was $47.03 , $35.57 , and $41.63 per barrel at December 31, 2017 , 2016 and 2015 , respectively. The weighted average natural gas price (adjusted for location and quality differentials) utilized in the computation of future cash inflows was $3.00 , $2.14 , and $2.35 per Mcf at December 31, 2017 , 2016 and 2015 , respectively. Future cash flows are reduced by estimated future costs to develop and produce the proved reserves, as well as certain abandonment costs, based on year-end cost estimates assuming continuation of existing economic conditions. The expected tax benefits to be realized from the utilization of net operating loss carryforwards and tax credits are used in the computation of future income tax cash flows. The changes in the aggregate standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves are presented below for each of the past three years. December 31, In thousands 2017 2016 2015 Standardized measure of discounted future net cash flows at January 1 $ 5,510,223 $ 6,476,284 $ 18,433,034 Extensions, discoveries and improved recoveries, less related costs 1,462,629 786,587 1,091,283 Revisions of previous quantity estimates (1,004,355 ) (794,785 ) (2,156,028 ) Changes in estimated future development and abandonment costs 743,657 1,651,218 5,008,731 Sales of minerals in place, net (41,077 ) (90,390 ) (7,768 ) Net change in prices and production costs 3,808,116 (2,003,163 ) (16,111,142 ) Accretion of discount 665,507 798,597 1,843,303 Sales of crude oil and natural gas produced, net of production costs (2,450,474 ) (1,595,281 ) (2,002,997 ) Development costs incurred during the period 1,045,875 454,983 1,394,584 Change in timing of estimated future production and other 948,519 (538,665 ) (3,844,259 ) Change in income taxes (218,443 ) 364,838 2,827,543 Net change 4,959,954 (966,061 ) (11,956,750 ) Standardized measure of discounted future net cash flows at December 31 $ 10,470,177 $ 5,510,223 $ 6,476,284

Quarterly Financial Data (Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data (Unaudited)	Quarterly Financial Data (Unaudited) The Company’s unaudited quarterly financial data for 2017 and 2016 is summarized below. Quarter ended In thousands, except per share data March 31 June 30 September 30 December 31 2017 Total revenues (1) $ 685,427 $ 661,486 $ 726,743 $ 1,047,172 Gain on crude oil and natural gas derivatives, net (1) $ 46,858 $ 28,022 $ 8,602 $ 8,165 Property impairments (2) $ 51,372 $ 123,316 $ 35,130 $ 27,552 Litigation settlement (3) $ — $ — $ — $ 59,600 Gain (loss) on sale of assets, net (4) $ (3,638 ) $ 780 $ 3,562 $ 54,420 Income (loss) from operations $ 77,221 $ (29,041 ) $ 91,753 $ 309,468 Net income (loss) (5) $ 469 $ (63,557 ) $ 10,621 $ 841,914 Net income (loss) per share: Basic $ — $ (0.17 ) $ 0.03 $ 2.27 Diluted $ — $ (0.17 ) $ 0.03 $ 2.25 2016 Total revenues (1) $ 453,174 $ 451,211 $ 526,199 $ 549,689 Gain (loss) on crude oil and natural gas derivatives, net (1) $ 42,112 $ (82,257 ) $ 15,668 $ (47,382 ) Property impairments (2) $ 78,927 $ 66,112 $ 57,689 $ 34,564 Gain on sale of assets, net (4) $ 109 $ 96,907 $ 6,158 $ 201,315 Income (loss) from operations $ (239,103 ) $ (110,547 ) $ (93,183 ) $ 155,299 Loss on extinguishment of debt (6) $ — $ — $ — $ 26,055 Net income (loss) $ (198,326 ) $ (119,402 ) $ (109,621 ) $ 27,670 Net income (loss) per share: Basic $ (0.54 ) $ (0.32 ) $ (0.30 ) $ 0.07 Diluted $ (0.54 ) $ (0.32 ) $ (0.30 ) $ 0.07 (1) Gains and losses on crude oil and natural gas derivative instruments are reflected in “Total revenues” on both the consolidated statements of comprehensive income (loss) and this table of unaudited quarterly financial data. Crude oil and natural gas derivative gains and losses have been shown separately to illustrate the fluctuations in revenues that are attributable to the Company’s derivative instruments. Commodity price fluctuations each quarter can result in significant swings in mark-to-market gains and losses, which affects comparability between periods. (2) Property impairments have been shown separately to illustrate the impact on quarterly results attributable to write downs of the Company’s assets. Commodity price fluctuations each quarter can result in significant changes in estimated future cash flows and resulting impairments, which affects comparability between periods. (3) Fourth quarter 2017 results include a $59.6 million pre-tax loss accrual recognized in conjunction with a litigation settlement as discussed in Note 10. Commitments and Contingencies , which resulted in an after-tax decrease in net income of $37.0 million ( $0.10 per basic and diluted share). (4) Gains on asset sales have been shown separately to illustrate the impact on quarterly results attributable to asset dispositions, which differ in significance from period to period and affect comparability. See Note 14. Property Dispositions for a discussion of notable dispositions. (5) Fourth quarter 2017 results reflect the remeasurement of the Company's deferred income tax assets and liabilities in response to the enactment of the Tax Reform Act in December 2017, which resulted in a one-time decrease in income tax expense and corresponding increase in net income of approximately $713.7 million ( $1.92 per basic share and $1.91 per diluted share). See Note 8. Income Taxes for further discussion. (6) See Note 7. Long-Term Debt for discussion of the loss recognized by the Company upon the redemption of its 2020 Notes and 2021 Notes in the 2016 fourth quarter.

Organization and Summary of S24

Organization and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Description of the Company	Description of the Company Continental Resources, Inc. (the “Company”) was originally formed in 1967 and is incorporated under the laws of the State of Oklahoma. The Company’s principal business is crude oil and natural gas exploration, development and production with properties primarily located in the North, South, and East regions of the United States. The North region consists of properties north of Kansas and west of the Mississippi River and includes North Dakota Bakken, Montana Bakken, and the Red River units. The South region includes all properties south of Nebraska and west of the Mississippi River including various plays in the SCOOP (South Central Oklahoma Oil Province) and STACK (Sooner Trend Anadarko Canadian Kingfisher) areas of Oklahoma. The East region is primarily comprised of undeveloped leasehold acreage east of the Mississippi River with no significant drilling or production operations. A substantial portion of the Company’s operations is located in the North region, with that region comprising approximately 59% of the Company’s crude oil and natural gas production and approximately 69% of its crude oil and natural gas revenues for the year ended December 31, 2017 . The Company’s principal producing properties in the North region are located in the Bakken field of North Dakota and Montana. As of December 31, 2017 , approximately 50% of the Company’s estimated proved reserves were located in the North region. In recent years, the Company has significantly expanded its operations in the South region with its increased activity in the SCOOP and STACK plays. The South region comprised approximately 41% of the Company’s crude oil and natural gas production, 31% of its crude oil and natural gas revenues, and 50% of its estimated proved reserves as of and for the year ended December 31, 2017 . For the year ended December 31, 2017 , crude oil accounted for approximately 57% of the Company’s total production and approximately 78% of its crude oil and natural gas revenues. Crude oil represents approximately 48% of the Company’s estimated proved reserves as of December 31, 2017 .
Basis of presentation of consolidated financial statements	Basis of presentation of consolidated financial statements The consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are 100% owned, after all significant intercompany accounts and transactions have been eliminated upon consolidation.
Use of Estimates	Use of estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure and estimation of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Actual results may differ from those estimates. The most significant estimates and assumptions impacting reported results are estimates of the Company’s crude oil and natural gas reserves, which are used to compute depreciation, depletion, amortization and impairment of proved crude oil and natural gas properties.
Revenue Recognition	Revenue recognition Crude oil and natural gas sales result from interests owned by the Company in crude oil and natural gas properties. Sales of crude oil and natural gas produced from crude oil and natural gas operations are recognized when the product is delivered to the purchaser and title transfers to the purchaser. Payment is generally received one to three months after the sale has occurred. The Company uses the sales method of accounting for natural gas imbalances in those circumstances where it has under-produced or over-produced its ownership percentage in a property. Under this method, a receivable or payable is recognized only to the extent an imbalance cannot be recouped from the reserves in the underlying properties. The Company’s aggregate imbalance positions at December 31, 2017 and 2016 were not material. New accounting rules governing the recognition and presentation of revenues went into effect on January 1, 2018. See the subsequent section titled " New accounting pronouncements not yet adopted at December 31, 2017–Revenue recognition and presentation" for discussion of the expected impact of the new rules on the Company's future financial statements.
Cash and Cash Equivalents	Cash and cash equivalents The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The Company maintains its cash and cash equivalents in accounts that may not be federally insured. As of December 31, 2017 , the Company had cash deposits in excess of federally insured amounts of approximately $42.5 million . The Company has not experienced any losses in such accounts and believes it is not exposed to significant credit risk in this area.
Accounts Receivable	Accounts receivable The Company operates exclusively in crude oil and natural gas exploration and production related activities. Receivables arising from crude oil and natural gas sales and joint interest receivables are generally unsecured. Accounts receivable are due within 30 days and are considered delinquent after 60 days. The Company determines its allowance for doubtful accounts by considering a number of factors, including the length of time accounts are past due, the Company’s history of losses, and the customer or working interest owner’s ability to pay. The Company writes off specific receivables when they become noncollectable and any payments subsequently received on those receivables are credited to the allowance for doubtful accounts. Write-offs of noncollectable receivables have historically not been material. The Company’s allowance for doubtful accounts totaled $2.2 million and $3.0 million as of December 31, 2017 and 2016 , respectively, which is included in “Receivables — Joint interest and other, net” on the consolidated balance sheets.
Concentration of Credit Risk	Concentration of credit risk The Company is subject to credit risk resulting from the concentration of its crude oil and natural gas receivables with several significant purchasers. For the year ended December 31, 2017 , sales to the Company’s two largest purchasers accounted for approximately 11% and 11% , respectively, of the Company’s total crude oil and natural gas sales. No other purchaser accounted for more than 10% of the Company’s total crude oil and natural gas sales for 2017 . The Company does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers in various regions.
Inventories	Inventories Inventory is comprised of crude oil held in storage or as line fill in pipelines and tubular goods and equipment to be used in the Company’s exploration and development activities. Crude oil inventories are valued at the lower of cost or market primarily using the first-in, first-out inventory method. Tubular goods and equipment are valued primarily using a weighted average cost method applied to specific classes of inventory items. The components of inventory as of December 31, 2017 and 2016 consisted of the following: December 31, In thousands 2017 2016 Tubular goods and equipment $ 14,946 $ 15,243 Crude oil 82,460 96,744 Total $ 97,406 $ 111,987
Crude Oil and Natural Gas Properties	Crude oil and natural gas properties The Company uses the successful efforts method of accounting for crude oil and natural gas properties whereby costs incurred to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, to drill and equip development wells, and expenditures for enhanced recovery operations are capitalized. Geological and geophysical costs, seismic costs incurred for exploratory projects, lease rentals and costs associated with unsuccessful exploratory wells or projects are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. To the extent a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between capitalized development costs and exploration expense. Maintenance, repairs and costs of injection are expensed as incurred, except that the costs of replacements or renewals that expand capacity or improve production are capitalized. Under the successful efforts method of accounting, the Company capitalizes exploratory drilling costs on the balance sheet pending determination of whether the well has found proved reserves in economically producible quantities. The Company capitalizes costs associated with the acquisition or construction of support equipment and facilities with the drilling and development costs to which they relate. If proved reserves are found by an exploratory well, the associated capitalized costs become part of well equipment and facilities. However, if proved reserves are not found, the capitalized costs associated with the well are expensed, net of any salvage value. Production expenses are those costs incurred by the Company to operate and maintain its crude oil and natural gas properties and associated equipment and facilities. Production expenses include but are not limited to labor costs to operate the Company’s properties, repairs and maintenance, waste water disposal costs, utility costs, certain workover-related costs, and materials and supplies utilized in the Company’s operations.
Service Property and Equipment	Service property and equipment Service property and equipment consist primarily of automobiles and aircraft; machinery and equipment; gathering and recycling systems; storage tanks; office and computer equipment, software, furniture and fixtures; and buildings and improvements. Major renewals and replacements are capitalized and stated at cost, while maintenance and repairs are expensed as incurred. Depreciation and amortization of service property and equipment are provided in amounts sufficient to expense the cost of depreciable assets to operations over their estimated useful lives using the straight-line method. The estimated useful lives of service property and equipment are as follows: Service property and equipment Useful Lives In Years Automobiles and aircraft 5-10 Machinery and equipment 6-10 Gathering and recycling systems 15-30 Storage tanks 10-30 Office and computer equipment, software, furniture and fixtures 3-25 Buildings and improvements 4-40
Depreciation, Depletion and Amortization	Depreciation, depletion and amortization Depreciation, depletion and amortization of capitalized drilling and development costs of producing crude oil and natural gas properties, including related support equipment and facilities, are computed using the unit-of-production method on a field basis based on total estimated proved developed reserves. Amortization of producing leaseholds is based on the unit-of-production method using total estimated proved reserves. In arriving at rates under the unit-of-production method, the quantities of recoverable crude oil and natural gas reserves are established based on estimates made by the Company’s internal geologists and engineers and external independent reserve engineers. Upon sale or retirement of properties, the cost and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss, if any, is recognized. Unit of production rates are revised whenever there is an indication of a need, but at least in conjunction with semi-annual reserve reports. Revisions are accounted for prospectively as changes in accounting estimates.
Asset Retirement Obligations	Asset retirement obligations The Company accounts for its asset retirement obligations by recording the fair value of a liability for an asset retirement obligation in the period in which a legal obligation is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the capitalized asset retirement costs are charged to expense through the depreciation, depletion and amortization of crude oil and natural gas properties and the liability is accreted to the expected future abandonment cost ratably over the related asset’s life. The Company’s primary asset retirement obligations relate to future plugging and abandonment costs and related disposal of facilities on its crude oil and natural gas properties.
Asset Impairment	Asset impairment Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter. The estimated future cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value. Non-producing crude oil and natural gas properties primarily consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Impairment losses for non-producing properties are recognized by amortizing the portion of the properties’ costs which management estimates will not be transferred to proved properties over the lives of the leases based on drilling plans, experience of successful drilling, and the average holding period. The Company’s impairment assessments are affected by economic factors such as the results of exploration activities, commodity price outlooks, anticipated drilling programs, remaining lease terms, and potential shifts in business strategy employed by management.
Debt Issuance Costs	Debt issuance costs Costs incurred in connection with the execution of the Company’s note payable and revolving credit facility and any amendments thereto are capitalized and amortized over the terms of the arrangements on a straight-line basis, the use of which approximates the effective interest method. Costs incurred upon the issuances of the Company’s various senior notes (collectively, the “Notes”) were capitalized and are being amortized over the terms of the Notes using the effective interest method.
Derivative Instruments	Derivative instruments The Company recognizes its derivative instruments on the balance sheet as either assets or liabilities measured at fair value with such amounts classified as current or long-term based on contractual settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the changes in fair value in the consolidated statements of comprehensive income (loss). Gains and losses on crude oil and natural gas derivatives are reflected in the caption “ Gain (loss) on crude oil and natural gas derivatives, net .” Gains and losses on diesel fuel derivatives are reflected in the caption “Operating costs and expenses—Net gain on sale of assets and other.”
Fair Value of Financial Instruments	Fair value of financial instruments The Company’s financial instruments consist primarily of cash, trade receivables, trade payables, derivative instruments and long-term debt. See Note 6. Fair Value Measurements for a discussion of the methods used to determine fair value for the Company’s financial instruments and the quantification of fair value for its derivatives and long-term debt obligations at December 31, 2017 and 2016 .
Income Taxes	Income taxes Income taxes are accounted for using the liability method under which deferred income taxes are recognized for the future tax effects of temporary differences between financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year-end. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. On December 22, 2017, the Tax Cuts and Jobs Act (the "Tax Reform Act") was signed into law, which among other things reduces the federal corporate income tax rate from 35% to 21% effective January 1, 2018. In accordance with U.S. GAAP, the Company remeasured its deferred income tax assets and liabilities as of December 31, 2017 to reflect the reduced tax rate. See Note 8. Income Taxes for further discussion of the Tax Reform Act and its impact on the Company's financial statements as of and for the year ended December 31, 2017 . The Company’s policy is to recognize penalties and interest related to unrecognized tax benefits, if any, in income tax expense. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized. The Company recorded valuation allowances of $0.4 million , $1.0 million , and $13.5 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively, against deferred tax assets associated with operating loss carryforwards generated by its Canadian subsidiary for which the Company does not expect to realize a benefit.
Earnings Per Share	Earnings per share Basic net income (loss) per share is computed by dividing net income (loss) by the weighted-average number of shares outstanding for the period. In periods where the Company has net income, diluted earnings per share reflects the potential dilution of non-vested restricted stock awards, which are calculated using the treasury stock method.
Foreign Currency Transactions and Translations Policy	Foreign currency translation In 2014, the Company initiated exploratory drilling activities in Canada through a 100%-owned Canadian subsidiary. The Company’s operations in Canada are currently immaterial. The Company has designated the Canadian dollar as the functional currency for its Canadian operations. Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in “Accumulated other comprehensive income (loss)” within shareholders’ equity on the consolidated balance sheets.
New Accounting Pronouncements	Adoption of new accounting pronouncements Stock-based compensation – In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting , which changes how companies account for certain aspects of share-based payment awards, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. The Company adopted the new standard on January 1, 2017 as required. The impact of adoption is described below. ASU 2016-09 removes the requirement to delay recognition of an excess tax benefit until it reduces current taxes payable. An excess tax benefit (tax deficiency) arises when stock-based compensation expense recognized in an entity’s tax return exceeds (is less than) the expense recognized in an entity’s financial statements. Under the new standard, effective January 1, 2017 excess tax benefits are recorded when they arise. This change was required to be applied on a modified retrospective basis by recording a cumulative effect adjustment to opening retained earnings upon adoption to account for previously unrecognized excess tax benefits. The Company’s cumulative effect adjustment recorded under the new standard resulted in a $5.2 million increase in retained earnings and corresponding decrease in deferred income tax liabilities at January 1, 2017. Additionally, under ASU 2016-09 companies no longer record excess tax benefits and deficiencies in additional paid-in capital. Instead, excess tax benefits and deficiencies are recognized as income tax benefit or expense in the income statement, effective January 1, 2017 on a prospective basis. This is expected to result in increased volatility in income tax expense/benefit and corresponding variations in the relationship between income tax expense/benefit and pre-tax income/loss from period to period. The Company recognized $3.9 million ( $0.01 per basic and diluted share) of tax deficiencies from stock-based compensation as income tax expense for the year ended December 31, 2017 under the new standard, which is reflected in “Benefit for income taxes” in the consolidated statements of comprehensive income (loss). ASU 2016-09 also removed the requirement that entities present excess tax benefits and deficiencies as offsetting cash flows from financing and operating activities in the statement of cash flows. Instead, ASU 2016-09 requires cash flows related to excess tax benefits and deficiencies be classified as operating activities in the same manner as other cash flows related to income taxes. The Company has elected to apply this guidance on a prospective basis. Accordingly, the cash flow presentation of excess tax benefits and deficiencies in periods prior to January 1, 2017 has not been adjusted to conform to current period presentation. The Company has elected to continue its historical accounting practice of estimating forfeitures in determining the amount of stock-based compensation expense to recognize. Therefore, the adoption of ASU 2016-09 does not have an impact on the amount of stock-based compensation expense to be recognized by the Company on non-vested restricted stock awards. Business combinations – In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business , which changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities is deemed to be a business. Determining whether a transferred set constitutes a business is important because the accounting for a business combination differs from that of an asset acquisition. The definition of a business also affects the accounting for dispositions. Under the new standard, when substantially all of the fair value of assets acquired is concentrated in a single asset, or a group of similar assets, the assets acquired would not represent a business and business combination accounting would not be required. The new standard may result in more transactions being accounted for as asset acquisitions rather than business combinations. The standard is effective for interim and annual periods beginning after December 15, 2017 and shall be applied prospectively. The Company early adopted ASU 2017-01 as of January 1, 2017, which had no significant impact on the Company’s financial statements as of and for the year ended December 31, 2017. New accounting pronouncements not yet adopted at December 31, 2017 Revenue recognition and presentation – In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) , which generally requires an entity to identify performance obligations in its contracts, estimate the amount of consideration to be received in the transaction price, allocate the transaction price to each separate performance obligation, and recognize revenue as obligations are satisfied. Additionally, the standard requires expanded disclosures related to revenue recognition. Subsequent to the issuance of ASU 2014-09, the FASB issued various clarifications and interpretive guidance to assist entities with implementation efforts, including guidance pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis. Under this guidance, an entity generally shall record revenue on a gross basis if it controls a promised good or service before transferring it to a customer, whereas an entity shall record revenue on a net basis if its role is to arrange for another entity to provide the goods or services to a customer. Significant judgment may be required in some circumstances to determine whether gross or net presentation is appropriate. ASU 2014-09 and related interpretive guidance is effective for interim and annual periods beginning after December 15, 2017 and allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. The Company adopted the standard on January 1, 2018 using the modified retrospective approach, which had no cumulative effect impact on retained earnings upon adoption. The standard is not expected to have a material effect on the timing of the Company’s revenue recognition or its financial position, results of operations, net income, or cash flows, but will impact the Company’s revenue-related disclosures and internal controls over financial reporting beginning January 1, 2018. Additionally, the standard will impact the Company's future presentation of revenues and expenses under the gross-versus-net presentation guidance. Historically, the Company has generally presented its revenues net of transportation costs. The new guidance will result in future revenues and associated transportation expenses for certain of the Company’s operated properties being reported on a gross basis beginning January 1, 2018. The changes from net to gross presentation will result in an increase in revenues and a corresponding increase in separately reported transportation expenses, with no net effect on the Company’s results of operations, net income, or cash flows. For the year ended December 31, 2017 , the Company had approximately $201.5 million of transportation–related charges on operated properties included in “Crude oil and natural gas sales” on the consolidated statements of comprehensive income (loss). This amount is not necessarily indicative of amounts to be expected in future periods. The Company is not able to estimate the impact on the presentation of its future revenues and expenses under the new guidance due to uncertainties with respect to future sales volumes, service costs, locations of producing properties, sales destinations, transportation methods utilized, and changes in the nature, timing, and extent of its arrangements from period to period. Leases – In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) , which requires companies to recognize a right of use asset and related liability on the balance sheet for the rights and obligations arising from leases with durations greater than 12 months. The standard is effective for interim and annual reporting periods beginning after December 15, 2018 and requires adoption by application of a modified retrospective transition approach. The Company continues to evaluate the impact of ASU 2016-02 on its financial statements, accounting policies and internal controls and is in the process of developing systems and processes to identify, classify, and account for leases within the scope of the new guidance and to comply with the related disclosure requirements. Standard setting guidance and interpretations continue to evolve and are being monitored for applicability and impact to the Company’s business and industry. Based on an initial review of the new guidance and the Company’s current commitments, the Company anticipates it may be required to recognize lease assets and liabilities related to drilling rig commitments, certain equipment rentals and leases, certain surface use agreements, and potentially certain firm transportation agreements, as well as other arrangements, the effect of which cannot be estimated at this time. Credit losses – In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments . This standard changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. The standard is effective for interim and annual periods beginning after December 15, 2019 and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. The Company continues to evaluate the new standard and is unable to estimate its financial statement impact at this time. Historically, the Company’s credit losses on crude oil and natural gas sales receivables and joint interest receivables have been immaterial.

Organization and Summary of S25

Organization and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Components of Inventories	The components of inventory as of December 31, 2017 and 2016 consisted of the following: December 31, In thousands 2017 2016 Tubular goods and equipment $ 14,946 $ 15,243 Crude oil 82,460 96,744 Total $ 97,406 $ 111,987
Schedule of Estimated Useful Lives of Service Property and Equipment	The estimated useful lives of service property and equipment are as follows: Service property and equipment Useful Lives In Years Automobiles and aircraft 5-10 Machinery and equipment 6-10 Gathering and recycling systems 15-30 Storage tanks 10-30 Office and computer equipment, software, furniture and fixtures 3-25 Buildings and improvements 4-40
Summary of Changes in Future Abandonment Liabilities	The following table summarizes the changes in the Company’s future abandonment liabilities from January 1, 2015 through December 31, 2017 : In thousands 2017 2016 2015 Asset retirement obligations at January 1 $ 96,178 $ 102,909 $ 76,708 Accretion expense 5,886 6,086 4,740 Revisions (1) 7,801 (12,755 ) 15,068 Plus: Additions for new assets 6,884 2,692 7,404 Less: Plugging costs and sold assets (2,343 ) (2,754 ) (1,011 ) Total asset retirement obligations at December 31 $ 114,406 $ 96,178 $ 102,909 Less: Current portion of asset retirement obligations at December 31 (2) 2,612 1,742 1,658 Non-current portion of asset retirement obligations at December 31 $ 111,794 $ 94,436 $ 101,251 (1) Revisions primarily represent changes in the present value of liabilities resulting from changes in estimated costs and economic lives of producing properties. (2) Balance is included in the caption “Accrued liabilities and other” in the consolidated balance sheets.
Calculation of Basic and Diluted Weighted Average Shares and Net Income per Share	The following table presents the calculation of basic and diluted weighted average shares outstanding and net income (loss) per share for the years ended December 31, 2017 , 2016 and 2015 . Year ended December 31, In thousands, except per share data 2017 2016 2015 Net income (loss) (numerator) (1) $ 789,447 $ (399,679 ) $ (353,668 ) Weighted average shares (denominator): Weighted average shares - basic 371,066 370,380 369,540 Non-vested restricted stock (2) 2,702 — — Weighted average shares - diluted 373,768 370,380 369,540 Net income (loss) per share: (1) Basic $ 2.13 $ (1.08 ) $ (0.96 ) Diluted $ 2.11 $ (1.08 ) $ (0.96 ) (1) The Company’s remeasurement of its deferred income tax assets and liabilities in response to the enactment of the Tax Reform Act in December 2017 resulted in a one-time decrease in income tax expense and corresponding increase in net income of approximately $713.7 million ( $1.92 per basic share and $1.91 per diluted share) for the year ended December 31, 2017 . See Note 8. Income Taxes for further discussion. Additionally, 2017 results include a $59.6 million pre-tax loss accrual recognized in conjunction with a litigation settlement as discussed in Note 10. Commitments and Contingencies , which resulted in an after-tax decrease in 2017 net income of $37.0 million ( $0.10 per basic and diluted share). (2) For the years ended December 31, 2016 and 2015, the Company had a net loss and therefore the potential dilutive effect of approximately 2,303,000 and 1,567,000 weighted average non-vested restricted shares, respectively, were not included in the calculation of diluted net loss per share because to do so would have been anti-dilutive to the computations.

Supplemental Cash Flow Inform26

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2017
Supplemental Cash Flow Information [Abstract]
Summary of Supplemental Cash Flow Information	The following table discloses supplemental cash flow information about cash paid for interest and income tax payments and refunds. Also disclosed is information about investing activities that affects recognized assets and liabilities but does not result in cash receipts or payments. Year ended December 31, In thousands 2017 2016 2015 Supplemental cash flow information: Cash paid for interest $ 281,058 $ 316,116 $ 301,743 Cash paid for income taxes 2 2 30 Cash received for income tax refunds 257 174 61,403 Non-cash investing activities: Asset retirement obligation additions and revisions, net 14,685 (10,063 ) 22,472

Net Property and Equipment (Tab

Net Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment, Net [Abstract]
Schedule of Net Property and Equipment	Net property and equipment includes the following at December 31, 2017 and 2016 . December 31, In thousands 2017 2016 Proved crude oil and natural gas properties $ 21,362,199 $ 19,802,395 Unproved crude oil and natural gas properties 365,413 429,562 Service properties, equipment and other 290,111 301,788 Total property and equipment 22,017,723 20,533,745 Accumulated depreciation, depletion and amortization (9,083,934 ) (7,652,518 ) Net property and equipment $ 12,933,789 $ 12,881,227

Accrued Liabilities and Other (

Accrued Liabilities and Other (Tables)	12 Months Ended
	Dec. 31, 2017
Accrued Liabilities and Other Liabilities [Abstract]
Schedule of Accrued Liabilities and Other	Accrued liabilities and other includes the following at December 31, 2017 and 2016 : December 31, In thousands 2017 2016 Prepaid advances from joint interest owners $ 34,511 $ 57,861 Accrued compensation 65,308 38,046 Accrued production taxes, ad valorem taxes and other non-income taxes 40,611 22,053 Accrued interest 55,282 52,657 Accrued litigation settlement (see Note 10) 59,600 — Current portion of asset retirement obligations 2,612 1,742 Other 2,150 4,411 Accrued liabilities and other $ 260,074 $ 176,770

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative [Line Items]
Summary of Outstanding Contracts with Respect to Natural Gas	Period and Type of Contract MMBtus Swaps Weighted Average Price January 2018 - March 2018 Swaps - Henry Hub 6,300,000 $ 3.28
Realized and Unrealized Gains and Losses on Derivative Instruments	Cash receipts in the following table reflect gains on diesel fuel derivatives which matured during the period, calculated as the difference between the contract price and the market settlement price of matured contracts. Non-cash gains and losses below represent the change in fair value of diesel fuel derivatives held at period end, if any, and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period. Year ended December 31, In thousands 2017 2016 Cash received on diesel fuel derivatives $ 2,845 $ 699 Non-cash gain (loss) on diesel fuel derivatives (4,060 ) 4,060 Gain (loss) on diesel fuel derivatives, net $ (1,215 ) $ 4,759 Year ended December 31, In thousands 2017 2016 2015 Cash received (paid) on derivatives: Natural gas fixed price swaps $ 40,095 $ 88,823 $ 39,670 Natural gas collars (10,539 ) — 29,883 Cash received on derivatives, net 29,556 88,823 69,553 Non-cash gain (loss) on derivatives: Crude oil written call options — 38 4,715 Natural gas fixed price swaps 18,960 (120,784 ) 41,828 Natural gas collars 43,131 (39,936 ) (25,011 ) Non-cash gain (loss) on derivatives, net 62,091 (160,682 ) 21,532 Gain (loss) on crude oil and natural gas derivatives, net $ 91,647 $ (71,859 ) $ 91,085
Balance sheet offsetting of derivative assets and liabilities	The following table presents the gross amounts of recognized crude oil, natural gas, and diesel fuel derivative assets and liabilities, as applicable, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the consolidated balance sheets for the periods presented, all at fair value. December 31, In thousands 2017 2016 Commodity derivative assets: Gross amounts of recognized assets $ 2,603 $ 4,061 Gross amounts offset on balance sheet — — Net amounts of assets on balance sheet 2,603 4,061 Commodity derivative liabilities: Gross amounts of recognized liabilities — (59,489 ) Gross amounts offset on balance sheet — — Net amounts of liabilities on balance sheet $ — $ (59,489 )
Schedule Of Derivative Assets Liabilities At Fair Value Net By Balance Sheet Classification Table	The following table reconciles the net amounts disclosed above to the individual financial statement line items in the consolidated balance sheets. December 31, In thousands 2017 2016 Derivative assets $ 2,603 $ 4,061 Noncurrent derivative assets — — Net amounts of assets on balance sheet 2,603 4,061 Derivative liabilities — (59,489 ) Noncurrent derivative liabilities — — Net amounts of liabilities on balance sheet — (59,489 ) Total derivative assets (liabilities), net $ 2,603 $ (55,428 )

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Valuation of Financial Instruments by Pricing Levels	The following tables summarize the valuation of financial instruments by pricing levels that were accounted for at fair value on a recurring basis as of December 31, 2017 and 2016 . Fair value measurements at December 31, 2017 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets: Swaps $ — $ 2,603 $ — $ 2,603 Total $ — $ 2,603 $ — $ 2,603 Fair value measurements at December 31, 2016 using: In thousands Level 1 Level 2 Level 3 Total Derivative liabilities: Swaps $ — $ (12,297 ) $ — $ (12,297 ) Collars — (43,131 ) — (43,131 ) Total $ — $ (55,428 ) $ — $ (55,428 )
Unobservable inputs used in level 3 fair value measurements	Unobservable Input Assumption Future production Future production estimates for each property Forward commodity prices Forward NYMEX strip prices through 2022 (adjusted for differentials), escalating 3% per year thereafter Operating costs Estimated costs for the current year, escalating 3% per year thereafter Productive life of field Ranging from 1 to 38 years Discount rate 10% Unobservable inputs to the fair value assessment are reviewed quarterly and are revised as warranted based on a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Fair value measurements of proved properties are reviewed and approved by certain members of the Company’s management.
Property Impairments	The following table sets forth the non-cash impairments of both proved and unproved properties for the indicated periods. Proved and unproved property impairments are recorded under the caption “Property impairments” in the consolidated statements of comprehensive income (loss). Year ended December 31, In thousands 2017 2016 2015 Proved property impairments $ 82,340 $ 2,895 $ 138,878 Unproved property impairments 155,030 234,397 263,253 Total $ 237,370 $ 237,292 $ 402,131
Fair Values of Financial Instruments not Recorded at Fair Value	The following table sets forth the estimated fair values of financial instruments that are not recorded at fair value in the consolidated financial statements. December 31, 2017 December 31, 2016 In thousands Carrying Amount Fair Value Carrying Amount Fair Value Debt: Revolving credit facility (1) $ 188,000 $ 188,000 $ 905,000 $ 905,000 Term loan (1) — — 498,865 500,000 Note payable 9,974 9,900 12,176 10,200 5% Senior Notes due 2022 1,997,576 2,040,000 1,997,188 2,020,400 4.5% Senior Notes due 2023 1,486,690 1,526,800 1,484,524 1,474,800 3.8% Senior Notes due 2024 992,036 988,800 990,964 929,400 4.375% Senior Notes due 2028 (1) 988,061 987,200 — — 4.9% Senior Notes due 2044 691,354 679,900 691,199 607,600 Total debt $ 6,353,691 $ 6,420,600 $ 6,579,916 $ 6,447,400 (1) In December 2017, the Company issued $1.0 billion of 4.375% Senior Notes due 2028 and used the proceeds therefrom to repay in full and terminate its term loan and to repay a portion of the borrowings outstanding under its revolving credit facility. See Note 7. Long-Term Debt for further discussion.

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Long-Term Debt	Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $44.3 million and $37.3 million at December 31, 2017 and 2016 , respectively, consists of the following. December 31, In thousands 2017 2016 Revolving credit facility $ 188,000 $ 905,000 Term loan — 498,865 Note payable 9,974 12,176 5% Senior Notes due 2022 1,997,576 1,997,188 4.5% Senior Notes due 2023 1,486,690 1,484,524 3.8% Senior Notes due 2024 992,036 990,964 4.375% Senior Notes due 2028 988,061 — 4.9% Senior Notes due 2044 691,354 691,199 Total debt 6,353,691 6,579,916 Less: Current portion of long-term debt 2,286 2,219 Long-term debt, net of current portion $ 6,351,405 $ 6,577,697
Summary of Maturity Dates, Semi-Annual Interest Payment Dates, and Optional Redemption Periods of Outstanding Senior Note Obligations	The following table summarizes the face values, maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding senior note obligations at December 31, 2017 . 2022 Notes (1) 2023 Notes 2024 Notes 2028 Notes 2044 Notes Face value (in thousands) $2,000,000 $1,500,000 $1,000,000 $1,000,000 $700,000 Maturity date Sep 15, 2022 April 15, 2023 June 1, 2024 January 15, 2028 June 1, 2044 Interest payment dates March 15, Sep 15 April 15, Oct 15 June 1, Dec 1 Jan 15, July 15 June 1, Dec 1 Make-whole redemption period (2) — Jan 15, 2023 Mar 1, 2024 Oct 15, 2027 Dec 1, 2043 (1) The Company has the option to redeem all or a portion of its 2022 Notes at the decreasing redemption prices specified in the indenture related to the 2022 Notes plus any accrued and unpaid interest to the date of redemption. (2) At any time prior to the indicated dates, the Company has the option to redeem all or a portion of its senior notes of the applicable series at the “make-whole” redemption prices or amounts specified in the respective senior note indentures plus any accrued and unpaid interest to the date of redemption. On or after these dates, the Company may redeem all or a portion of its senior notes at a redemption price equal to 100% of the principal amount of the senior notes being redeemed plus any accrued and unpaid interest to the date of redemption.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Provision for Income Taxes	The items comprising the Company's benefit for income taxes are as follows for the periods presented: Year ended December 31, In thousands 2017 2016 2015 Current income tax (provision) benefit: United States federal (1) $ 7,781 $ 22,941 $ — Various states — (2 ) (24 ) Total current income tax (provision) benefit 7,781 22,939 (24 ) Deferred income tax (provision) benefit: United States federal - taxation on operations (81,054 ) 182,422 140,578 United States federal - effect of US tax reform 713,655 — — Various states (7,002 ) 27,414 40,863 Total deferred income tax benefit 625,599 209,836 181,441 Benefit for income taxes $ 633,380 $ 232,775 $ 181,417
Schedule of Provision for Income Taxes with Income Tax at Federal Statutory Rate	Year ended December 31, 2017 2016 2015 In thousands, except rates Amount Rate Amount Rate Amount Rate Expected income tax (provision) benefit based on US statutory tax rate of 35% $ (54,623 ) 35.0 % $ 221,359 35.0 % $ 187,280 35.0 % State income taxes, net of federal benefit (4,682 ) 3.0 % 18,829 3.0 % 16,219 3.0 % Effect of US tax reform legislation 713,655 (457.3 %) — — % — — % Tax deficiency from stock-based compensation (1) (3,932 ) 2.5 % — — % — — % Canadian valuation allowance (2) (404 ) 0.3 % (1,044 ) (0.2 %) (13,503 ) (2.5 %) Effect of differing statutory tax rate in Canada (194 ) 0.1 % (481 ) (0.1 %) (5,239 ) (1.0 %) Non-deductible compensation (13,813 ) 8.9 % (3,471 ) (0.5 %) (1,488 ) (0.3 %) Other, net (2,627 ) 1.7 % (2,417 ) (0.4 %) (1,852 ) (0.3 %) Benefit for income taxes $ 633,380 (405.8 %) $ 232,775 36.8 % $ 181,417 33.9 %
Components of Deferred Tax Assets and Liabilities	The components of the Company’s deferred tax assets and deferred tax liabilities as of December 31, 2017 and 2016 are reflected in the table below. December 31, In thousands 2017 2016 Deferred tax assets United States net operating loss carryforwards $ 604,423 $ 478,975 Canadian net operating loss carryforwards 19,341 18,936 Alternative minimum tax carryforwards 7,781 16,663 Equity compensation 12,962 32,924 Non-cash losses on derivatives — 21,064 Other 21,885 11,466 Total deferred tax assets 666,392 580,028 Canadian valuation allowance (19,341 ) (18,936 ) Total deferred tax assets, net of valuation allowance 647,051 561,092 Deferred tax liabilities Property and equipment (1,903,451 ) (2,448,450 ) Other (3,158 ) (2,947 ) Total deferred tax liabilities (1,906,609 ) (2,451,397 ) Deferred income tax liabilities, net $ (1,259,558 ) $ (1,890,305 )

Lease Commitments (Tables)

Lease Commitments (Tables)	12 Months Ended
	Dec. 31, 2017
Leases [Abstract]
Schedule of Minimum Future Rental Commitments Under Operating Leases	At December 31, 2017 , the minimum future rental commitments under operating leases having lease terms in excess of one year are reflected in the table below. New accounting rules will go into effect for reporting periods beginning after December 15, 2018 that will impact the Company's accounting for leases. See Note 1. Organization and Summary of Significant Accounting Policies–New accounting pronouncements not yet adopted at December 31, 2017–Leases for further discussion. In thousands Total amount 2018 $ 1,656 2019 958 2020 817 2021 645 2022 620 Thereafter 7,208 Total obligations $ 11,904

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2017
Stock-Based Compensation Expense	The Company’s associated compensation expense, which is included in the caption “General and administrative expenses” in the consolidated statements of comprehensive income (loss), was $45.9 million , $48.1 million , and $51.8 million for the years ended December 31, 2017 , 2016 and 2015 , respectively.
Restricted stock [Member]
Summary of Changes in Non-vested Shares of Restricted Stock	A summary of changes in non-vested restricted shares from December 31, 2014 to December 31, 2017 is presented below. Number of Weighted Non-vested restricted shares at December 31, 2014 2,678,764 $ 49.40 Granted 1,462,534 46.65 Vested (555,517 ) 48.07 Forfeited (336,170 ) 51.23 Non-vested restricted shares at December 31, 2015 3,249,611 $ 48.20 Granted 2,064,508 22.36 Vested (1,207,235 ) 41.27 Forfeited (193,250 ) 39.79 Non-vested restricted shares at December 31, 2016 3,913,634 $ 37.12 Granted 1,585,870 44.58 Vested (874,665 ) 57.36 Forfeited (598,729 ) 37.34 Non-vested restricted shares at December 31, 2017 4,026,110 $ 35.63

Accumulated Other Comprehensi35

Accumulated Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2017
Statement of Comprehensive Income [Abstract]
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	The following table summarizes the change in accumulated other comprehensive income (loss) for the years ended December 31, 2017 , 2016 , and 2015 : Year ended December 31, In thousands 2017 2016 2015 Beginning accumulated other comprehensive loss, net of tax $ (260 ) $ (3,354 ) $ (385 ) Foreign currency translation adjustments 567 3,094 (2,969 ) Income taxes (1) — — — Other comprehensive income (loss), net of tax 567 3,094 (2,969 ) Ending accumulated other comprehensive income (loss), net of tax $ 307 $ (260 ) $ (3,354 ) (1) A valuation allowance has been recognized against all deferred tax assets associated with losses generated by the Company’s Canadian operations, thereby resulting in no income taxes on other comprehensive income (loss).

Crude Oil and Natural Gas Pro36

Crude Oil and Natural Gas Property Information (Tables)	12 Months Ended
	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Schedule of Results of Operations from Crude Oil and Natural Gas Producing Activities	The following table sets forth the Company’s consolidated results of operations from crude oil and natural gas producing activities for the years ended December 31, 2017 , 2016 and 2015 . Year ended December 31, In thousands 2017 2016 2015 Crude oil and natural gas sales $ 2,982,966 $ 2,026,958 $ 2,552,531 Production expenses (324,214 ) (289,289 ) (348,897 ) Production taxes (208,278 ) (142,388 ) (200,637 ) Exploration expenses (12,393 ) (16,972 ) (19,413 ) Depreciation, depletion, amortization and accretion (1,652,180 ) (1,679,485 ) (1,722,336 ) Property impairments (237,370 ) (237,292 ) (402,131 ) Income tax benefit (1) 504,475 126,794 33,680 Results from crude oil and natural gas producing activities $ 1,053,006 $ (211,674 ) $ (107,203 )
Schedule of Costs Incurred in Oil and Gas Property Acquisition Exploration and Development Activities	Costs incurred, both capitalized and expensed, in connection with the Company’s consolidated crude oil and natural gas acquisition, exploration and development activities for the years ended December 31, 2017 , 2016 and 2015 are presented below: Year ended December 31, In thousands 2017 2016 2015 Property acquisition costs: Proved $ 8,446 $ 5,008 $ 557 Unproved 220,875 149,962 168,492 Total property acquisition costs 229,321 154,970 169,049 Exploration Costs 123,461 182,355 241,523 Development Costs 1,695,954 767,148 2,148,530 Total $ 2,048,736 $ 1,104,473 $ 2,559,102
Schedule of Aggregate Capitalized Costs Related to Crude Oil and Natural Gas Producing Activities	Aggregate capitalized costs relating to the Company’s consolidated crude oil and natural gas producing activities and related accumulated depreciation, depletion and amortization as of December 31, 2017 and 2016 are as follows: December 31, In thousands 2017 2016 Proved crude oil and natural gas properties $ 21,362,199 $ 19,802,395 Unproved crude oil and natural gas properties 365,413 429,562 Total 21,727,612 20,231,957 Less accumulated depreciation, depletion and amortization (8,971,935 ) (7,553,255 ) Net capitalized costs $ 12,755,677 $ 12,678,702
Schedule of Capitalized Exploratory Drilling Costs Pending Evaluation	The following table presents the amount of capitalized exploratory drilling costs pending evaluation at December 31 for each of the last three years and changes in those amounts during the years then ended: Year ended December 31, In thousands 2017 2016 2015 Balance at January 1 $ 34,852 $ 59,397 $ 93,421 Additions to capitalized exploratory well costs pending determination of proved reserves 79,451 123,980 132,806 Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves (81,035 ) (141,941 ) (160,779 ) Capitalized exploratory well costs charged to expense (1,912 ) (6,584 ) (6,051 ) Balance at December 31 $ 31,356 $ 34,852 $ 59,397 Number of gross wells 37 54 73

Supplemental Crude Oil and Na37

Supplemental Crude Oil and Natural Gas Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Supplemental Crude Oil and Natural Gas Information [Abstract]
Proved crude oil and natural gas reserves	Proved crude oil and natural gas reserves Changes in proved reserves were as follows for the periods presented: Crude Oil Natural Gas Total Proved reserves as of December 31, 2014 866,360 2,908,386 1,351,091 Revisions of previous estimates (246,840 ) (302,143 ) (297,198 ) Extensions, discoveries and other additions 134,764 710,453 253,173 Production (53,517 ) (164,454 ) (80,926 ) Sales of minerals in place (253 ) (456 ) (329 ) Purchases of minerals in place — — — Proved reserves as of December 31, 2015 700,514 3,151,786 1,225,811 Revisions of previous estimates (99,966 ) (63,057 ) (110,474 ) Extensions, discoveries and other additions 97,587 911,062 249,430 Production (46,850 ) (195,240 ) (79,390 ) Sales of minerals in place (8,057 ) (14,733 ) (10,513 ) Purchases of minerals in place — — — Proved reserves as of December 31, 2016 643,228 3,789,818 1,274,864 Revisions of previous estimates (77,779 ) (25,390 ) (82,012 ) Extensions, discoveries and other additions 129,895 661,867 240,206 Production (50,536 ) (228,159 ) (88,562 ) Sales of minerals in place (4,365 ) (64,989 ) (15,197 ) Purchases of minerals in place 506 7,134 1,696 Proved reserves as of December 31, 2017 640,949 4,140,281 1,330,995
Schedule of proved developed and undeveloped oil and gas reserve quantities	The following reserve information sets forth the estimated quantities of proved developed and proved undeveloped crude oil and natural gas reserves of the Company as of December 31, 2017 , 2016 and 2015 : December 31, 2017 2016 2015 Proved Developed Reserves Crude oil (MBbl) 318,707 290,210 326,798 Natural Gas (MMcf) 1,699,161 1,370,620 1,190,343 Total (MBoe) 601,901 518,646 525,188 Proved Undeveloped Reserves Crude oil (MBbl) 322,242 353,018 373,716 Natural Gas (MMcf) 2,441,120 2,419,198 1,961,443 Total (MBoe) 729,094 756,218 700,623 Total Proved Reserves Crude oil (MBbl) 640,949 643,228 700,514 Natural Gas (MMcf) 4,140,281 3,789,818 3,151,786 Total (MBoe) 1,330,995 1,274,864 1,225,811
Standardized Measure of Discounted Future Net Cash Flows	The following table sets forth the standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves as of December 31, 2017 , 2016 and 2015 . December 31, In thousands 2017 2016 2015 Future cash inflows $ 42,574,897 $ 31,008,587 $ 36,551,672 Future production costs (11,159,362 ) (9,175,410 ) (10,869,493 ) Future development and abandonment costs (6,487,097 ) (6,452,647 ) (6,935,958 ) Future income taxes (1) (3,488,755 ) (3,018,839 ) (3,717,612 ) Future net cash flows 21,439,683 12,361,691 15,028,609 10% annual discount for estimated timing of cash flows (10,969,506 ) (6,851,468 ) (8,552,325 ) Standardized measure of discounted future net cash flows $ 10,470,177 $ 5,510,223 $ 6,476,284
Changes in Standardized Measure of Discounted Future Net Cash Flows	The changes in the aggregate standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves are presented below for each of the past three years. December 31, In thousands 2017 2016 2015 Standardized measure of discounted future net cash flows at January 1 $ 5,510,223 $ 6,476,284 $ 18,433,034 Extensions, discoveries and improved recoveries, less related costs 1,462,629 786,587 1,091,283 Revisions of previous quantity estimates (1,004,355 ) (794,785 ) (2,156,028 ) Changes in estimated future development and abandonment costs 743,657 1,651,218 5,008,731 Sales of minerals in place, net (41,077 ) (90,390 ) (7,768 ) Net change in prices and production costs 3,808,116 (2,003,163 ) (16,111,142 ) Accretion of discount 665,507 798,597 1,843,303 Sales of crude oil and natural gas produced, net of production costs (2,450,474 ) (1,595,281 ) (2,002,997 ) Development costs incurred during the period 1,045,875 454,983 1,394,584 Change in timing of estimated future production and other 948,519 (538,665 ) (3,844,259 ) Change in income taxes (218,443 ) 364,838 2,827,543 Net change 4,959,954 (966,061 ) (11,956,750 ) Standardized measure of discounted future net cash flows at December 31 $ 10,470,177 $ 5,510,223 $ 6,476,284

Quarterly Financial Data (Una38

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Schedule Of Quarterly Financial Data	The Company’s unaudited quarterly financial data for 2017 and 2016 is summarized below. Quarter ended In thousands, except per share data March 31 June 30 September 30 December 31 2017 Total revenues (1) $ 685,427 $ 661,486 $ 726,743 $ 1,047,172 Gain on crude oil and natural gas derivatives, net (1) $ 46,858 $ 28,022 $ 8,602 $ 8,165 Property impairments (2) $ 51,372 $ 123,316 $ 35,130 $ 27,552 Litigation settlement (3) $ — $ — $ — $ 59,600 Gain (loss) on sale of assets, net (4) $ (3,638 ) $ 780 $ 3,562 $ 54,420 Income (loss) from operations $ 77,221 $ (29,041 ) $ 91,753 $ 309,468 Net income (loss) (5) $ 469 $ (63,557 ) $ 10,621 $ 841,914 Net income (loss) per share: Basic $ — $ (0.17 ) $ 0.03 $ 2.27 Diluted $ — $ (0.17 ) $ 0.03 $ 2.25 2016 Total revenues (1) $ 453,174 $ 451,211 $ 526,199 $ 549,689 Gain (loss) on crude oil and natural gas derivatives, net (1) $ 42,112 $ (82,257 ) $ 15,668 $ (47,382 ) Property impairments (2) $ 78,927 $ 66,112 $ 57,689 $ 34,564 Gain on sale of assets, net (4) $ 109 $ 96,907 $ 6,158 $ 201,315 Income (loss) from operations $ (239,103 ) $ (110,547 ) $ (93,183 ) $ 155,299 Loss on extinguishment of debt (6) $ — $ — $ — $ 26,055 Net income (loss) $ (198,326 ) $ (119,402 ) $ (109,621 ) $ 27,670 Net income (loss) per share: Basic $ (0.54 ) $ (0.32 ) $ (0.30 ) $ 0.07 Diluted $ (0.54 ) $ (0.32 ) $ (0.30 ) $ 0.07 (1) Gains and losses on crude oil and natural gas derivative instruments are reflected in “Total revenues” on both the consolidated statements of comprehensive income (loss) and this table of unaudited quarterly financial data. Crude oil and natural gas derivative gains and losses have been shown separately to illustrate the fluctuations in revenues that are attributable to the Company’s derivative instruments. Commodity price fluctuations each quarter can result in significant swings in mark-to-market gains and losses, which affects comparability between periods. (2) Property impairments have been shown separately to illustrate the impact on quarterly results attributable to write downs of the Company’s assets. Commodity price fluctuations each quarter can result in significant changes in estimated future cash flows and resulting impairments, which affects comparability between periods. (3) Fourth quarter 2017 results include a $59.6 million pre-tax loss accrual recognized in conjunction with a litigation settlement as discussed in Note 10. Commitments and Contingencies , which resulted in an after-tax decrease in net income of $37.0 million ( $0.10 per basic and diluted share). (4) Gains on asset sales have been shown separately to illustrate the impact on quarterly results attributable to asset dispositions, which differ in significance from period to period and affect comparability. See Note 14. Property Dispositions for a discussion of notable dispositions. (5) Fourth quarter 2017 results reflect the remeasurement of the Company's deferred income tax assets and liabilities in response to the enactment of the Tax Reform Act in December 2017, which resulted in a one-time decrease in income tax expense and corresponding increase in net income of approximately $713.7 million ( $1.92 per basic share and $1.91 per diluted share). See Note 8. Income Taxes for further discussion. (6) See Note 7. Long-Term Debt for discussion of the loss recognized by the Company upon the redemption of its 2020 Notes and 2021 Notes in the 2016 fourth quarter.

Organization and Summary of S39

Organization and Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Thousands		3 Months Ended	12 Months Ended
		Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Organization And Summary Of Significant Accounting Policies [Line Items]
Tax benefit from US tax reform legislation			$ (713,655)	$ 0	$ 0
Accrued litigation settlement		$ 59,600	59,600	0
Cumulative Effect on Retained Earnings, Net of Tax			5,150
Allowance for Doubtful Accounts Receivable		2,200	2,200	3,000
Unamortized Debt Issuance Expense		55,000	55,000	50,400
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	[1]		$ (404)	(1,044)	(13,503)
Percentage of operations concentrated in geographical areas			59.00%
Percentage of estimated proved reserves in north region			50.00%
Percentage of crude oil and natural gas production concentrated in south region			41.00%
Percentage of estimated proved reserves in south region			50.00%
Percentage Of Crude Oil And Natural Gas Production Concentrated In Crude Oil			57.00%
Percentage Of Crude Oil and Natural Gas Revenue Concentrated in Crude Oil			78.00%
Cash deposits in excess of federally insured amounts		42,500	$ 42,500
Net asset retirement costs		40,300	40,300	34,000
Capitalized debt issue costs, relating to long-term debt		58,200	58,200	55,900
Accumulated amortization, relating to capitalized debt issue costs		65,900	65,900	56,800
Amortization expense related to capitalized debt issuance costs			$ 9,100	9,800	$ 8,900
Percentage Of Estimated Proved Reserves Concentrated In Crude Oil			48.00%
Deferred Tax Assets, Valuation Allowance		19,341	$ 19,341	18,936
Transportation Costs			201,500
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense			$ 3,900
Tax Deficiency from Compensation Expense, Per Share			$ 0.01
Estimated litigation liability, after tax		$ 37,000
Basic eps litigation settlement		$ 0.10
Diluted eps estimated litigation settlement		$ 0.10
Revolving Credit Facility [Member]
Organization And Summary Of Significant Accounting Policies [Line Items]
Unamortized Debt Issuance Expense		$ 3,200	$ 3,200	$ 5,500
Customer one concentration [Member] | Oil And Natural Gas [Member]
Organization And Summary Of Significant Accounting Policies [Line Items]
Percentage of crude oil sales to one single purchaser accounted on total revenues			11.00%
Customer two concentration [Member] | Oil And Natural Gas [Member]
Organization And Summary Of Significant Accounting Policies [Line Items]
Percentage of crude oil sales to one single purchaser accounted on total revenues			11.00%
North Region [Member]
Organization And Summary Of Significant Accounting Policies [Line Items]
Percentage Of Revenues Concentrated In Geographical Areas			69.00%
South Region [Member]
Organization And Summary Of Significant Accounting Policies [Line Items]
Percentage Of Revenues Concentrated In Geographical Areas			31.00%
[1]	Represents valuation allowances recognized against all deferred tax assets associated with operating loss carryforwards generated by the Company's Canadian operations during the respective periods for which the Company does not expect to realize a benefit.

Organization and Summary of S40

Organization and Summary of Significant Accounting Policies - Components of Inventories (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Tubular goods and equipment	$ 14,946	$ 15,243
Crude oil	82,460	96,744
Total	$ 97,406	$ 111,987

Organization and Summary of S41

Organization and Summary of Significant Accounting Policies - Schedule of Estimated Useful Lives of Service Property and Equipment (Detail)	12 Months Ended
	Dec. 31, 2017
Minimum [Member] | Automobiles and Aircraft [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	5 years
Minimum [Member] | Gathering Systems [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	15 years
Minimum [Member] | Storage Tanks [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	10 years
Minimum [Member] | Machinery and Equipment [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	6 years
Minimum [Member] | Office Equipment, Computer Equipment and Software [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	3 years
Minimum [Member] | Buildings And Improvements [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	4 years
Maximum [Member] | Automobiles and Aircraft [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	10 years
Maximum [Member] | Gathering Systems [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	30 years
Maximum [Member] | Storage Tanks [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	30 years
Maximum [Member] | Machinery and Equipment [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	10 years
Maximum [Member] | Office Equipment, Computer Equipment and Software [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	25 years
Maximum [Member] | Buildings And Improvements [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	40 years

Organization and Summary of S42

Organization and Summary of Significant Accounting Policies - Summary Of Changes In Future Abandonment Liabilities (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations at January 1		$ 96,178	$ 102,909	$ 76,708
Accretion expense		5,886	6,086	4,740
Revisions	[1]	7,801	(12,755)	15,068
Plus: Additions for new assets		6,884	2,692	7,404
Less: Plugging costs and sold assets		(2,343)	(2,754)	(1,011)
Total asset retirement obligations at December 31		114,406	96,178	102,909
Less: Current portion of asset retirement obligations at December 31	[2]	2,612	1,742	1,658
Non-current portion of asset retirement obligations at December 31		$ 111,794	$ 94,436	$ 101,251
[1]	Revisions primarily represent changes in the present value of liabilities resulting from changes in estimated costs and economic lives of producing properties.
[2]	Balance is included in the caption “Accrued liabilities and other” in the consolidated balance sheets.

Organization and Summary of S43

Organization and Summary of Significant Accounting Policies - Earnings Per Share (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended									12 Months Ended
	Dec. 31, 2017		Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basic EPS impact from tax benefit from US tax reform										$ 1.92
Diluted EPS impact from tax benefit from US tax reform										$ 1.91
Weighted average number diluted shares excluded from calculation										2,303,000	1,567,000
Income (numerator):
Net income - basic and diluted	$ 841,914	[1]	$ 10,621	$ (63,557)	$ 469	$ 27,670	$ (109,621)	$ (119,402)	$ (198,326)	$ 789,447	$ (399,679)		$ (353,668)
Weighted average shares - basic										371,066,000	370,380,000		369,540,000
Non-vested restricted stock										2,702,000	0	[2]	0	[2]
Weighted average shares - diluted										373,768,000	370,380,000		369,540,000
Net income per share:
Basic (in dollars per share)	$ 2.27		$ 0.03	$ (0.17)	$ 0	$ 0.07	$ (0.30)	$ (0.32)	$ (0.54)	$ 2.13	$ (1.08)		$ (0.96)
Diluted (in dollars per share)	$ 2.25		$ 0.03	$ (0.17)	$ 0	$ 0.07	$ (0.30)	$ (0.32)	$ (0.54)	$ 2.11	$ (1.08)		$ (0.96)
[1]	Fourth quarter 2017 results reflect the remeasurement of the Company's deferred income tax assets and liabilities in response to the enactment of the Tax Reform Act in December 2017, which resulted in a one-time decrease in income tax expense and corresponding increase in net income of approximately $713.7 million ($1.92 per basic share and $1.91 per diluted share). See Note 8. Income Taxes for further discussion.
[2]	For the years ended December 31, 2016 and 2015, the Company had a net loss and therefore the potential dilutive effect of approximately 2,303,000 and 1,567,000 weighted average non-vested restricted shares, respectively, were not included in the calculation of diluted net loss per share because to do so would have been anti-dilutive to the computations.

Supplemental Cash Flow Inform44

Supplemental Cash Flow Information - Summary of Supplemental Cash Flow Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Supplemental Cash Flow Information [Abstract]
Capital Expenditures Incurred but Not yet Paid	$ 302,800	$ 223,600
Supplemental cash flow information:
Cash paid for interest	281,058	316,116	$ 301,743
Cash paid for income taxes	2	2	30
Cash received for income tax refunds	257	174	61,403
Asset Retirement Obligation, Additions or Revisions	$ 14,685	$ (10,063)	$ 22,472

Net Property and Equipment - Sc

Net Property and Equipment - Schedule of Net Property and Equipment (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment, Net [Abstract]
Proved crude oil and natural gas properties	$ 21,362,199	$ 19,802,395
Unproved crude oil and natural gas properties	365,413	429,562
Service properties, equipment and other	290,111	301,788
Total property and equipment	22,017,723	20,533,745
Accumulated depreciation, depletion and amortization	(9,083,934)	(7,652,518)
Net property and equipment	$ 12,933,789	$ 12,881,227

Accrued Liabilities and Other -

Accrued Liabilities and Other - Schedule of Accrued Liabilities and Other (Detail) - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accrued Liabilities and Other Liabilities [Abstract]
Prepaid advances from joint interest owners		$ 34,511	$ 57,861
Accrued compensation		65,308	38,046
Accrued production taxes, ad valorem taxes and other non-income taxes		40,611	22,053
Accrued interest		55,282	52,657
Accrued litigation settlement		59,600	0
Current portion of asset retirement obligations	[1]	2,612	1,742	$ 1,658
Other		2,150	4,411
Accrued liabilities and other		$ 260,074	$ 176,770
[1]	Balance is included in the caption “Accrued liabilities and other” in the consolidated balance sheets.

Derivative Instruments - Summar

Derivative Instruments - Summary of Outstanding Contracts with Respect to Natural Gas (Detail) - January 2018 to March 2018 Swaps [Member] - Natural Gas [Member]	12 Months Ended
	Dec. 31, 2017MMBTU$ / MMBTU
Derivative [Line Items]
Natural Gas Production Derivative Volume, MMBtus | MMBTU	6,300,000
Swaps Weighted Average Price | $ / MMBTU	3.28

Derivative Instruments - Realiz

Derivative Instruments - Realized and Unrealized Gains and Losses on Derivative Instruments (Detail) - USD ($) $ in Thousands	3 Months Ended																12 Months Ended
	Dec. 31, 2017	[1]	Sep. 30, 2017	[1]	Jun. 30, 2017	[1]	Mar. 31, 2017	[1]	Dec. 31, 2016	[1]	Sep. 30, 2016	[1]	Jun. 30, 2016	[1]	Mar. 31, 2016	[1]	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net																	$ 58,031	$ (156,621)	$ 21,532
Gain (loss) on crude oil and natural gas derivatives, net	$ 8,165		$ 8,602		$ 28,022		$ 46,858		$ (47,382)		$ 15,668		$ (82,257)		$ 42,112		91,647	(71,859)	91,085
Fuel [Member]
Cash received (paid) on derivatives:
Cash received on derivatives, net																	2,845	699
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net																	(4,060)	4,060
Gain (loss) on crude oil and natural gas derivatives, net																	(1,215)	4,759
Fixed Price Swaps [Member] | Natural Gas [Member]
Cash received (paid) on derivatives:
Cash received on derivatives, net																	40,095	88,823	39,670
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net																	18,960	(120,784)	41,828
Collars [Member] | Natural Gas [Member]
Cash received (paid) on derivatives:
Cash received on derivatives, net																	(10,539)	0	29,883
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net																	43,131	(39,936)	(25,011)
Call Option [Member] | Crude Oil [Member]
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net																	0	38	4,715
Crude Oil and Natural Gas
Cash received (paid) on derivatives:
Cash received on derivatives, net																	29,556	88,823	69,553
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net																	62,091	(160,682)	21,532
Gain (loss) on crude oil and natural gas derivatives, net																	$ 91,647	$ (71,859)	$ 91,085
[1]	Gains and losses on crude oil and natural gas derivative instruments are reflected in “Total revenues” on both the consolidated statements of comprehensive income (loss) and this table of unaudited quarterly financial data. Crude oil and natural gas derivative gains and losses have been shown separately to illustrate the fluctuations in revenues that are attributable to the Company’s derivative instruments. Commodity price fluctuations each quarter can result in significant swings in mark-to-market gains and losses, which affects comparability between periods.

Derivative Instruments Derivati

Derivative Instruments Derivative Instruments - Gross Amounts of Recognized Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
Commodity derivative assets, Gross amounts of recognized assets	$ 2,603	$ 4,061
Commodity derivative assets, Gross amounts offset on balance sheet	0	0
Derivative assets, Net amounts of assets on balance sheet	2,603	4,061
Commodity derivative liability, Gross amounts of recognized liabilities	0	(59,489)
Commodity derivative liability, Gross amounts offset on balance sheet	0	0
Derivative liability, Net amounts of liabilities on balance sheet	$ 0	$ (59,489)

Derivative Instruments Deriva50

Derivative Instruments Derivative Instruments - Reconciles Net Amounts Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative assets	$ 2,603	$ 4,061
Noncurrent derivative assets	0	0
Derivative assets, Net amounts of assets on balance sheet	2,603	4,061
Derivative liabilities	0	(59,489)
Noncurrent derivative liabilities	0	0
Derivative liability, Net amounts of liabilities on balance sheet	0	(59,489)
Total derivative assets (liabilities), net	$ 2,603	$ (55,428)

Fair Value Measurements - Valua

Fair Value Measurements - Valuation of Financial Instruments by Pricing Levels (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Derivative assets (liabilities):
Derivative assets (liabilities)	$ 2,603	$ (55,428)
Swap [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	2,603	(12,297)
Collars [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)		(43,131)
Fair Value, Inputs, Level 1 [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0	0
Fair Value, Inputs, Level 1 [Member] | Fixed Price Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0	0
Fair Value, Inputs, Level 1 [Member] | Collars [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)		0
Fair Value, Inputs, Level 2 [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	2,603	(55,428)
Fair Value, Inputs, Level 2 [Member] | Fixed Price Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	2,603	(12,297)
Fair Value, Inputs, Level 2 [Member] | Collars [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)		(43,131)
Fair Value, Inputs, Level 3 [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0	0
Fair Value, Inputs, Level 3 [Member] | Fixed Price Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	$ 0	0
Fair Value, Inputs, Level 3 [Member] | Collars [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)		$ 0

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jun. 30, 2017
Fair Value Measurements [Line Items]
Operating cost escalation assumption used in impairment assessment	3.00%
Discount factor utilized as standardized measure for future net cash flows	10.00%
Impairments of proved properties	$ 82,340	$ 2,895	$ 138,878
Estimated fair value of proved properties				$ 72,000
Minimum [Member]
Fair Value Measurements [Line Items]
Productive life of field (in years)	1 year
Maximum [Member]
Fair Value Measurements [Line Items]
Productive life of field (in years)	38 years
Forward Commodity Prices [Member]
Fair Value Measurements [Line Items]
Forward commodity price escalation assumption used in impairment assessment	3.00%

Fair Value Measurements - Prope

Fair Value Measurements - Property Impairments (Detail) - USD ($) $ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2017

[1]

Sep. 30, 2017

[1]

Jun. 30, 2017

Mar. 31, 2017

[1]

Dec. 31, 2016

[1]

Sep. 30, 2016

[1]

Jun. 30, 2016

[1]

Mar. 31, 2016

[1]

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Proved property impairments

$ 82,340

$ 2,895

$ 138,878

Unproved property impairments

155,030

234,397

263,253

Total

$ 27,552

$ 35,130

$ 123,316

[1]

$ 51,372

$ 34,564

$ 57,689

$ 66,112

$ 78,927

237,370

$ 237,292

$ 402,131

Estimated fair value of proved properties

$ 72,000

Arkoma Woodford [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Proved property impairments

81,200

Non-core [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Proved property impairments

$ 1,100

[1]

Property impairments have been shown separately to illustrate the impact on quarterly results attributable to write downs of the Company’s assets. Commodity price fluctuations each quarter can result in significant changes in estimated future cash flows and resulting impairments, which affects comparability between periods.

Fair Value Measurements - Fair

Fair Value Measurements - Fair Values of Financial Instruments not Recorded at Fair Value (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Fair Value Measurements [Line Items]
Term Loan		$ 500,000
5% Senior Notes due 2022 [Member]
Fair Value Measurements [Line Items]
Debt instrument, maturity date	2,022
Debt instrument, stated interest rate	5.00%
4 1/2% Senior Notes due 2023 [Member]
Fair Value Measurements [Line Items]
Debt instrument, maturity date	2,023
Debt instrument, stated interest rate	4.50%
3.8% Senior Notes due 2024 [Member]
Fair Value Measurements [Line Items]
Debt instrument, maturity date	2,024
Debt instrument, stated interest rate	3.80%
Senior notes		990,964
4.375% Senior Notes Due 2028
Fair Value Measurements [Line Items]
Debt instrument, maturity date	2,028
Debt instrument, stated interest rate	4.375%
Senior notes		0
4.9% Senior Notes due 2044 [Member]
Fair Value Measurements [Line Items]
Debt instrument, maturity date	2,044
Debt instrument, stated interest rate	4.90%
Senior notes		691,199
Carrying Amount [Member]
Fair Value Measurements [Line Items]
Revolving credit facility	$ 188,000	905,000
Term Loan	0	498,865
Note payable	9,974	12,176
Total debt	6,353,691	6,579,916
Carrying Amount [Member] | 5% Senior Notes due 2022 [Member]
Fair Value Measurements [Line Items]
Senior notes	1,997,576	1,997,188
Carrying Amount [Member] | 4 1/2% Senior Notes due 2023 [Member]
Fair Value Measurements [Line Items]
Senior notes	1,486,690	1,484,524
Carrying Amount [Member] | 3.8% Senior Notes due 2024 [Member]
Fair Value Measurements [Line Items]
Senior notes	992,036	990,964
Carrying Amount [Member] | 4.375% Senior Notes Due 2028
Fair Value Measurements [Line Items]
Senior notes	988,061	0
Carrying Amount [Member] | 4.9% Senior Notes due 2044 [Member]
Fair Value Measurements [Line Items]
Senior notes	691,354	691,199
Fair Value [Member]
Fair Value Measurements [Line Items]
Revolving credit facility	188,000	905,000
Term loan	0	500,000
Note payable	9,900	10,200
Total debt	6,420,600	6,447,400
Fair Value [Member] | 5% Senior Notes due 2022 [Member]
Fair Value Measurements [Line Items]
Senior notes	2,040,000	2,020,400
Fair Value [Member] | 4 1/2% Senior Notes due 2023 [Member]
Fair Value Measurements [Line Items]
Senior notes	1,526,800	1,474,800
Fair Value [Member] | 3.8% Senior Notes due 2024 [Member]
Fair Value Measurements [Line Items]
Senior notes	988,800	929,400
Fair Value [Member] | 4.375% Senior Notes Due 2028
Fair Value Measurements [Line Items]
Senior notes	987,200	0
Fair Value [Member] | 4.9% Senior Notes due 2044 [Member]
Fair Value Measurements [Line Items]
Senior notes	$ 679,900	$ 607,600

Long-Term Debt - Long-Term Debt

Long-Term Debt - Long-Term Debt (Detail) - USD ($) $ in Thousands	3 Months Ended					12 Months Ended
	Dec. 31, 2016		Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Nov. 10, 2016
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net	$ 37,300					$ 44,300	$ 37,300
Total Redemption Amount									$ 623,900
Less: Current portion of long-term debt	(2,219)					(2,286)	(2,219)
Long-term debt, net of current portion	6,577,697					6,351,405	6,577,697
Loss on extinguishment of debt	(26,055)	[1]	$ 0	$ 0	$ 0	$ (554)	(26,055)	$ 0
Term Loan	500,000						500,000
5% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate						5.00%
4.5% Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate						4.50%
3.8% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Senior notes	990,964						990,964
Debt instrument, stated interest rate						3.80%
4.375% Senior Notes Due 2028
Debt Instrument [Line Items]
Senior notes	0						0
Debt instrument, stated interest rate						4.375%
4.9% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Senior notes	691,199						691,199
Debt instrument, stated interest rate						4.90%
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity						$ 2,560,000
Carrying Amount [Member]
Debt Instrument [Line Items]
Revolving credit facility	905,000					188,000	905,000
Note payable	12,176					9,974	12,176
Total debt	6,579,916					6,353,691	6,579,916
Term Loan	498,865					0	498,865
Carrying Amount [Member] | 5% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Senior notes	1,997,188					1,997,576	1,997,188
Carrying Amount [Member] | 4.5% Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Senior notes	1,484,524					1,486,690	1,484,524
Carrying Amount [Member] | 3.8% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Senior notes	990,964					992,036	990,964
Carrying Amount [Member] | 4.375% Senior Notes Due 2028
Debt Instrument [Line Items]
Senior notes	0					988,061	0
Carrying Amount [Member] | 4.9% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Senior notes	$ 691,199					$ 691,354	$ 691,199
[1]	See Note 7. Long-Term Debt for discussion of the loss recognized by the Company upon the redemption of its 2020 Notes and 2021 Notes in the 2016 fourth quarter

Long-Term Debt - Additional Inf

Long-Term Debt - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended					12 Months Ended
	Dec. 31, 2016		Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Nov. 10, 2016
Debt Instrument [Line Items]
Proceeds from sale of assets	$ 214,800					$ 144,353	$ 631,549	$ 34,008
Loss on extinguishment of debt	(26,055)	[1]	$ 0	$ 0	$ 0	(554)	(26,055)	0
Total Redemption Amount									$ 623,900
Aggregate amount of lender commitments on credit facility						$ 2,750,000
Line of credit facility, commitment fee percentage, per annum						0.30%
Line of Credit Facility, Covenant Terms						0.65
Proceeds from issuance of Senior Notes						$ 990,000	0	0
Repayments of Lines of Credit						2,019,000	1,639,000	$ 1,313,000
Current portion of long-term debt	$ 2,219					2,286	2,219
Repayment of Term Loan						500,000
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity						2,560,000
Senior Notes due 2028 [Domain]
Debt Instrument [Line Items]
Debt Instrument, Face Amount						1,000,000
Proceeds from issuance of Senior Notes						$ 990,000
Debt instrument, maturity date						Jan. 15, 2028
2020 Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	102.458%
Debt Instrument, Face Amount									200,000
2021 Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	103.563%
Debt Instrument, Face Amount									$ 400,000
Credit Facility [Domain]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate						3.19%
Note Payable [Member]
Debt Instrument [Line Items]
Notes Payable						$ 22,000
Loan period, in years						10 years
Debt instrument, stated interest rate						3.14%
Debt instrument, maturity date						Feb. 26, 2022
5% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate						5.00%
Senior Notes Due 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount						$ 1,500,000
Debt instrument, maturity date						Apr. 15, 2023
4.5% Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate						4.50%
3.8% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Senior notes	$ 990,964						990,964
Debt instrument, stated interest rate						3.80%
4.375% Senior Notes Due 2028
Debt Instrument [Line Items]
Senior notes	0						0
Debt instrument, stated interest rate						4.375%
4.9% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Senior notes	691,199						691,199
Debt instrument, stated interest rate						4.90%
Carrying Amount [Member]
Debt Instrument [Line Items]
Line of credit facility, amount outstanding	905,000					$ 188,000	905,000
Notes Payable	12,176					9,974	12,176
Carrying Amount [Member] | 5% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Senior notes	1,997,188					1,997,576	1,997,188
Carrying Amount [Member] | 4.5% Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Senior notes	1,484,524					1,486,690	1,484,524
Carrying Amount [Member] | 3.8% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Senior notes	990,964					992,036	990,964
Carrying Amount [Member] | 4.375% Senior Notes Due 2028
Debt Instrument [Line Items]
Senior notes	0					988,061	0
Carrying Amount [Member] | 4.9% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Senior notes	$ 691,199					$ 691,354	$ 691,199
[1]	See Note 7. Long-Term Debt for discussion of the loss recognized by the Company upon the redemption of its 2020 Notes and 2021 Notes in the 2016 fourth quarter

Long-Term Debt - Summary of Mat

Long-Term Debt - Summary of Maturity Dates, Semi-Annual Interest Payment Dates, and Optional Redemption Periods Of Outstanding Senior Note Obligations (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Nov. 10, 2016
2021 Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount			$ 400,000
Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount		$ 2,000,000
Maturity date		Sep. 15, 2022
Interest Payment Dates		March 15,  Sep 15
Senior Notes Due 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount		$ 1,500,000
Maturity date		Apr. 15, 2023
Interest Payment Dates		April 15, Oct 15
Make-whole redemption period	[1]	Jan. 15, 2023
Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount		$ 1,000,000
Maturity date		Jun. 1, 2024
Interest Payment Dates		June 1, Dec 1
Make-whole redemption period	[1]	Mar. 1, 2024
Senior Notes due 2028 [Domain]
Debt Instrument [Line Items]
Debt Instrument, Face Amount		$ 1,000,000
Maturity date		Jan. 15, 2028
Interest Payment Dates		Jan 15, July 15
Make-whole redemption period	[1]	Oct. 15, 2027
2020 Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount			$ 200,000
Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount		$ 700,000
Maturity date		Jun. 1, 2044
Interest Payment Dates		June 1, Dec 1
Make-whole redemption period	[1]	Dec. 1, 2043
[1]	At any time prior to the indicated dates, the Company has the option to redeem all or a portion of its senior notes of the applicable series at the “make-whole” redemption prices or amounts specified in the respective senior note indentures plus any accrued and unpaid interest to the date of redemption. On or after these dates, the Company may redeem all or a portion of its senior notes at a redemption price equal to 100% of the principal amount of the senior notes being redeemed plus any accrued and unpaid interest to the date of redemption.

Income Taxes - Provision for In

Income Taxes - Provision for Income Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Current federal income tax (provision) benefit	$ 7,781	$ 22,941	$ 0
Current tax (provision), various states	0	(2)	(24)
Total current income tax (provision) benefit	7,781	22,939	(24)
Deferred federal income tax (provision) benefit	(81,054)	182,422	140,578
Tax benefit from US tax reform legislation	713,655	0	0
Deferred tax (provision) benefit, various states	(7,002)	27,414	40,863
Total deferred income tax benefit	625,599	209,836	181,441
Benefit for income taxes	$ 633,380	$ 232,775	$ 181,417

Income Taxes - Schedule of Prov

Income Taxes - Schedule of Provision for Income Taxes with Income Tax at Federal Statutory Rate (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017		Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Expected income tax (provision) benefit based on US statutory tax rate of 35%		$ (54,623)		$ 221,359	$ 187,280
State income taxes, net of federal benefit		(4,682)		18,829	16,219
Tax benefit from US tax reform legislation		713,655		0	0
Tax deficiency from stock-based compensation		(3,932)	[1]	0	0
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Share-based Compensation Cost, Amount		(13,813)		(3,471)	(1,488)
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	[2]	(404)		(1,044)	(13,503)
Effect of differing statutory tax rate in Canada		(194)		(481)	(5,239)
Other, net		(2,627)		(2,417)	(1,852)
Benefit for income taxes		$ 633,380		$ 232,775	$ 181,417
Federal statutory income tax rate		35.00%
[1]	The Company recognized $3.9 million of tax deficiencies from stock-based compensation as income tax expense for the year ended December 31, 2017 in accordance with ASU 2016-09 as discussed in Note 1. Organization and Summary of Significant Accounting Policies–Adoption of new accounting pronouncements.
[2]	Represents valuation allowances recognized against all deferred tax assets associated with operating loss carryforwards generated by the Company's Canadian operations during the respective periods for which the Company does not expect to realize a benefit.

Income Taxes - Components of De

Income Taxes - Components of Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Deferred tax assets, Net operating loss carryforwards	$ 604,423	$ 478,975
Deferred tax assets, Canadian net operating loss carryforwards	19,341	18,936
Deferred tax assets, Alternative minimum tax carryforwards	7,781	16,663
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Share-based Compensation Cost	12,962	32,924
Deferred Tax Assets Non-cash Losses On Derivatives	0	21,064
Deferred Tax Assets, Other	21,885	11,466
Total deferred tax assets	666,392	580,028
Deferred Tax Assets, Valuation Allowance	(19,341)	(18,936)
Deferred Tax Assets, Net	647,051	561,092
Deferred tax liabilities, Property and equipment	(1,903,451)	(2,448,450)
Deferred Tax Liabilities, Other	(3,158)	(2,947)
Total deferred tax liabilities	(1,906,609)	(2,451,397)
Net deferred tax liabilities	$ (1,259,558)	$ (1,890,305)

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards, State		$ 3,400,000
Alternative minimum tax credit carryforward		7,780
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	[1]	(404)	$ (1,044)	$ (13,503)
Deferred Tax Assets, Valuation Allowance		19,341	$ 18,936
UNITED STATES
Operating Loss Carryforwards [Line Items]
Federal Operating Loss Carryforwards		2,390,000
OKLAHOMA
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards, State		2,170,000
NORTH DAKOTA
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards, State		$ 1,070,000
[1]	Represents valuation allowances recognized against all deferred tax assets associated with operating loss carryforwards generated by the Company's Canadian operations during the respective periods for which the Company does not expect to realize a benefit.

Lease Commitments - Lease Commi

Lease Commitments - Lease Commitments (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Leases [Abstract]
Lease expenses associated with operating leases	$ 1,900	$ 4,400	$ 9,600
2,018	1,656
2,019	958
2,020	817
2,021	645
2,022	620
Thereafter	7,208
Total obligations	$ 11,904

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Long-term Purchase Commitment [Line Items]
Total future drilling commitments at balance sheet date	$ 104
Drilling commitments 2018	73
Drilling commitments 2019	30
Drilling commitments 2020	$ 1
Future Drilling Commitments End Date	2020-02
Pipeline Transportation and Processing Commitments [Member]
Long-term Purchase Commitment [Line Items]
Future commitment, end date	2,028
Future commitment, total	$ 1,430
Future commitment, due in 2018	197
Future commitment, due in 2019	216
Future commitment, due in 2020	186
Future commitment, due in 2021	168
Future commitment, due in 2022	166
Future commitments, thereafter	$ 497

Commitments and Contingencies L

Commitments and Contingencies Loss Contingencies (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Loss Contingencies [Line Items]
Accrued litigation settlement	$ 59,600	$ 0
Legal proceedings recorded as a liability under other noncurrent liabilities	7,600	$ 6,500
Strack royalty payment litigation [Member]
Loss Contingencies [Line Items]
Damages sought related to contingency matter	200,000
Accrued litigation settlement	$ 59,600

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Revenues from transactions with related party	$ 0	$ 0	$ 1,400,000
Production expenses to affiliates	0	0	1,654,000
Total amount paid to related party		100,000	7,700,000
Amount charged to affiliate for aircraft use	19,400	9,500	9,600
Amount charged to company by affiliate for aircraft use	460,000	292,000	236,000
Affiliated Entity [Member]
Related Party Transaction [Line Items]
Expenses from transactions with related party			8,800,000
Capitalized costs		100,000	2,600,000
Production expenses to affiliates			1,700,000
Total amount paid to related party			9,200,000
Officers And Other Key Employees [Member]
Related Party Transaction [Line Items]
Revenues from transactions with related party	300,000	300,000	500,000
Due to affiliates	48,000	45,000
Revenues paid to related party	500,000	400,000	700,000
Due from affiliates	58,000	90,000
Other Affiliates [Member]
Related Party Transaction [Line Items]
Total amount paid to related party	368,000	195,000	221,000
Due to affiliates	92,000	97,000
Due from affiliates	4,200	3,400
Total amount received from related party	$ 18,600	$ 6,800	33,000
Affiliated Entity [Member]
Related Party Transaction [Line Items]
Revenues from transactions with related party			$ 1,400,000

Stock Based Compensation - Asso

Stock Based Compensation - Associated Compensation Expense (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-based compensation	$ 45,868	$ 48,098	$ 51,834

Stock-Based Compensation - Addi

Stock-Based Compensation - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Restricted stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value at vesting date	$ 39.8	$ 30	$ 23.6
Unrecognized compensation expense related to non-vested	$ 58
Unrecognized compensation expense related to non-vested, period for recognition, in years	1 year 2 months
Restricted stock [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grants vest over periods, in years	1 year
Restricted stock [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grants vest over periods, in years	3 years
2013 Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock available for issue	19,680,072
2013 Plan [Member] | Restricted stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock available to grant	14,538,540

Stock Based Compensation - Summ

Stock Based Compensation - Summary of Changes in Non Vested Shares of Restricted Stock (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Non-vested shares, beginning balance	3,913,634	3,249,611	2,678,764
Granted shares	1,585,870	2,064,508	1,462,534
Vested shares	(874,665)	(1,207,235)	(555,517)
Forfeited shares	(598,729)	(193,250)	(336,170)
Non-vested shares, ending balance	4,026,110	3,913,634	3,249,611
Non-vested, weighted average grant-date fair value, beginning of period	$ 37.12	$ 48.20	$ 49.40
Granted, weighted average grant-date fair value	44.58	22.36	46.65
Vested, weighted average grant-date fair value	57.36	41.27	48.07
Forfeited, weighted average grant-date fair value	37.34	39.79	51.23
Non-vested, weighted average grant-date fair value, end of period	$ 35.63	$ 37.12	$ 48.20

Accumulated Other Comprehensi69

Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Foreign Currency [Abstract]
Foreign currency translation adjustments		$ 567	$ 3,094	$ (2,969)
Translation Adjustment Functional to Reporting Currency, Tax Benefit (Expense)	[1]	0	0	0
Other Comprehensive Income (Loss), Net of Tax		567	3,094	(2,969)
Accumulated other comprehensive loss		$ 307	$ (260)	$ (3,354)	$ (385)
[1]	A valuation allowance has been recognized against all deferred tax assets associated with losses generated by the Company’s Canadian operations, thereby resulting in no income taxes on other comprehensive income (loss).

Property Dispositions - Additio

Property Dispositions - Additional Information (Detail) $ in Thousands	1 Months Ended		3 Months Ended					12 Months Ended
	Oct. 31, 2017USD ($)	Sep. 30, 2017USD ($)a	Dec. 31, 2017USD ($)	Sep. 30, 2017USD ($)aBoe	Dec. 31, 2016USD ($)	Sep. 30, 2016aBoe	Jun. 30, 2016USD ($)a	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)Boe	Dec. 31, 2015USD ($)	Oct. 14, 2016a
Property Acquisition And Dispositions [Line Items]
Proceeds from sale of assets					$ 214,800			$ 144,353	$ 631,549	$ 34,008
Proceeds from sale of non-producing leasehold					295,600		$ 110,000			25,900
Gain (Loss) on disposition of non-producing leasehold					$ 201,000		$ 96,900			$ 20,500
Arkoma Woodford [Member]
Property Acquisition And Dispositions [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment								65,300
Land Subject to Ground Leases | a		26,000		26,000
Production, Barrels of Oil Equivalents | Boe				1,700
Gain (Loss) on disposition of non-producing leasehold								(3,500)
STACK [Domain]
Property Acquisition And Dispositions [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	$ 59,900	$ 3,600						63,500
Gain (Loss) on disposition of non-producing leasehold			$ 53,600	$ 3,300
OKLAHOMA
Property Acquisition And Dispositions [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment								7,200
Gain (Loss) on disposition of oil loading facilities								$ 4,200
SCOOP [Member]
Property Acquisition And Dispositions [Line Items]
Land Subject to Ground Leases | a											30,000
Production, Barrels of Oil Equivalents | Boe									700
WYOMING
Property Acquisition And Dispositions [Line Items]
Land Subject to Ground Leases | a							132,000
NORTH DAKOTA
Property Acquisition And Dispositions [Line Items]
Land Subject to Ground Leases | a						68,000
MONTANA
Property Acquisition And Dispositions [Line Items]
Land Subject to Ground Leases | a						12,000
BAKKEN [Domain]
Property Acquisition And Dispositions [Line Items]
Production, Barrels of Oil Equivalents | Boe						2,700

Crude Oil and Natural Gas Pro71

Crude Oil and Natural Gas Property Information - Schedule of Results of Operations from Crude Oil and Natural Gas Producing Activities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017		Dec. 31, 2016	Dec. 31, 2015
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Crude oil and natural gas sales	$ 2,982,966		$ 2,026,958	$ 2,552,531
Production expenses	(324,214)		(289,289)	(348,897)
Production taxes	(208,278)		(142,388)	(200,637)
Exploration Expense	(12,393)		(16,972)	(19,413)
Depreciation, depletion, amortization and accretion	(1,652,180)		(1,679,485)	(1,722,336)
Property impairments	(237,370)		(237,292)	(402,131)
Income tax benefit (1)	504,475	[1]	126,794	33,680
Results from crude oil and natural gas producing activities	$ 1,053,006		$ (211,674)	$ (107,203)
[1]	Income taxes reflect the application of a combined federal and state tax rate of 38% on pre-tax income and losses generated by operations in the United States. Additionally, the 2017 period includes a $713.7 million income tax benefit recognized upon the Company’s remeasurement of its deferred income tax assets and liabilities in response to the enactment of the Tax Reform Act in December 2017. See Note 8. Income Taxes for further discussion.

Crude Oil and Natural Gas Pro72

Crude Oil and Natural Gas Property Information - Schedule of Costs Incurred in Oil and Gas Property Acquisition Exploration and Development Activities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Property Acquisition Costs - Proved	$ 8,446	$ 5,008	$ 557
Property Acquisition Costs - Unproved	220,875	149,962	168,492
Total property acquisition costs	229,321	154,970	169,049
Exploration Costs	123,461	182,355	241,523
Development Costs	1,695,954	767,148	2,148,530
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities	$ 2,048,736	$ 1,104,473	$ 2,559,102

Crude Oil and Natural Gas Pro73

Crude Oil and Natural Gas Property Information - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Development costs included in asset retirement costs	$ 15.3	$ (9.6)	$ 22.8

Crude Oil and Natural Gas Pro74

Crude Oil and Natural Gas Property Information - Schedule of Aggregate Capitalized Costs Relates to Crude Oil and Natural Gas Producing Activities (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Proved crude oil and natural gas properties	$ 21,362,199	$ 19,802,395
Unproved crude oil and natural gas properties	365,413	429,562
Total	21,727,612	20,231,957
Less accumulated depreciation, depletion and amortization	(8,971,935)	(7,553,255)
Net capitalized costs	$ 12,755,677	$ 12,678,702

Crude Oil and Natural Gas Pro75

Crude Oil and Natural Gas Property Information - Schedule of Capitalized Exploratory Drilling Costs Pending Evaluation (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)Well	Dec. 31, 2016USD ($)Well	Dec. 31, 2015USD ($)Well
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Balance at January 1	$ 34,852	$ 59,397	$ 93,421
Additions to capitalized exploratory well costs pending determination of proved reserves	79,451	123,980	132,806
Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves	(81,035)	(141,941)	(160,779)
Capitalized exploratory well costs charged to expense	(1,912)	(6,584)	(6,051)
Balance at December 31	$ 31,356	$ 34,852	$ 59,397
Number of wells | Well	37	54	73

Supplemental Crude Oil and Na76

Supplemental Crude Oil and Natural Gas Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2017MBoe	Dec. 31, 2017MMcf	Dec. 31, 2017MBbls	Dec. 31, 2017$ / Barrels	Dec. 31, 2016$ / bbl$ / McfMBoeMMcfMBbls	Dec. 31, 2015$ / bbl$ / McfMBoeMMcfMBbls
Reserve Quantities [Line Items]
Extensions, discoveries, and other additions		240,206				249,430	253,173
Discount factor utilized as standardized measure for future net cash flows	10.00%
Crude Oil [Member]
Reserve Quantities [Line Items]
Weighted average price utilized in computation of future cash inflows					47.03	35.57	41.63
Crude Oil [Member]
Reserve Quantities [Line Items]
Percentage change in average SEC price	20.00%
Revisions of previous estimates | MBbls				(77,779)		(99,966)	(246,840)
Extensions, discoveries and other additions | MBbls				129,895		97,587	134,764
Natural Gas [Member]
Reserve Quantities [Line Items]
Percentage change in average SEC price	20.00%
Revisions of previous estimates | MMcf			(25,390)			(63,057)	(302,143)
Extensions, discoveries and other additions | MMcf			661,867			911,062	710,453
Weighted average price utilized in computation of future cash inflows					3	2.14	2.35
Proved Undeveloped Reserves [Domain]
Reserve Quantities [Line Items]
Revisions of previous estimates		89
Proved Undeveloped Reserves [Domain] | Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MMcf			290
Proved Undeveloped Reserves [Domain] | Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls				41
Bakken [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions			253,000	106,000
Extensions, discoveries, and other additions		148,000
SCOOP [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates		53,000
Extensions, discoveries and other additions			224,000	16,000
STACK [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates		39,000
Extensions, discoveries and other additions			185,000	8,000
Production Type [Domain] | Proved Reserves [Domain]
Reserve Quantities [Line Items]
Revisions of previous estimates		30
Production Type [Domain] | Proved Reserves [Domain] | Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MMcf			173
Production Type [Domain] | Proved Reserves [Domain] | Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls				59
Price Driven [Domain] | Proved Reserves [Domain]
Reserve Quantities [Line Items]
Revisions of previous estimates		42
Price Driven [Domain] | Proved Reserves [Domain] | Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MMcf			78
Price Driven [Domain] | Proved Reserves [Domain] | Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls				29

Supplemental Crude Oil and Na77

Supplemental Crude Oil and Natural Gas Information - Schedule of Proved Crude Oil and Natural Gas Reserves (Detail)	12 Months Ended
	Dec. 31, 2017$ / BarrelsMBoeMMcfMBbls	Dec. 31, 2016$ / BarrelsMBoeMMcfMBbls	Dec. 31, 2015MBoeMMcfMBbls	Dec. 31, 2014MBoe
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Net (Energy) | MBoe	1,330,995	1,274,864	1,225,811	1,351,091
Changes in Proved Reserves [Roll Forward]
Revisions of previous estimates | MBoe	(82,012)	(110,474)	(297,198)
Extensions, discoveries, and other additions | MBoe	240,206	249,430	253,173
Proved Developed and Undeveloped Reserve, Production (Energy) | MBoe	88,562	79,390	80,926
Sales of minerals in place, Total | MBoe	(15,197)	(10,513)	(329)
Purchases of minerals in place, Total | MBoe	1,696	0	0
Percent of proved crude oil reserve estimates prepared by external reserve engineers	96.00%	99.00%	98.00%
Natural Gas [Member]
Reserve Quantities [Line Items]
Twelve month average SEC price | $ / Barrels	2.98	2.49
Changes in Proved Reserves [Roll Forward]
Proved reserves at beginning of period | MMcf	3,789,818	3,151,786	2,908,386
Revisions of previous estimates | MMcf	(25,390)	(63,057)	(302,143)
Extensions, discoveries and other additions | MMcf	661,867	911,062	710,453
Production | MMcf	(228,159)	(195,240)	(164,454)
Sales of minerals in place | MMcf	(64,989)	(14,733)	(456)
Purchases of minerals in place | MMcf	7,134	0	0
Proved reserves at end of period | MMcf	4,140,281	3,789,818	3,151,786
Crude Oil [Member]
Reserve Quantities [Line Items]
Twelve month average SEC price | $ / Barrels	51.34	42.75
Changes in Proved Reserves [Roll Forward]
Proved reserves at beginning of period | MBbls	643,228	700,514	866,360
Revisions of previous estimates | MBbls	(77,779)	(99,966)	(246,840)
Extensions, discoveries and other additions | MBbls	129,895	97,587	134,764
Production | MBbls	(50,536)	(46,850)	(53,517)
Sales of minerals in place | MBbls	(4,365)	(8,057)	(253)
Purchases of minerals in place | MBbls	506	0	0
Proved reserves at end of period | MBbls	640,949	643,228	700,514

Supplemental Crude Oil and Na78

Supplemental Crude Oil and Natural Gas Information - Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities (Detail)	12 Months Ended
	Dec. 31, 2017MBoeMMcfMBbls	Dec. 31, 2016MBoeMMcfMBbls	Dec. 31, 2015MBoeMMcfMBbls	Dec. 31, 2014MBoeMMcf
Reserve Quantities [Line Items]
Proved Developed Reserves (MBOE) | MBoe	601,901	518,646	525,188
Proved Undeveloped Reserve (MBOE) | MBoe	729,094	756,218	700,623
Proved Developed and Undeveloped Reserve, Net (MBOE) | MBoe	1,330,995	1,274,864	1,225,811	1,351,091
Crude Oil [Member]
Reserve Quantities [Line Items]
Proved Developed Reserves (Volume) | MBbls	318,707	290,210	326,798
Proved Undeveloped Reserve (Volume) | MBbls	322,242	353,018	373,716
Proved Developed and Undeveloped Reserves, Net | MBbls	640,949	643,228	700,514
Proved Undeveloped Reserves [Domain]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBoe	89
Proved Undeveloped Reserves [Domain] | Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls	41
Proved Undeveloped Reserves [Domain] | Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates	290
Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates	(25,390)	(63,057)	(302,143)
Proved Developed Reserves (Volume)	1,699,161	1,370,620	1,190,343
Proved Undeveloped Reserve (Volume)	2,441,120	2,419,198	1,961,443
Proved Developed and Undeveloped Reserves, Net	4,140,281	3,789,818	3,151,786	2,908,386
Price Driven [Domain] | Proved Reserves [Domain]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBoe	42
Price Driven [Domain] | Proved Reserves [Domain] | Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls	29
Price Driven [Domain] | Proved Reserves [Domain] | Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates	78
Production Type [Domain] | Proved Reserves [Domain]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBoe	30
Production Type [Domain] | Proved Reserves [Domain] | Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls	59
Production Type [Domain] | Proved Reserves [Domain] | Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates	173
Other [Domain] | Proved Reserves [Domain]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBoe	5
Other [Domain] | Proved Reserves [Domain] | Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls	7
Other [Domain] | Proved Reserves [Domain] | Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates	11

Supplemental Crude Oil and Na79

Supplemental Crude Oil and Natural Gas Information - Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplemental Crude Oil and Natural Gas Information [Abstract]
Discount factor utilized as standardized measure for future net cash flows	10.00%
Future cash inflows	$ 42,574,897	$ 31,008,587	$ 36,551,672
Future production costs	(11,159,362)	(9,175,410)	(10,869,493)
Future development and abandonment costs	(6,487,097)	(6,452,647)	(6,935,958)
Future income taxes	(3,488,755)	(3,018,839)	(3,717,612)
Future net cash flows	21,439,683	12,361,691	15,028,609
10% annual discount for estimated timing of cash flows	(10,969,506)	(6,851,468)	(8,552,325)
Standardized measure of discounted future net cash flows	$ 10,470,177	$ 5,510,223	$ 6,476,284	$ 18,433,034

Supplemental Crude Oil and Na80

Supplemental Crude Oil and Natural Gas Information - Changes in Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Standardized measure of discounted future net cash flows at beginning of year	$ 5,510,223	$ 6,476,284	$ 18,433,034
Extensions, discoveries and improved recoveries, less related costs	1,462,629	786,587	1,091,283
Revisions of previous quantity estimates	(1,004,355)	(794,785)	(2,156,028)
Changes in estimated future development and abandonment costs	743,657	1,651,218	5,008,731
Sales of Minerals in Place	(41,077)	(90,390)	(7,768)
Net change in prices and production costs	3,808,116	(2,003,163)	(16,111,142)
Accretion of discount	665,507	798,597	1,843,303
Sales of crude oil and natural gas produced, net of production costs	(2,450,474)	(1,595,281)	(2,002,997)
Development costs incurred during the period	1,045,875	454,983	1,394,584
Change in timing of estimated future production and other	948,519	(538,665)	(3,844,259)
Change in income taxes	(218,443)	364,838	2,827,543
Net change	4,959,954	(966,061)	(11,956,750)
Standardized measure of discounted future net cash flows at end of year	$ 10,470,177	$ 5,510,223	$ 6,476,284

Quarterly Financial Data - Sche

Quarterly Financial Data - Schedule Of Quarterly Financial Data (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended																12 Months Ended
	Dec. 31, 2017		Sep. 30, 2017		Jun. 30, 2017		Mar. 31, 2017		Dec. 31, 2016		Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Effect of Fourth Quarter Events [Line Items]
Estimated litigation liability, after tax	$ 37,000
Basic eps litigation settlement	$ 0.10
Diluted eps estimated litigation settlement	$ 0.10
Loss on extinguishment of debt									$ 26,055	[1]	$ 0		$ 0		$ 0		$ 554	$ 26,055	$ 0
Total revenues	$ 1,047,172	[2]	$ 726,743	[2]	$ 661,486	[2]	$ 685,427	[2]	549,689	[2]	526,199	[2]	451,211	[2]	453,174	[2]	3,120,828	1,980,273	2,680,167
Gain (loss) on derivative instruments, net	8,165	[2]	8,602	[2]	28,022	[2]	46,858	[2]	(47,382)	[2]	15,668	[2]	(82,257)	[2]	42,112	[2]	91,647	(71,859)	91,085
Property impairments	27,552	[3]	35,130	[3]	123,316	[3]	51,372	[3]	34,564	[3]	57,689	[3]	66,112	[3]	78,927	[3]	237,370	237,292	402,131
Litigation settlement	59,600	[4]	0		0		0										59,600	0	0
Gain (Loss) on Disposition of Property Plant Equipment	54,420	[5]	3,562	[5]	780	[5]	(3,638)	[5]	201,315	[5]	6,158	[5]	96,907	[5]	109	[5]	(55,124)	(304,489)	(23,149)
Income from operations	309,468		91,753		(29,041)		77,221		155,299		(93,183)		(110,547)		(239,103)		449,401	(287,534)	(224,001)
Tax benefit from US tax reform legislation																	(713,655)	0	0
Net income (loss)	$ 841,914	[6]	$ 10,621		$ (63,557)		$ 469		$ 27,670		$ (109,621)		$ (119,402)		$ (198,326)		$ 789,447	$ (399,679)	$ (353,668)
Net income per share: Basic	$ 2.27		$ 0.03		$ (0.17)		$ 0		$ 0.07		$ (0.30)		$ (0.32)		$ (0.54)		$ 2.13	$ (1.08)	$ (0.96)
Net income per share: Diluted	$ 2.25		$ 0.03		$ (0.17)		$ 0		$ 0.07		$ (0.30)		$ (0.32)		$ (0.54)		$ 2.11	$ (1.08)	$ (0.96)
[1]	See Note 7. Long-Term Debt for discussion of the loss recognized by the Company upon the redemption of its 2020 Notes and 2021 Notes in the 2016 fourth quarter
[2]	Gains and losses on crude oil and natural gas derivative instruments are reflected in “Total revenues” on both the consolidated statements of comprehensive income (loss) and this table of unaudited quarterly financial data. Crude oil and natural gas derivative gains and losses have been shown separately to illustrate the fluctuations in revenues that are attributable to the Company’s derivative instruments. Commodity price fluctuations each quarter can result in significant swings in mark-to-market gains and losses, which affects comparability between periods.
[3]	Property impairments have been shown separately to illustrate the impact on quarterly results attributable to write downs of the Company’s assets. Commodity price fluctuations each quarter can result in significant changes in estimated future cash flows and resulting impairments, which affects comparability between periods.
[4]	Fourth quarter 2017 results include a $59.6 million pre-tax loss accrual recognized in conjunction with a litigation settlement as discussed in Note 10. Commitments and Contingencies, which resulted in an after-tax decrease in net income of $37.0 million ($0.10 per basic and diluted share).
[5]	Gains on asset sales have been shown separately to illustrate the impact on quarterly results attributable to asset dispositions, which differ in significance from period to period and affect comparability. See Note 14. Property Dispositions for a discussion of notable dispositions.
[6]	Fourth quarter 2017 results reflect the remeasurement of the Company's deferred income tax assets and liabilities in response to the enactment of the Tax Reform Act in December 2017, which resulted in a one-time decrease in income tax expense and corresponding increase in net income of approximately $713.7 million ($1.92 per basic share and $1.91 per diluted share). See Note 8. Income Taxes for further discussion.