Continental Resources Inc (CLR) 10-K 22 Feb 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2016	Jan. 31, 2017	Jun. 30, 2016
Entity Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2,016
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		374,483,998
Entity Public Float			$ 3.9

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 16,643	$ 11,463
Receivables:
Crude oil and natural gas sales	404,750	378,622
Affiliated parties	99	122
Joint interest and other, net	364,850	232,293
Derivative assets	4,061	93,922
Inventories	111,987	94,151
Prepaid expenses and other	10,843	11,766
Total current assets	913,233	822,339
Net property and equipment, based on successful efforts method of accounting	12,881,227	14,063,328
Noncurrent derivative assets	0	14,560
Other noncurrent assets	17,316	19,581
Total assets	13,811,776	14,919,808
Current liabilities:
Accounts payable trade	476,342	553,285
Revenues and royalties payable	217,425	187,000
Payables to affiliated parties	148	69
Accrued liabilities and other	176,770	176,947
Derivative liabilities	59,489	3,583
Current portion of long-term debt	2,219	2,144
Total current liabilities	932,393	923,028
Long-term debt, net of current portion	6,577,697	7,115,644
Other noncurrent liabilities:
Deferred income tax liabilities, net	1,890,305	2,090,228
Asset retirement obligations, net of current portion	94,436	101,251
Noncurrent derivative liabilities	0	3,706
Other noncurrent liabilities	14,949	17,051
Total other noncurrent liabilities	1,999,690	2,212,236
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; 374,492,357 shares issued and outstanding at December 31, 2016; 372,959,080 shares issued and outstanding at December 31, 2015	3,745	3,730
Additional paid-in capital	1,375,290	1,345,624
Accumulated other comprehensive loss	(260)	(3,354)
Retained earnings	2,923,221	3,322,900
Total shareholders’ equity	4,301,996	4,668,900
Total liabilities and shareholders’ equity	$ 13,811,776	$ 14,919,808

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2016	Dec. 31, 2015
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	374,492,357	372,959,080
Common stock, outstanding	374,492,357	372,959,080

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues:
Crude oil and natural gas sales	$ 2,026,958	$ 2,551,131	$ 4,107,894
Crude oil and natural gas sales to affiliates	0	1,400	95,128
Gain (loss) on crude oil and natural gas derivatives, net	(71,859)	91,085	559,759
Crude oil and natural gas service operations	25,174	36,551	38,837
Total revenues	1,980,273	2,680,167	4,801,618
Operating costs and expenses:
Production expenses	289,289	347,243	347,349
Production expenses to affiliates	0	1,654	5,123
Production taxes and other expenses	142,388	200,637	349,760
Exploration expenses	16,972	19,413	50,067
Crude oil and natural gas service operations	11,386	17,337	21,871
Depreciation, depletion, amortization and accretion	1,708,744	1,749,056	1,358,669
Property impairments	237,292	402,131	616,888
General and administrative expenses	169,580	189,846	184,655
Net gain on sale of assets and other	(307,844)	(23,149)	(600)
Total operating costs and expenses	2,267,807	2,904,168	2,933,782
Income (loss) from operations	(287,534)	(224,001)	1,867,836
Other income (expense):
Interest expense	(320,562)	(313,079)	(283,928)
Loss on extinguishment of debt	(26,055)	0	(24,517)
Other	1,697	1,995	2,647
Total other income (expense)	(344,920)	(311,084)	(305,798)
Income (loss) before income taxes	(632,454)	(535,085)	1,562,038
Provision (benefit) for income taxes	(232,775)	(181,417)	584,697
Net income (loss)	$ (399,679)	$ (353,668)	$ 977,341
Basic net income (loss) per share (in dollars per share)	$ (1.08)	$ (0.96)	$ 2.65
Diluted net income (loss) per share (in dollars per share)	$ (1.08)	$ (0.96)	$ 2.64
Foreign currency translation adjustments	$ 3,094	$ (2,969)	$ (385)
Other Comprehensive Income (Loss), Net of Tax	3,094	(2,969)	(385)
Comprehensive Income (Loss)	$ (396,585)	$ (356,637)	$ 976,956

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, 2013	$ 3,953,118	$ 3,713	$ 1,250,178		$ 2,699,227
Balance, shares at Dec. 31, 2013		371,317,318
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	977,341				977,341
Other Comprehensive Income (Loss), Net of Tax	(385)			$ (385)
Stock-based compensation	54,343		54,343
Restricted stock:
Issued	14	$ 14	0
Issued, shares		1,424,764
Repurchased and canceled	(16,583)	$ (3)	(16,580)
Repurchased and canceled, shares		(283,434)
Forfeited	(4)	$ (4)
Forfeited, shares		(453,146)
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	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
Adjustments to Additional Paid in Capital, Income Tax Deficiency 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

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash flows from operating activities:
Net income (loss)	$ (399,679)	$ (353,668)	$ 977,341
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion, amortization and accretion	1,709,567	1,746,454	1,368,311
Property impairments	237,292	402,131	616,888
Non-cash (gain) loss on derivatives, net	156,621	(21,532)	(174,409)
Stock-based compensation	48,098	51,834	54,353
Provision (benefit) for deferred income taxes	(209,836)	(181,441)	584,677
Tax deficiency (benefit) from stock-based compensation	9,828	(13,177)	0
Dry hole costs	4,866	8,381	23,679
Net gain on sale of assets and other	(304,489)	(23,149)	(600)
Loss on extinguishment of debt	(26,055)	0	(24,517)
Other, net	9,812	12,646	7,637
Changes in assets and liabilities:
Accounts receivable	(158,383)	524,973	(129,634)
Inventories	(17,836)	7,997	(65,919)
Other current assets	968	65,493	(57,489)
Accounts payable trade	(14,404)	(201,434)	85,540
Revenues and royalties payable	30,455	(85,754)	(18,022)
Accrued liabilities and other	(883)	(84,056)	58,880
Other noncurrent assets and liabilities	(2,133)	1,403	(35)
Net cash provided by operating activities	1,125,919	1,857,101	3,355,715
Cash flows from investing activities:
Exploration and development	(1,154,131)	(3,042,747)	(4,604,468)
Purchase of producing crude oil and natural gas properties	(5,008)	(557)	(48,917)
Purchase of other property and equipment	(5,375)	(36,951)	(63,402)
Proceeds from sale of assets	631,549	34,008	129,388
Net cash used in investing activities	(532,965)	(3,046,247)	(4,587,399)
Cash flows from financing activities:
Credit facility borrowings	1,691,000	2,001,000	1,695,000
Repayment of credit facility	(1,639,000)	(1,313,000)	(1,805,000)
Proceeds from issuance of Senior Notes	0	0	1,681,834
Redemption of Senior Notes	(600,000)	0	(300,000)
Premium on redemption of Senior Notes	(19,168)	0	(17,497)
Proceeds from other debt	0	500,000	0
Repayment of other debt	(2,144)	(2,078)	(2,013)
Debt issuance costs	(40)	(4,597)	(8,026)
Repurchase of restricted stock for tax withholdings	(8,593)	(7,313)	(16,583)
Tax (deficiency) benefit from stock-based compensation	(9,828)	13,177	0
Net cash (used in) provided by financing activities	(587,773)	1,187,189	1,227,715
Effect of exchange rate on cash and cash equivalents	(1)	(10,961)	(132)
Net change in cash and cash equivalents	5,180	(12,918)	(4,101)
Cash and cash equivalents at beginning of period	11,463	24,381	28,482
Cash and cash equivalents at end of period	$ 16,643	$ 11,463	$ 24,381

Organization and Summary of Sig

Organization and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
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), STACK (Sooner Trend Anadarko Canadian Kingfisher), and Arkoma Woodford areas of Oklahoma. Historically, our properties in Blaine, Dewey and Custer counties of Oklahoma that produced from the Woodford formation were referred to as the Northwest Cana district, while properties often underlying the same surface acreage in those counties that produced from the Meramec and Osage formations were referred to as the STACK district. Such properties were historically combined by us and referred to as "Northwest Cana/STACK". Effective December 31, 2016, we now refer to such properties simply as "STACK". The East region is comprised of undeveloped leasehold acreage east of the Mississippi River with no current drilling or production operations. A substantial portion of the Company’s operations are located in the North region, with that region comprising approximately 61% 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, 2016 . 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, 2016 , approximately 50% of the Company’s estimated proved reserves were located in the North region. In recent years, the Company has significantly expanded its activity in the South region with its discovery of the SCOOP play and its increased activity in the STACK play. The South region comprised approximately 39% 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 at December 31, 2016 . For the year ended December 31, 2016 , crude oil accounted for approximately 59% of the Company’s total production and approximately 82% of its crude oil and natural gas revenues. Crude oil represents approximately 50% of the Company's estimated proved reserves as of December 31, 2016 . 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 period. Actual results may differ from those estimates. The most significant of the estimates and assumptions that affect reported results are the 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, 2016 and 2015 were not material. 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, 2016 , the Company had cash deposits in excess of federally insured amounts of approximately $15.0 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 $3.0 million and $2.3 million as of December 31, 2016 and 2015 , 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, 2016 , sales to the Company’s largest purchaser accounted for approximately 18% of its total crude oil and natural gas sales. No other purchasers accounted for more than 10% of the Company’s total crude oil and natural gas sales for 2016 . 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 at the lower of cost or market, with cost determined primarily using a weighted average cost method applied to specific classes of inventory items. The components of inventory as of December 31, 2016 and 2015 consisted of the following: December 31, In thousands 2016 2015 Tubular goods and equipment $ 15,243 $ 15,633 Crude oil 96,744 78,518 Total $ 111,987 $ 94,151 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 labor costs to operate the Company’s properties, repairs and maintenance, waste water disposal costs, utility 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 10-40 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 on its crude oil and natural gas properties and related facilities disposal. The following table summarizes the changes in the Company’s future abandonment liabilities from January 1, 2014 through December 31, 2016 : In thousands 2016 2015 2014 Asset retirement obligations at January 1 $ 102,909 $ 76,708 $ 55,787 Accretion expense 6,086 4,740 3,366 Revisions (1) (12,755 ) 15,068 9,916 Plus: Additions for new assets 2,692 7,404 9,022 Less: Plugging costs and sold assets (2,754 ) (1,011 ) (1,383 ) Total asset retirement obligations at December 31 $ 96,178 $ 102,909 $ 76,708 Less: Current portion of asset retirement obligations at December 31 (2) 1,742 1,658 1,246 Non-current portion of asset retirement obligations at December 31 $ 94,436 $ 101,251 $ 75,462 (1) Revisions for the year ended December 31, 2016 primarily represent a decrease in the present value of liabilities resulting from a deferral of the estimated future timing of abandonment prompted by an increase in the economic lives of certain producing properties. (2) Balance is included in the caption "Accrued liabilities and other" in the consolidated balance sheets. As of December 31, 2016 and 2015 , net property and equipment on the consolidated balance sheets included $77.9 million and $87.5 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 three-year term loan, 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 $55.9 million and $71.8 million (net of accumulated amortization of $56.8 million and $47.0 million ) relating to its long-term debt at December 31, 2016 and 2015 , respectively. Unamortized capitalized costs associated with the Company’s Notes, three-year term loan, and note payable totaled $50.4 million and $64.1 million at December 31, 2016 and 2015 , respectively, and are reflected as a reduction of "Long-term debt, net of current portion" on the consolidated balance sheets. Unamortized capitalized costs associated with the Company’s revolving credit facility totaled $5.5 million and $7.7 million at December 31, 2016 and 2015 , respectively, and are reflected in "Other noncurrent assets" on the consolidated balance sheets. In November 2016, the Company wrote off $6.1 million of unamortized capitalized costs in conjunction with the redemptions of its 7.375% Senior Notes due 2020 and 7.125% Senior Notes due 2021 as discussed in Note 7. Long-Term Debt . For the years ended December 31, 2016 , 2015 and 2014 , the Company recognized amortization expense associated with capitalized debt issuance costs of $9.8 million , $8.9 million and $9.3 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, 2016 and 2015 . 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. 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 $1.0 million , $13.5 million , and $4.4 million for the years ended December 31, 2016 , 2015, and 2014, 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, 2016 , 2015 and 2014 . Year ended December 31, In thousands, except per share data 2016 2015 2014 Income (loss) (numerator): Net income (loss) - basic and diluted $ (399,679 ) $ (353,668 ) $ 977,341 Weighted average shares (denominator): Weighted average shares - basic 370,380 369,540 368,829 Non-vested restricted stock (1) — — 1,929 Weighted average shares - diluted 370,380 369,540 370,758 Net income (loss) per share: Basic $ (1.08 ) $ (0.96 ) $ 2.65 Diluted $ (1.08 ) $ (0.96 ) $ 2.64 (1) 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 loss" within shareholders’ equity on the consolidated balance sheets. New accounting pronouncements not yet adopted Leases – In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("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 and is in the process of developing systems and processes to identify, classify, and account for leases within the scope of the new guidance. 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. Stock-based compensation – In March 2016, the FASB issued 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 standard is effective for interim and annual reporting periods beginning after December 15, 2016 and will be adopted either prospectively, retrospectively or using a modified retrospective transition approach depending on the topic covered in the standard. The Company will adopt the new standard on January 1, 2017. Under ASU 2016-09, effective January 1, 2017 companies will no longer record excess tax benefits and deficiencies in additional paid-in capital. Instead, excess tax benefits and deficiencies will be recognized as income tax expense or benefit in the income statement. 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. ASU 2016-09 also removes the requirement to delay recognition of an excess tax benefit until it reduces current taxes payable. Under the new guidance, effective January 1, 2017 excess tax benefits will be recorded when they arise. This change is required to be applied on a modified retrospective basis through a cumulative effect adjustment to retained earnings upon adoption. The Company estimates its cumulative effect adjustment will result in an approximate $5 million increase to retained earnings upon adoption of ASU 2016-09 on January 1, 2017. Additionally, the Company expects to recognize approximately $4 million of tax deficiencies as income tax expense in the first quarter of 2017 under the new standard. The Company will continue its current accounting practice of estimating forfeitures in determining the amount of stock-based compensation expense to recognize. Therefore, the adoption of ASU 2016-09 is not expected to have an impact on stock-based compensation expense to be recognized on non-vested restricted stock awards. 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 has 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 will be 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 plans to adopt the standard on January 1, 2018 using a modified retrospective approach. 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 is expected to impact the presentation of future 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 is expected to result in future revenues and associated transportation expenses for certain of the Company's arrangements being reported on a gross basis. The Company expects 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, 2016 , the Company estimates it had approximately $230 million of transportation related charges included in "Crude oil and natural gas sales" on the consolidated statements of comprehensive income (loss). The Company is not currently 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. 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. Early adoption is permitted. The Company has elected to early adopt ASU 2017-01 on January 1, 2017 and will apply the new guidance to applicable transactions occurring after that date. 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 is currently evaluating the new standard and is unable to estimate its financial statement impact at this time.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2016
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 2016 2015 2014 Supplemental cash flow information: Cash paid for interest $ 316,116 $ 301,743 $ 267,384 Cash paid for income taxes 2 30 53,457 Cash received for income tax refunds 174 61,403 7 Non-cash investing activities: Asset retirement obligation additions and revisions, net (10,063 ) 22,472 18,938 As of December 31, 2016 , 2015 , 2014 , and 2013, the Company had $223.6 million , $282.8 million , $797.5 million , and $507.0 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, 2016
Property, Plant and Equipment, Net [Abstract]
Net Property and Equipment	Net Property and Equipment Net property and equipment includes the following at December 31, 2016 and 2015 . For the year ended December 31, 2016 , capital expenditures of $1.1 billion were offset by the removal of $804 million of costs associated with asset sales and $234 million of impairments of unproved properties, resulting in a minimal change in gross property and equipment during the year. December 31, In thousands 2016 2015 Proved crude oil and natural gas properties $ 19,802,395 $ 19,520,724 Unproved crude oil and natural gas properties 429,562 682,988 Service properties, equipment and other 301,788 307,059 Total property and equipment 20,533,745 20,510,771 Accumulated depreciation, depletion and amortization (7,652,518 ) (6,447,443 ) Net property and equipment $ 12,881,227 $ 14,063,328

Accrued Liabilities and Other

Accrued Liabilities and Other	12 Months Ended
	Dec. 31, 2016
Accrued Liabilities and Other Liabilities [Abstract]
Accrued Liabilities and Other	Accrued Liabilities and Other Accrued liabilities and other includes the following at December 31, 2016 and 2015 : December 31, In thousands 2016 2015 Prepaid advances from joint interest owners $ 57,861 $ 49,917 Accrued compensation 38,046 40,060 Accrued production taxes, ad valorem taxes and other non-income taxes 22,053 21,678 Accrued interest 52,657 62,058 Current portion of asset retirement obligations 1,742 1,658 Other 4,411 1,576 Accrued liabilities and other $ 176,770 $ 176,947

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2016
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, 2016 , the Company had outstanding natural gas derivative contracts with respect to future production as set forth in the table below. The hedged volumes reflected below represent an aggregation of multiple derivative contracts primarily having calendar year 2017 durations that are generally expected to be realized ratably over the year. The Company's natural gas derivative contracts are settled based upon reported NYMEX Henry Hub settlement prices. At December 31, 2016 the Company had no outstanding crude oil derivative contracts. Swaps Weighted Average Price Floors Ceilings Weighted Average Price Weighted Average Price Period and Type of Contract MMBtus Range Range January 2017 - December 2017 Swaps - Henry Hub 72,690,000 $ 3.41 Collars - Henry Hub 65,700,000 $2.40 - $3.00 $ 2.47 $2.92 - $3.88 $ 3.08 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 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 2016 2015 2014 Cash received (paid) on derivatives: Crude oil fixed price swaps (1) $ — $ — $ 331,591 Crude oil collars (1) — — 65,310 Natural gas fixed price swaps 88,823 39,670 (11,551 ) Natural gas collars — 29,883 — Cash received on derivatives, net 88,823 69,553 385,350 Non-cash gain (loss) on derivatives: Crude oil fixed price swaps — — 84,792 Crude oil collars — — 1,121 Crude oil written call options 38 4,715 3,981 Natural gas fixed price swaps (120,784 ) 41,828 62,699 Natural gas collars (39,936 ) (25,011 ) 21,816 Non-cash gain (loss) on derivatives, net (160,682 ) 21,532 174,409 Gain (loss) on crude oil and natural gas derivatives, net $ (71,859 ) $ 91,085 $ 559,759 (1) Net cash receipts for crude oil swaps and collars for the year ended December 31, 2014 include $433 million of proceeds received from crude oil derivative contracts that were settled in the fourth quarter of 2014 prior to their contractual maturities. Of the proceeds, $373 million related to crude oil swap liquidations and $60 million related to crude oil collar liquidations. Diesel fuel derivatives In March 2016, the Company entered into diesel fuel swap derivative contracts to economically hedge against the variability in cash flows associated with future purchases of diesel fuel for use in drilling activities. The Company has hedged approximately 12 million gallons of diesel fuel over the period from January 2017 to December 2017 at a weighted average price of $1.43 per gallon. With respect to these diesel fuel swap contracts, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is greater 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 less than the swap price. The diesel fuel swap contracts are settled based upon reported NYMEX settlement prices for New York Harbor ultra-low sulfur diesel fuel. The Company recognizes its diesel fuel derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The estimated fair value is based upon various factors, including commodity exchange prices, over-the-counter quotations, the risk-free interest rate, and time to expiration. The Company has not designated its diesel fuel derivative instruments as hedges for accounting purposes and, as a result, marks the derivative instruments to fair value and recognizes 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.” For the year ended December 31, 2016 , the Company recognized cash gains totaling $0.7 million on diesel fuel derivatives that matured during the period and non-cash gains totaling $4.1 million on diesel fuel derivatives that continue to be held at year-end. 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”. 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, 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 2016 2015 Commodity derivative assets: Gross amounts of recognized assets $ 4,061 $ 120,385 Gross amounts offset on balance sheet — (11,903 ) Net amounts of assets on balance sheet 4,061 108,482 Commodity derivative liabilities: Gross amounts of recognized liabilities (59,489 ) (19,192 ) Gross amounts offset on balance sheet — 11,903 Net amounts of liabilities on balance sheet $ (59,489 ) $ (7,289 ) 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 2016 2015 Derivative assets $ 4,061 $ 93,922 Noncurrent derivative assets — 14,560 Net amounts of assets on balance sheet 4,061 108,482 Derivative liabilities (59,489 ) (3,583 ) Noncurrent derivative liabilities — (3,706 ) Net amounts of liabilities on balance sheet (59,489 ) (7,289 ) Total derivative assets (liabilities), net $ (55,428 ) $ 101,193

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2016
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 that are 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 that are 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 fixed price swaps, 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 fixed price swaps are calculated mainly using significant observable inputs (Level 2). Calculation of the fair values of collars and written call options 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, 2016 and 2015 . Fair value measurements at December 31, 2016 using: In thousands Level 1 Level 2 Level 3 Total Derivative liabilities: Fixed price swaps $ — $ (12,297 ) $ — $ (12,297 ) Collars — (43,131 ) — (43,131 ) Total $ — $ (55,428 ) $ — $ (55,428 ) Fair value measurements at December 31, 2015 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets (liabilities): Fixed price swaps $ — $ 104,426 $ — $ 104,426 Collars — (3,195 ) — (3,195 ) Written call options — (38 ) $ — (38 ) Total $ — $ 101,193 $ — $ 101,193 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. 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 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 swap prices through 2021 (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 0 to 40 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, 2016 , 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 $2.9 million for 2016 , all of which were recognized in the third quarter primarily for properties in a non-core area of the North region. The impaired properties were written down to their estimated fair value of approximately $0.7 million . Certain unproved crude oil and natural gas properties were impaired during the years ended December 31, 2016 , 2015 , and 2014 , 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 2016 2015 2014 Proved property impairments $ 2,895 $ 138,878 $ 324,302 Unproved property impairments 234,397 263,253 292,586 Total $ 237,292 $ 402,131 $ 616,888 Financial instruments not recorded at fair value The following table sets forth the fair values of financial instruments that are not recorded at fair value in the consolidated financial statements. December 31, 2016 December 31, 2015 In thousands Carrying Amount Fair Value Carrying Amount Fair Value Debt: Revolving credit facility $ 905,000 $ 905,000 $ 853,000 $ 853,000 Term loan 498,865 500,000 498,274 500,000 Note payable 12,176 10,200 14,309 12,500 7.375% Senior Notes due 2020 (1) — — 196,574 179,200 7.125% Senior Notes due 2021 (1) — — 395,365 388,300 5% Senior Notes due 2022 1,997,188 2,020,400 1,996,831 1,480,400 4.5% Senior Notes due 2023 1,484,524 1,474,800 1,482,451 1,061,000 3.8% Senior Notes due 2024 990,964 929,400 989,932 700,300 4.9% Senior Notes due 2044 691,199 607,600 691,052 430,500 Total debt $ 6,579,916 $ 6,447,400 $ 7,117,788 $ 5,605,200 (1) The Company redeemed the 7.375% Senior Notes due 2020 and the 7.125% Senior Notes due 2021 on November 10, 2016. See Note 7. Long-Term Debt for further discussion of the redemptions. 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 7.375% Senior Notes due 2020 (“2020 Notes”), the 7.125% Senior Notes due 2021 (“2021 Notes”), 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”), 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, 2016
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $37.3 million and $49.6 million at December 31, 2016 and 2015 , respectively, consists of the following. December 31, In thousands 2016 2015 Revolving credit facility $ 905,000 $ 853,000 Term loan 498,865 498,274 Note payable 12,176 14,309 7.375% Senior Notes due 2020 (1) — 196,574 7.125% Senior Notes due 2021 (1) — 395,365 5% Senior Notes due 2022 1,997,188 1,996,831 4.5% Senior Notes due 2023 1,484,524 1,482,451 3.8% Senior Notes due 2024 990,964 989,932 4.9% Senior Notes due 2044 691,199 691,052 Total debt 6,579,916 7,117,788 Less: Current portion of long-term debt 2,219 2,144 Long-term debt, net of current portion $ 6,577,697 $ 7,115,644 (1) The Company redeemed the 7.375% Senior Notes due 2020 and the 7.125% Senior Notes due 2021 on November 10, 2016 as discussed below. 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, 2016 , which may be increased up to a total of $4.0 billion upon agreement between the Company and participating lenders. The Company had $905 million and $853 million of outstanding borrowings on its revolving credit facility at December 31, 2016 and 2015 , respectively. 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 borrowings at December 31, 2016 was 2.4% . The Company had approximately $1.84 billion of borrowing availability on its revolving credit facility at December 31, 2016 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, 2016 . Senior notes 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, 2016 . 2022 Notes 2023 Notes 2024 Notes 2044 Notes Face value (in thousands) $2,000,000 $1,500,000 $1,000,000 $700,000 Maturity date Sep 15, 2022 April 15, 2023 June 1, 2024 June 1, 2044 Interest payment dates March 15, Sep 15 April 15, Oct 15 June 1, Dec 1 June 1, Dec 1 Call premium redemption period (1) March 15, 2017 — — — Make-whole redemption period (2) March 15, 2017 Jan 15, 2023 Mar 1, 2024 Dec 1, 2043 (1) On or after this date, the Company has the option to redeem all or a portion of its 2022 Notes at the decreasing redemption prices specified in the indenture to the 2022 Notes plus any accrued and unpaid interest to the date of redemption. (2) At any time prior to these 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, and 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, 2016 . 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 On November 10, 2016, the Company redeemed its then outstanding 7.375% Senior Notes due 2020 and 7.125% Senior Notes due 2021. 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. Such borrowings offset the Company's previous reduction of outstanding credit facility borrowings which used proceeds totaling approximately $631.5 million from asset dispositions completed in 2016, resulting in no net increase in total debt associated with the redemptions. The Company recognized a pre-tax loss totaling $26.1 million related to the redemptions, which includes 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 . 2014 Redemption of Senior Notes In July 2014, the Company redeemed its then outstanding $300 million of 8.25% Senior Notes due 2019 for $317.5 million , representing a make-whole amount calculated in accordance with the terms of the notes and related indenture. The Company recognized a pre-tax loss of $24.5 million related to the redemption, which included the make-whole premium and the write-off of deferred financing costs and unaccreted debt discount 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, 2014. Term loan In November 2015, the Company borrowed $500 million under a three-year term loan agreement, the proceeds of which were used to repay a portion of the borrowings then outstanding on the Company's revolving credit facility. The term loan matures in full on November 4, 2018 and bears interest at a variable market-based interest rate 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 interest rate on the term loan at December 31, 2016 was 2.3% . The term loan 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 1.0, consistent with the covenant requirement in the Company's revolving credit facility. The Company was in compliance with the term loan covenants at December 31, 2016 . 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 3.1% per annum. Principal and interest are payable monthly through the loan’s maturity date of February 26, 2022 . Accordingly, approximately $2.2 million is reflected as a current liability under the caption “Current portion of long-term debt” in the consolidated balance sheets at December 31, 2016 .

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The items comprising the provision (benefit) for income taxes are as follows for the periods presented: Year ended December 31, In thousands 2016 2015 2014 Current income tax provision (benefit): United States federal (1) (22,941 ) — — Various states 2 24 20 Total current income tax provision (benefit) (22,939 ) 24 20 Deferred income tax provision (benefit): United States federal (182,422 ) (140,578 ) 527,315 Various states (27,414 ) (40,863 ) 57,362 Total deferred income tax provision (benefit) (209,836 ) (181,441 ) 584,677 Provision (benefit) for income taxes $ (232,775 ) $ (181,417 ) $ 584,697 (1) The current federal income tax benefit for the year ended December 31, 2016 represents alternative minimum tax refunds. The provision (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, In thousands 2016 2015 2014 Expected income tax expense (benefit) based on US statutory tax rate of 35% $ (221,359 ) $ (187,280 ) $ 546,713 State income taxes, net of federal benefit (18,829 ) (16,219 ) 42,169 Canadian valuation allowance 1,044 13,503 4,389 Effect of differing statutory tax rate in Canada 481 5,239 (1,900 ) Other, net 5,888 3,340 (6,674 ) Provision (benefit) for income taxes $ (232,775 ) $ (181,417 ) $ 584,697 The components of the Company’s deferred tax assets and deferred tax liabilities as of December 31, 2016 and 2015 are reflected in the table below. December 31, In thousands 2016 2015 Deferred tax assets United States net operating loss carryforwards 478,975 398,024 Canadian net operating loss carryforwards 18,936 17,892 Alternative minimum tax carryforwards 16,663 40,796 Equity compensation 32,924 32,910 Non-cash losses on derivatives 21,064 — Other 11,466 11,048 Total deferred tax assets 580,028 500,670 Canadian valuation allowance (18,936 ) (17,892 ) Total deferred tax assets, net of valuation allowance 561,092 482,778 Deferred tax liabilities Property and equipment (2,448,450 ) (2,528,125 ) Non-cash gains on derivatives — (38,452 ) Gain on derivative liquidation — (4,158 ) Other (2,947 ) (2,271 ) Total deferred tax liabilities (2,451,397 ) (2,573,006 ) Deferred income tax liabilities, net $ (1,890,305 ) $ (2,090,228 ) As of December 31, 2016 , the Company had federal and state net operating loss carryforwards of $1.08 billion and $2.17 billion , respectively. The federal net operating loss carryforward will begin expiring in 2033. The Company's net operating loss carryforward in Oklahoma totaled $1.56 billion at December 31, 2016 , which will begin to expire in 2027. The Company's net operating loss carryforward in North Dakota totaled $530 million at December 31, 2016 , which will begin to expire in 2033. The Company has alternative minimum tax credit carryforwards of $17 million that have no expiration date. 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 2013. The Company recorded valuation allowances of $1.0 million , $13.5 million and $4.4 million against Canadian deferred tax assets for the years ended December 31, 2016 , 2015 and 2014, respectively, which resulted in a cumulative valuation allowance of $18.9 million as of December 31, 2016 . 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, 2016
Leases [Abstract]
Lease Commitments	Lease Commitments The Company’s operating lease obligations primarily represent leases for land and road use, office equipment, and communication towers. Lease payments associated with operating leases for the years ended December 31, 2016 , 2015 and 2014 were $4.4 million , $9.6 million and $8.0 million , respectively, a portion of which was capitalized and/or billed to other interest owners. At December 31, 2016 , the minimum future rental commitments under operating leases having lease terms in excess of one year are as follows: In thousands Total amount 2017 $ 1,624 2018 1,376 2019 746 2020 643 2021 476 Thereafter 7,629 Total obligations $ 12,494

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2016
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, 2016 . The commitments under these arrangements are not recorded in the accompanying consolidated balance sheets. Drilling commitments – As of December 31, 2016 , the Company has drilling rig contracts with various terms extending to January 2020 to ensure rig availability in its key operating areas. Future commitments as of December 31, 2016 total approximately $227 million , of which $138 million is expected to be incurred in 2017, $59 million in 2018, $29 million in 2019, and $1 million in 2020. 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 2027, 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, 2016 under the arrangements amount to approximately $840 million , of which $221 million is expected to be incurred in 2017, $215 million in 2018, $162 million in 2019, $55 million in 2020, $44 million in 2021, and $143 million thereafter. The Company’s commitments are for production primarily in the North region. The Company is not committed under these 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 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 seek recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the proposed class. On November 3, 2014, plaintiffs filed an Amended Petition that did not add any substantive claims, but sought a “hybrid class action” in which they sought certification of certain claims for injunctive relief, reserving the right to seek a further class certification on money damages in the future. Plaintiffs filed an Amended Motion for Class Certification on January 9, 2015, that modified the proposed class to royalty owners in Oklahoma production from July 1, 1993, to the present (instead of 1980 to the present) and sought certification of over 45 separate “issues” for injunctive or declaratory relief, again, reserving the right to seek a further class certification of money damages in the future. The Company responded to the petition, its amendment, and the motions for class certification denying the allegations and raising a number of affirmative defenses and legal arguments to each of the claims and filings. Certain discovery was undertaken and the “hybrid” motion was briefed by plaintiffs and the Company. A hearing on the “hybrid” class certification was held on June 1 and 2, 2015. On June 11, 2015, the trial court certified a “hybrid” class as requested by plaintiffs. The Company appealed the trial court’s class certification order. On February 8, 2017, the Court of Civil Appeals reversed the trial court’s ruling on certification and remanded the case for further proceedings. The Company is not currently able to estimate a reasonably possible loss or range of loss or what impact, if any, the ultimate resolution of the action will 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 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. It is reasonably possible one or more events may occur in the near term that could impact the Company’s ability to estimate the potential effect this matter could have, if any, on its financial condition, results of operations or cash flows. Plaintiffs have alleged underpayments in excess of $200 million that they may claim as damages, which may increase with the passage of time, a majority of which would be comprised of interest. The Company disputes plaintiffs’ claims, disputes the case meets the requirements for a class action and continues to vigorously defend the case. An unsuccessful mediation was conducted on December 7, 2015. The parties continue to negotiate a possible resolution to the case. However, it is unclear and unforeseeable whether the parties' efforts will result in settlement and the Company will continue to defend the case on all merits and certification issues and, absent settlement, intends to defend the case to a final judgment. 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 such other 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, 2016 and 2015 , the Company had recorded a liability on the consolidated balance sheets under the caption “Other noncurrent liabilities” of $6.5 million and $6.1 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, 2016
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions The affiliate transactions reflected in the consolidated statements of comprehensive income (loss) include transactions between the Company and 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, which resulted in a reduction in certain affiliate transactions recognized in the Company's financial statements subsequent to that date. The Company historically sold a portion of its natural gas production to Hiland. For the years ended December 31, 2015 and 2014 , these sales amounted to $1.4 million and $95.1 million , respectively, net of transportation and processing costs, and are 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 , $2.6 million and $5.9 million in 2016 , 2015 , and 2014 , 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 were $1.7 million and $5.1 million for the years ended December 31, 2015 and 2014 , respectively. The total amount paid to these affiliates, a portion of which was billed to other interest owners, was $0.1 million , $7.7 million and $58.2 million for the years ended December 31, 2016 , 2015 , and 2014 , respectively. Nothing was due to these affiliates at December 31, 2016 and 2015 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 $0.4 million , $0.7 million , and $1.7 million and received payments from these affiliates of $0.3 million , $0.5 million , and $0.8 million during the years ended December 31, 2016 , 2015 , and 2014 , respectively, relating to the operations of the respective properties. At December 31, 2016 and 2015 , approximately $90,000 and $106,000 was due from these affiliates, respectively, and approximately $45,000 and $52,000 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 and crews 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 2016 , 2015 , and 2014 , the Company charged affiliates approximately $9,500 , $9,600 , and $51,000 , respectively, for use of its corporate aircraft, crews, fuel, utilities and reimbursement of expenses and received approximately $6,800 , $33,000 , and $39,000 from affiliates in 2016 , 2015 , and 2014 , respectively. The Company was charged approximately $292,000 , $236,000 , and $97,000 , respectively, by affiliates for use of their aircraft and reimbursement of expenses during 2016 (including the prepayment), 2015 , and 2014 and paid $195,000 , $221,000 , and $34,000 to the affiliates in 2016 , 2015 , and 2014 , respectively. At December 31, 2016 and 2015 , approximately $3,400 and $1,000 was due from an affiliate, respectively, and approximately $97,000 and $15,000 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 and 2014 associated with the projects was $8.8 million and $1.8 million , respectively. The total amount paid, a portion of which was billed to other interest owners, was $9.2 million and $1.9 million for 2015 and 2014 respectively.

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-Based Compensation	Stock-Based Compensation 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 $48.1 million , $51.8 million , and $54.4 million for the years ended December 31, 2016 , 2015 and 2014 , 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, 2016 , the Company had 15,265,952 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 or 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, 2013 to December 31, 2016 is presented below. Number of Weighted Non-vested restricted shares at December 31, 2013 2,714,312 $ 37.50 Granted 1,424,764 61.11 Vested (1,007,166 ) 35.91 Forfeited (453,146 ) 44.90 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 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 a fixed amount determined at the grant date fair value and is recognized ratably over the vesting period as services are rendered by employees and directors. 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 2016 , 2015 and 2014 was $30.0 million , $23.6 million and $58.2 million , respectively. As of December 31, 2016 , there was approximately $55 million of unrecognized compensation expense related to non-vested restricted stock. This expense is expected to be recognized over a weighted average period of 1.4 years.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income Accumulated Other Comprehensive Income (Loss) (Notes)	12 Months Ended
	Dec. 31, 2016
Statement of Comprehensive Income [Abstract]
Comprehensive Income (Loss) Note [Text Block]	Accumulated Other Comprehensive Loss Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in "Accumulated other comprehensive loss" within shareholders’ equity on the consolidated balance sheets. The following table summarizes the change in accumulated other comprehensive loss for the years ended December 31, 2016 , 2015 , and 2014 : Year ended December 31, In thousands 2016 2015 2014 Beginning accumulated other comprehensive loss, net of tax $ (3,354 ) $ (385 ) $ — Foreign currency translation adjustments 3,094 (2,969 ) (385 ) Income taxes (1) — — — Other comprehensive income (loss), net of tax 3,094 (2,969 ) (385 ) Ending accumulated other comprehensive loss, net of tax $ (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

Property Dispositions	12 Months Ended
	Dec. 31, 2016
Extractive Industries [Abstract]
Property Acquisitions and Dispositions	Property Dispositions 2016 In October 2016, the Company sold approximately 30,000 net acres of non-strategic leasehold located 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 to a third party for cash proceeds of $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 located in Wyoming to a third party for cash proceeds of $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 to third parties for proceeds totaling $34.0 million . The proceeds primarily related to the disposition of certain non-producing leasehold acreage in Oklahoma to a third party 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. 2014 During the year ended December 31, 2014 , the Company sold certain non-strategic properties in various areas to third parties for proceeds totaling $129.4 million . The proceeds primarily related to dispositions of properties in the Niobrara play in Colorado and Wyoming in March 2014 for proceeds totaling $30.3 million and $85.8 million of proceeds received in conjunction with the disposition of certain Oklahoma properties in September 2014, with no significant gains or losses recognized. The disposed properties represented an immaterial portion of the Company’s total proved reserves, production, and revenues.

Crude Oil and Natural Gas Prope

Crude Oil and Natural Gas Property Information	12 Months Ended
	Dec. 31, 2016
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, 2016, 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, 2016 , 2015 and 2014 . Year ended December 31, In thousands 2016 2015 2014 Crude oil and natural gas sales $ 2,026,958 $ 2,552,531 $ 4,203,022 Production expenses (289,289 ) (348,897 ) (352,472 ) Production taxes and other expenses (142,388 ) (200,637 ) (349,760 ) Exploration expenses (16,972 ) (19,413 ) (50,067 ) Depreciation, depletion, amortization and accretion (1,679,485 ) (1,722,336 ) (1,338,351 ) Property impairments (237,292 ) (402,131 ) (616,888 ) Income tax benefit (provision) 126,794 33,680 (559,311 ) Results from crude oil and natural gas producing activities $ (211,674 ) $ (107,203 ) $ 936,173 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, 2016 , 2015 and 2014 are presented below: Year ended December 31, In thousands 2016 2015 2014 Property acquisition costs: Proved $ 5,008 $ 557 $ 48,917 Unproved 149,962 168,492 409,529 Total property acquisition costs 154,970 169,049 458,446 Exploration Costs 182,355 241,523 863,606 Development Costs 767,148 2,148,530 3,670,448 Total $ 1,104,473 $ 2,559,102 $ 4,992,500 Costs incurred above include asset retirement costs and revisions thereto of ($9.6) million , $22.8 million and $20.3 million for the years ended December 31, 2016 , 2015 and 2014 , 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, 2016 and 2015 are as follows: December 31, In thousands 2016 2015 Proved crude oil and natural gas properties $ 19,802,395 $ 19,520,724 Unproved crude oil and natural gas properties 429,562 682,988 Total 20,231,957 20,203,712 Less accumulated depreciation, depletion and amortization (7,553,255 ) (6,374,218 ) Net capitalized costs $ 12,678,702 $ 13,829,494 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 2016 2015 2014 Balance at January 1 $ 59,397 $ 93,421 $ 152,775 Additions to capitalized exploratory well costs pending determination of proved reserves 123,980 132,806 627,853 Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves (141,941 ) (160,779 ) (671,618 ) Capitalized exploratory well costs charged to expense (6,584 ) (6,051 ) (15,589 ) Balance at December 31 $ 34,852 $ 59,397 $ 93,421 Number of gross wells 54 73 119 As of December 31, 2016 , 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, 2016
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. ("Ryder Scott") prepared reserve estimates for properties comprising approximately 99% , 99% , and 99% of the Company’s discounted future net cash flows (PV-10) as of December 31, 2016 , 2015 , and 2014 , respectively. Properties comprising 99% , 98% , and 98% of total proved reserves were evaluated by Ryder Scott as of December 31, 2016 , 2015 , and 2014 , 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, 2016 , 2015 , and 2014 . 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, 2016 , 2015 and 2014 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, 2016 , 2015 and 2014 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, 2013 737,788 2,078,020 1,084,125 Revisions of previous estimates (67,151 ) (244,783 ) (107,949 ) Extensions, discoveries and other additions 239,526 1,206,569 440,621 Production (44,530 ) (114,295 ) (63,579 ) Sales of minerals in place (123 ) (18,623 ) (3,227 ) Purchases of minerals in place 850 1,498 1,100 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. 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, operating costs or development costs. Downward revisions to proved reserves in 2016 resulted in part from decreases in average commodity prices during the year. The 12-month average price for crude oil decreased 15% from $50.28 per Bbl for 2015 to $42.75 per Bbl for 2016, while the 12-month average price for natural gas decreased 3% from $2.58 per MMBtu for 2015 to $2.49 per MMBtu for 2016. These decreases shortened the economic lives of certain producing properties and caused certain exploration and development projects to become uneconomic which had an adverse impact on the Company's proved reserve estimates, resulting in downward revisions of 20 MMBo and 50 Bcf (totaling 28 MMBoe) in 2016. In response to the prolonged decrease in commodity prices throughout the majority of 2016, the Company further refined its capital program to focus on areas that provide the greatest opportunities to convert undeveloped acreage to acreage held by production, achieve operating efficiencies and cost reductions through multi-well pad drilling, and improve recoveries, cash flows and rates of return using enhanced completions. As part of this effort, the Company shifted a significant portion of its 2016 spending away from the Bakken to areas in Oklahoma that offered more advantageous opportunities. This shift, a longer and more severe decrease in crude oil prices than anticipated, and the Company's increased emphasis on balancing capital spending with cash flows have altered the timing and extent of previous development plans in certain areas and resulted in the removal of 51 MMBo and 118 Bcf (totaling 70 MMBoe) of proved undeveloped reserves no longer scheduled to be developed within five years from the date of initial booking, primarily in the Bakken. Additionally, changes in anticipated production performance on certain properties resulted in 37 MMBo of downward revisions to crude oil proved reserves and 166 Bcf of upward revisions to natural gas proved reserves (netting to 9 MMBoe of downward revisions) in 2016. Further, changes in ownership interests, operating costs, and other factors during 2016 resulted in 7 MMBo of upward revisions to crude oil proved reserves and 61 Bcf of downward revisions to natural gas proved reserves (netting to 3 MMBoe of downward revisions). 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 activity in the Bakken, SCOOP, and STACK plays. Proved reserve additions in the Bakken totaled 55 MMBo and 105 Bcf (totaling 73 MMBoe) and reserve additions in SCOOP totaled 18 MMBo and 475 Bcf (totaling 97 MMBoe) for the year ended December 31, 2016 . Additionally, 2016 extensions and discoveries were significantly impacted by successful drilling results in the STACK play, resulting in proved reserve additions of 24 MMBo and 331 Bcf (totaling 79 MMBoe) in 2016 . 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 notable 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, 2016 , 2015 and 2014 : December 31, 2016 2015 2014 Proved Developed Reserves Crude oil (MBbl) 290,210 326,798 342,137 Natural Gas (MMcf) 1,370,620 1,190,343 962,051 Total (MBoe) 518,646 525,188 502,479 Proved Undeveloped Reserves Crude oil (MBbl) 353,018 373,716 524,223 Natural Gas (MMcf) 2,419,198 1,961,443 1,946,335 Total (MBoe) 756,218 700,623 848,612 Total Proved Reserves Crude oil (MBbl) 643,228 700,514 866,360 Natural Gas (MMcf) 3,789,818 3,151,786 2,908,386 Total (MBoe) 1,274,864 1,225,811 1,351,091 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, 2016 , 2015 and 2014 . December 31, In thousands 2016 2015 2014 Future cash inflows $ 31,008,587 $ 36,551,672 $ 90,867,459 Future production costs (9,175,410 ) (10,869,493 ) (25,799,221 ) Future development and abandonment costs (6,452,647 ) (6,935,958 ) (12,842,174 ) Future income taxes (3,018,839 ) (3,717,612 ) (13,800,737 ) Future net cash flows 12,361,691 15,028,609 38,425,327 10% annual discount for estimated timing of cash flows (6,851,468 ) (8,552,325 ) (19,992,293 ) Standardized measure of discounted future net cash flows $ 5,510,223 $ 6,476,284 $ 18,433,034 The weighted average crude oil price (adjusted for location and quality differentials) utilized in the computation of future cash inflows was $35.57 , $41.63 , and $84.54 per barrel at December 31, 2016 , 2015 and 2014 , respectively. The weighted average natural gas price (adjusted for location and quality differentials) utilized in the computation of future cash inflows was $2.14 , $2.35 , and $6.06 per Mcf at December 31, 2016 , 2015 and 2014 , 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 2016 2015 2014 Standardized measure of discounted future net cash flows at January 1 $ 6,476,284 $ 18,433,034 $ 16,295,767 Extensions, discoveries and improved recoveries, less related costs 786,587 1,091,283 5,516,528 Revisions of previous quantity estimates (794,785 ) (2,156,028 ) (1,755,366 ) Changes in estimated future development and abandonment costs 1,651,218 5,008,731 476,665 Sales of minerals in place, net (90,390 ) (7,768 ) (3,196 ) Net change in prices and production costs (2,003,163 ) (16,111,142 ) (1,925,349 ) Accretion of discount 798,597 1,843,303 1,629,576 Sales of crude oil and natural gas produced, net of production costs (1,595,281 ) (2,002,997 ) (3,500,790 ) Development costs incurred during the period 454,983 1,394,584 2,466,748 Change in timing of estimated future production and other (538,665 ) (3,844,259 ) (309,902 ) Change in income taxes 364,838 2,827,543 (457,647 ) Net change (966,061 ) (11,956,750 ) 2,137,267 Standardized measure of discounted future net cash flows at December 31 $ 5,510,223 $ 6,476,284 $ 18,433,034

Quarterly Financial Data (Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data (Unaudited)	Quarterly Financial Data (Unaudited) The Company’s unaudited quarterly financial data for 2016 and 2015 is summarized below. Quarter ended In thousands, except per share data March 31 June 30 September 30 December 31 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 (3) $ 109 $ 96,907 $ 6,158 $ 201,315 Income (loss) from operations $ (239,103 ) $ (110,547 ) $ (93,183 ) $ 155,299 Loss on extinguishment of debt (4) $ — $ — $ — $ 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 2015 Total revenues (1) $ 625,644 $ 796,374 $ 682,669 $ 575,480 Gain (loss) on crude oil and natural gas derivatives, net (1) $ 32,755 $ (4,737 ) $ 46,527 $ 16,540 Property impairments (2) $ 147,561 $ 76,872 $ 96,697 $ 81,001 Gain on sale of assets, net (3) $ 2,070 $ 20,573 $ 288 $ 218 Income (loss) from operations $ (111,276 ) $ 82,447 $ (52,356 ) $ (142,816 ) Net income (loss) $ (131,971 ) $ 403 $ (82,423 ) $ (139,677 ) Net income (loss) per share: Basic $ (0.36 ) $ — $ (0.22 ) $ (0.38 ) Diluted $ (0.36 ) $ — $ (0.22 ) $ (0.38 ) (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) 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. (4) 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, 2016
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), STACK (Sooner Trend Anadarko Canadian Kingfisher), and Arkoma Woodford areas of Oklahoma. Historically, our properties in Blaine, Dewey and Custer counties of Oklahoma that produced from the Woodford formation were referred to as the Northwest Cana district, while properties often underlying the same surface acreage in those counties that produced from the Meramec and Osage formations were referred to as the STACK district. Such properties were historically combined by us and referred to as "Northwest Cana/STACK". Effective December 31, 2016, we now refer to such properties simply as "STACK". The East region is comprised of undeveloped leasehold acreage east of the Mississippi River with no current drilling or production operations. A substantial portion of the Company’s operations are located in the North region, with that region comprising approximately 61% 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, 2016 . 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, 2016 , approximately 50% of the Company’s estimated proved reserves were located in the North region. In recent years, the Company has significantly expanded its activity in the South region with its discovery of the SCOOP play and its increased activity in the STACK play. The South region comprised approximately 39% 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 at December 31, 2016 . For the year ended December 31, 2016 , crude oil accounted for approximately 59% of the Company’s total production and approximately 82% of its crude oil and natural gas revenues. Crude oil represents approximately 50% of the Company's estimated proved reserves as of December 31, 2016 .
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 period. Actual results may differ from those estimates. The most significant of the estimates and assumptions that affect reported results are the 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, 2016 and 2015 were not material.
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, 2016 , the Company had cash deposits in excess of federally insured amounts of approximately $15.0 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.
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, 2016 , sales to the Company’s largest purchaser accounted for approximately 18% of its total crude oil and natural gas sales. No other purchasers accounted for more than 10% of the Company’s total crude oil and natural gas sales for 2016 . 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 at the lower of cost or market, with cost determined primarily using a weighted average cost method applied to specific classes of inventory items. The components of inventory as of December 31, 2016 and 2015 consisted of the following: December 31, In thousands 2016 2015 Tubular goods and equipment $ 15,243 $ 15,633 Crude oil 96,744 78,518 Total $ 111,987 $ 94,151
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 labor costs to operate the Company’s properties, repairs and maintenance, waste water disposal costs, utility 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 10-40
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.
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 three-year term loan, 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, 2016 and 2015 .
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. 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.
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 loss" within shareholders’ equity on the consolidated balance sheets.
New Accounting Pronouncements	New accounting pronouncements not yet adopted Leases – In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("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 and is in the process of developing systems and processes to identify, classify, and account for leases within the scope of the new guidance. 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. Stock-based compensation – In March 2016, the FASB issued 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 standard is effective for interim and annual reporting periods beginning after December 15, 2016 and will be adopted either prospectively, retrospectively or using a modified retrospective transition approach depending on the topic covered in the standard. The Company will adopt the new standard on January 1, 2017. Under ASU 2016-09, effective January 1, 2017 companies will no longer record excess tax benefits and deficiencies in additional paid-in capital. Instead, excess tax benefits and deficiencies will be recognized as income tax expense or benefit in the income statement. 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. ASU 2016-09 also removes the requirement to delay recognition of an excess tax benefit until it reduces current taxes payable. Under the new guidance, effective January 1, 2017 excess tax benefits will be recorded when they arise. This change is required to be applied on a modified retrospective basis through a cumulative effect adjustment to retained earnings upon adoption. The Company estimates its cumulative effect adjustment will result in an approximate $5 million increase to retained earnings upon adoption of ASU 2016-09 on January 1, 2017. Additionally, the Company expects to recognize approximately $4 million of tax deficiencies as income tax expense in the first quarter of 2017 under the new standard. The Company will continue its current accounting practice of estimating forfeitures in determining the amount of stock-based compensation expense to recognize. Therefore, the adoption of ASU 2016-09 is not expected to have an impact on stock-based compensation expense to be recognized on non-vested restricted stock awards. 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 has 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 will be 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 plans to adopt the standard on January 1, 2018 using a modified retrospective approach. 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 is expected to impact the presentation of future 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 is expected to result in future revenues and associated transportation expenses for certain of the Company's arrangements being reported on a gross basis. The Company expects 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, 2016 , the Company estimates it had approximately $230 million of transportation related charges included in "Crude oil and natural gas sales" on the consolidated statements of comprehensive income (loss). The Company is not currently 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. 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. Early adoption is permitted. The Company has elected to early adopt ASU 2017-01 on January 1, 2017 and will apply the new guidance to applicable transactions occurring after that date. 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 is currently evaluating the new standard and is unable to estimate its financial statement impact at this time.

Organization and Summary of S25

Organization and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Components of Inventories	The components of inventory as of December 31, 2016 and 2015 consisted of the following: December 31, In thousands 2016 2015 Tubular goods and equipment $ 15,243 $ 15,633 Crude oil 96,744 78,518 Total $ 111,987 $ 94,151
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 10-40
Summary of Changes in Future Abandonment Liabilities	The following table summarizes the changes in the Company’s future abandonment liabilities from January 1, 2014 through December 31, 2016 : In thousands 2016 2015 2014 Asset retirement obligations at January 1 $ 102,909 $ 76,708 $ 55,787 Accretion expense 6,086 4,740 3,366 Revisions (1) (12,755 ) 15,068 9,916 Plus: Additions for new assets 2,692 7,404 9,022 Less: Plugging costs and sold assets (2,754 ) (1,011 ) (1,383 ) Total asset retirement obligations at December 31 $ 96,178 $ 102,909 $ 76,708 Less: Current portion of asset retirement obligations at December 31 (2) 1,742 1,658 1,246 Non-current portion of asset retirement obligations at December 31 $ 94,436 $ 101,251 $ 75,462 (1) Revisions for the year ended December 31, 2016 primarily represent a decrease in the present value of liabilities resulting from a deferral of the estimated future timing of abandonment prompted by an increase in the economic lives of certain 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	he 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, 2016 , 2015 and 2014 . Year ended December 31, In thousands, except per share data 2016 2015 2014 Income (loss) (numerator): Net income (loss) - basic and diluted $ (399,679 ) $ (353,668 ) $ 977,341 Weighted average shares (denominator): Weighted average shares - basic 370,380 369,540 368,829 Non-vested restricted stock (1) — — 1,929 Weighted average shares - diluted 370,380 369,540 370,758 Net income (loss) per share: Basic $ (1.08 ) $ (0.96 ) $ 2.65 Diluted $ (1.08 ) $ (0.96 ) $ 2.64 (1) 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, 2016
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 2016 2015 2014 Supplemental cash flow information: Cash paid for interest $ 316,116 $ 301,743 $ 267,384 Cash paid for income taxes 2 30 53,457 Cash received for income tax refunds 174 61,403 7 Non-cash investing activities: Asset retirement obligation additions and revisions, net (10,063 ) 22,472 18,938

Net Property and Equipment (Tab

Net Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment, Net [Abstract]
Schedule of Net Property and Equipment	Net property and equipment includes the following at December 31, 2016 and 2015 . For the year ended December 31, 2016 , capital expenditures of $1.1 billion were offset by the removal of $804 million of costs associated with asset sales and $234 million of impairments of unproved properties, resulting in a minimal change in gross property and equipment during the year. December 31, In thousands 2016 2015 Proved crude oil and natural gas properties $ 19,802,395 $ 19,520,724 Unproved crude oil and natural gas properties 429,562 682,988 Service properties, equipment and other 301,788 307,059 Total property and equipment 20,533,745 20,510,771 Accumulated depreciation, depletion and amortization (7,652,518 ) (6,447,443 ) Net property and equipment $ 12,881,227 $ 14,063,328

Accrued Liabilities and Other (

Accrued Liabilities and Other (Tables)	12 Months Ended
	Dec. 31, 2016
Accrued Liabilities and Other Liabilities [Abstract]
Schedule of Accrued Liabilities and Other	Accrued liabilities and other includes the following at December 31, 2016 and 2015 : December 31, In thousands 2016 2015 Prepaid advances from joint interest owners $ 57,861 $ 49,917 Accrued compensation 38,046 40,060 Accrued production taxes, ad valorem taxes and other non-income taxes 22,053 21,678 Accrued interest 52,657 62,058 Current portion of asset retirement obligations 1,742 1,658 Other 4,411 1,576 Accrued liabilities and other $ 176,770 $ 176,947

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2016
Derivative [Line Items]
Summary of Outstanding Contracts with Respect to Natural Gas	Swaps Weighted Average Price Floors Ceilings Weighted Average Price Weighted Average Price Period and Type of Contract MMBtus Range Range January 2017 - December 2017 Swaps - Henry Hub 72,690,000 $ 3.41 Collars - Henry Hub 65,700,000 $2.40 - $3.00 $ 2.47 $2.92 - $3.88 $ 3.08
Realized and Unrealized Gains and Losses on Derivative Instruments	Year ended December 31, In thousands 2016 2015 2014 Cash received (paid) on derivatives: Crude oil fixed price swaps (1) $ — $ — $ 331,591 Crude oil collars (1) — — 65,310 Natural gas fixed price swaps 88,823 39,670 (11,551 ) Natural gas collars — 29,883 — Cash received on derivatives, net 88,823 69,553 385,350 Non-cash gain (loss) on derivatives: Crude oil fixed price swaps — — 84,792 Crude oil collars — — 1,121 Crude oil written call options 38 4,715 3,981 Natural gas fixed price swaps (120,784 ) 41,828 62,699 Natural gas collars (39,936 ) (25,011 ) 21,816 Non-cash gain (loss) on derivatives, net (160,682 ) 21,532 174,409 Gain (loss) on crude oil and natural gas derivatives, net $ (71,859 ) $ 91,085 $ 559,759 (1) Net cash receipts for crude oil swaps and collars for the year ended December 31, 2014 include $433 million of proceeds received from crude oil derivative contracts that were settled in the fourth quarter of 2014 prior to their contractual maturities. Of the proceeds, $373 million related to crude oil swap liquidations and $60 million related to crude oil collar liquidations.
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, 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 2016 2015 Commodity derivative assets: Gross amounts of recognized assets $ 4,061 $ 120,385 Gross amounts offset on balance sheet — (11,903 ) Net amounts of assets on balance sheet 4,061 108,482 Commodity derivative liabilities: Gross amounts of recognized liabilities (59,489 ) (19,192 ) Gross amounts offset on balance sheet — 11,903 Net amounts of liabilities on balance sheet $ (59,489 ) $ (7,289 )
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 2016 2015 Derivative assets $ 4,061 $ 93,922 Noncurrent derivative assets — 14,560 Net amounts of assets on balance sheet 4,061 108,482 Derivative liabilities (59,489 ) (3,583 ) Noncurrent derivative liabilities — (3,706 ) Net amounts of liabilities on balance sheet (59,489 ) (7,289 ) Total derivative assets (liabilities), net $ (55,428 ) $ 101,193

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 and 2015 . Fair value measurements at December 31, 2016 using: In thousands Level 1 Level 2 Level 3 Total Derivative liabilities: Fixed price swaps $ — $ (12,297 ) $ — $ (12,297 ) Collars — (43,131 ) — (43,131 ) Total $ — $ (55,428 ) $ — $ (55,428 ) Fair value measurements at December 31, 2015 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets (liabilities): Fixed price swaps $ — $ 104,426 $ — $ 104,426 Collars — (3,195 ) — (3,195 ) Written call options — (38 ) $ — (38 ) Total $ — $ 101,193 $ — $ 101,193
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 swap prices through 2021 (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 0 to 40 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 2016 2015 2014 Proved property impairments $ 2,895 $ 138,878 $ 324,302 Unproved property impairments 234,397 263,253 292,586 Total $ 237,292 $ 402,131 $ 616,888
Fair Values of Financial Instruments not Recorded at Fair Value	The following table sets forth the fair values of financial instruments that are not recorded at fair value in the consolidated financial statements. December 31, 2016 December 31, 2015 In thousands Carrying Amount Fair Value Carrying Amount Fair Value Debt: Revolving credit facility $ 905,000 $ 905,000 $ 853,000 $ 853,000 Term loan 498,865 500,000 498,274 500,000 Note payable 12,176 10,200 14,309 12,500 7.375% Senior Notes due 2020 (1) — — 196,574 179,200 7.125% Senior Notes due 2021 (1) — — 395,365 388,300 5% Senior Notes due 2022 1,997,188 2,020,400 1,996,831 1,480,400 4.5% Senior Notes due 2023 1,484,524 1,474,800 1,482,451 1,061,000 3.8% Senior Notes due 2024 990,964 929,400 989,932 700,300 4.9% Senior Notes due 2044 691,199 607,600 691,052 430,500 Total debt $ 6,579,916 $ 6,447,400 $ 7,117,788 $ 5,605,200 (1) The Company redeemed the 7.375% Senior Notes due 2020 and the 7.125% Senior Notes due 2021 on November 10, 2016. See Note 7. Long-Term Debt for further discussion of the redemptions.

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Long-Term Debt	Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $37.3 million and $49.6 million at December 31, 2016 and 2015 , respectively, consists of the following. December 31, In thousands 2016 2015 Revolving credit facility $ 905,000 $ 853,000 Term loan 498,865 498,274 Note payable 12,176 14,309 7.375% Senior Notes due 2020 (1) — 196,574 7.125% Senior Notes due 2021 (1) — 395,365 5% Senior Notes due 2022 1,997,188 1,996,831 4.5% Senior Notes due 2023 1,484,524 1,482,451 3.8% Senior Notes due 2024 990,964 989,932 4.9% Senior Notes due 2044 691,199 691,052 Total debt 6,579,916 7,117,788 Less: Current portion of long-term debt 2,219 2,144 Long-term debt, net of current portion $ 6,577,697 $ 7,115,644 (1) The Company redeemed the 7.375% Senior Notes due 2020 and the 7.125% Senior Notes due 2021 on November 10, 2016 as discussed below.
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, 2016 . 2022 Notes 2023 Notes 2024 Notes 2044 Notes Face value (in thousands) $2,000,000 $1,500,000 $1,000,000 $700,000 Maturity date Sep 15, 2022 April 15, 2023 June 1, 2024 June 1, 2044 Interest payment dates March 15, Sep 15 April 15, Oct 15 June 1, Dec 1 June 1, Dec 1 Call premium redemption period (1) March 15, 2017 — — — Make-whole redemption period (2) March 15, 2017 Jan 15, 2023 Mar 1, 2024 Dec 1, 2043 (1) On or after this date, the Company has the option to redeem all or a portion of its 2022 Notes at the decreasing redemption prices specified in the indenture to the 2022 Notes plus any accrued and unpaid interest to the date of redemption. (2) At any time prior to these 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.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Provision for Income Taxes	The items comprising the provision (benefit) for income taxes are as follows for the periods presented: Year ended December 31, In thousands 2016 2015 2014 Current income tax provision (benefit): United States federal (1) (22,941 ) — — Various states 2 24 20 Total current income tax provision (benefit) (22,939 ) 24 20 Deferred income tax provision (benefit): United States federal (182,422 ) (140,578 ) 527,315 Various states (27,414 ) (40,863 ) 57,362 Total deferred income tax provision (benefit) (209,836 ) (181,441 ) 584,677 Provision (benefit) for income taxes $ (232,775 ) $ (181,417 ) $ 584,697
Schedule of Provision for Income Taxes with Income Tax at Federal Statutory Rate	Year ended December 31, In thousands 2016 2015 2014 Expected income tax expense (benefit) based on US statutory tax rate of 35% $ (221,359 ) $ (187,280 ) $ 546,713 State income taxes, net of federal benefit (18,829 ) (16,219 ) 42,169 Canadian valuation allowance 1,044 13,503 4,389 Effect of differing statutory tax rate in Canada 481 5,239 (1,900 ) Other, net 5,888 3,340 (6,674 ) Provision (benefit) for income taxes $ (232,775 ) $ (181,417 ) $ 584,697
Components of Deferred Tax Assets and Liabilities	The components of the Company’s deferred tax assets and deferred tax liabilities as of December 31, 2016 and 2015 are reflected in the table below. December 31, In thousands 2016 2015 Deferred tax assets United States net operating loss carryforwards 478,975 398,024 Canadian net operating loss carryforwards 18,936 17,892 Alternative minimum tax carryforwards 16,663 40,796 Equity compensation 32,924 32,910 Non-cash losses on derivatives 21,064 — Other 11,466 11,048 Total deferred tax assets 580,028 500,670 Canadian valuation allowance (18,936 ) (17,892 ) Total deferred tax assets, net of valuation allowance 561,092 482,778 Deferred tax liabilities Property and equipment (2,448,450 ) (2,528,125 ) Non-cash gains on derivatives — (38,452 ) Gain on derivative liquidation — (4,158 ) Other (2,947 ) (2,271 ) Total deferred tax liabilities (2,451,397 ) (2,573,006 ) Deferred income tax liabilities, net $ (1,890,305 ) $ (2,090,228 )

Lease Commitments (Tables)

Lease Commitments (Tables)	12 Months Ended
	Dec. 31, 2016
Leases [Abstract]
Schedule of Minimum Future Rental Commitments Under Operating Leases	At December 31, 2016 , the minimum future rental commitments under operating leases having lease terms in excess of one year are as follows: In thousands Total amount 2017 $ 1,624 2018 1,376 2019 746 2020 643 2021 476 Thereafter 7,629 Total obligations $ 12,494

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2016
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 $48.1 million , $51.8 million , and $54.4 million for the years ended December 31, 2016 , 2015 and 2014 , 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, 2013 to December 31, 2016 is presented below. Number of Weighted Non-vested restricted shares at December 31, 2013 2,714,312 $ 37.50 Granted 1,424,764 61.11 Vested (1,007,166 ) 35.91 Forfeited (453,146 ) 44.90 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

Accumulated Other Comprehensi35

Accumulated Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2016
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 loss for the years ended December 31, 2016 , 2015 , and 2014 : Year ended December 31, In thousands 2016 2015 2014 Beginning accumulated other comprehensive loss, net of tax $ (3,354 ) $ (385 ) $ — Foreign currency translation adjustments 3,094 (2,969 ) (385 ) Income taxes (1) — — — Other comprehensive income (loss), net of tax 3,094 (2,969 ) (385 ) Ending accumulated other comprehensive loss, net of tax $ (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).

Crude Oil and Natural Gas Pro36

Crude Oil and Natural Gas Property Information (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 , 2015 and 2014 . Year ended December 31, In thousands 2016 2015 2014 Crude oil and natural gas sales $ 2,026,958 $ 2,552,531 $ 4,203,022 Production expenses (289,289 ) (348,897 ) (352,472 ) Production taxes and other expenses (142,388 ) (200,637 ) (349,760 ) Exploration expenses (16,972 ) (19,413 ) (50,067 ) Depreciation, depletion, amortization and accretion (1,679,485 ) (1,722,336 ) (1,338,351 ) Property impairments (237,292 ) (402,131 ) (616,888 ) Income tax benefit (provision) 126,794 33,680 (559,311 ) Results from crude oil and natural gas producing activities $ (211,674 ) $ (107,203 ) $ 936,173
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, 2016 , 2015 and 2014 are presented below: Year ended December 31, In thousands 2016 2015 2014 Property acquisition costs: Proved $ 5,008 $ 557 $ 48,917 Unproved 149,962 168,492 409,529 Total property acquisition costs 154,970 169,049 458,446 Exploration Costs 182,355 241,523 863,606 Development Costs 767,148 2,148,530 3,670,448 Total $ 1,104,473 $ 2,559,102 $ 4,992,500
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, 2016 and 2015 are as follows: December 31, In thousands 2016 2015 Proved crude oil and natural gas properties $ 19,802,395 $ 19,520,724 Unproved crude oil and natural gas properties 429,562 682,988 Total 20,231,957 20,203,712 Less accumulated depreciation, depletion and amortization (7,553,255 ) (6,374,218 ) Net capitalized costs $ 12,678,702 $ 13,829,494
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 2016 2015 2014 Balance at January 1 $ 59,397 $ 93,421 $ 152,775 Additions to capitalized exploratory well costs pending determination of proved reserves 123,980 132,806 627,853 Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves (141,941 ) (160,779 ) (671,618 ) Capitalized exploratory well costs charged to expense (6,584 ) (6,051 ) (15,589 ) Balance at December 31 $ 34,852 $ 59,397 $ 93,421 Number of gross wells 54 73 119

Supplemental Crude Oil and Na37

Supplemental Crude Oil and Natural Gas Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2013 737,788 2,078,020 1,084,125 Revisions of previous estimates (67,151 ) (244,783 ) (107,949 ) Extensions, discoveries and other additions 239,526 1,206,569 440,621 Production (44,530 ) (114,295 ) (63,579 ) Sales of minerals in place (123 ) (18,623 ) (3,227 ) Purchases of minerals in place 850 1,498 1,100 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
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, 2016 , 2015 and 2014 : December 31, 2016 2015 2014 Proved Developed Reserves Crude oil (MBbl) 290,210 326,798 342,137 Natural Gas (MMcf) 1,370,620 1,190,343 962,051 Total (MBoe) 518,646 525,188 502,479 Proved Undeveloped Reserves Crude oil (MBbl) 353,018 373,716 524,223 Natural Gas (MMcf) 2,419,198 1,961,443 1,946,335 Total (MBoe) 756,218 700,623 848,612 Total Proved Reserves Crude oil (MBbl) 643,228 700,514 866,360 Natural Gas (MMcf) 3,789,818 3,151,786 2,908,386 Total (MBoe) 1,274,864 1,225,811 1,351,091
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, 2016 , 2015 and 2014 . December 31, In thousands 2016 2015 2014 Future cash inflows $ 31,008,587 $ 36,551,672 $ 90,867,459 Future production costs (9,175,410 ) (10,869,493 ) (25,799,221 ) Future development and abandonment costs (6,452,647 ) (6,935,958 ) (12,842,174 ) Future income taxes (3,018,839 ) (3,717,612 ) (13,800,737 ) Future net cash flows 12,361,691 15,028,609 38,425,327 10% annual discount for estimated timing of cash flows (6,851,468 ) (8,552,325 ) (19,992,293 ) Standardized measure of discounted future net cash flows $ 5,510,223 $ 6,476,284 $ 18,433,034
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 2016 2015 2014 Standardized measure of discounted future net cash flows at January 1 $ 6,476,284 $ 18,433,034 $ 16,295,767 Extensions, discoveries and improved recoveries, less related costs 786,587 1,091,283 5,516,528 Revisions of previous quantity estimates (794,785 ) (2,156,028 ) (1,755,366 ) Changes in estimated future development and abandonment costs 1,651,218 5,008,731 476,665 Sales of minerals in place, net (90,390 ) (7,768 ) (3,196 ) Net change in prices and production costs (2,003,163 ) (16,111,142 ) (1,925,349 ) Accretion of discount 798,597 1,843,303 1,629,576 Sales of crude oil and natural gas produced, net of production costs (1,595,281 ) (2,002,997 ) (3,500,790 ) Development costs incurred during the period 454,983 1,394,584 2,466,748 Change in timing of estimated future production and other (538,665 ) (3,844,259 ) (309,902 ) Change in income taxes 364,838 2,827,543 (457,647 ) Net change (966,061 ) (11,956,750 ) 2,137,267 Standardized measure of discounted future net cash flows at December 31 $ 5,510,223 $ 6,476,284 $ 18,433,034

Quarterly Financial Data (Una38

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Schedule Of Quarterly Financial Data	The Company’s unaudited quarterly financial data for 2016 and 2015 is summarized below. Quarter ended In thousands, except per share data March 31 June 30 September 30 December 31 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 (3) $ 109 $ 96,907 $ 6,158 $ 201,315 Income (loss) from operations $ (239,103 ) $ (110,547 ) $ (93,183 ) $ 155,299 Loss on extinguishment of debt (4) $ — $ — $ — $ 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 2015 Total revenues (1) $ 625,644 $ 796,374 $ 682,669 $ 575,480 Gain (loss) on crude oil and natural gas derivatives, net (1) $ 32,755 $ (4,737 ) $ 46,527 $ 16,540 Property impairments (2) $ 147,561 $ 76,872 $ 96,697 $ 81,001 Gain on sale of assets, net (3) $ 2,070 $ 20,573 $ 288 $ 218 Income (loss) from operations $ (111,276 ) $ 82,447 $ (52,356 ) $ (142,816 ) Net income (loss) $ (131,971 ) $ 403 $ (82,423 ) $ (139,677 ) Net income (loss) per share: Basic $ (0.36 ) $ — $ (0.22 ) $ (0.38 ) Diluted $ (0.36 ) $ — $ (0.22 ) $ (0.38 ) (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) 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. (4) 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 ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Organization And Summary Of Significant Accounting Policies [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption on Retained Earnings, Quantification	$ 5,000
Allowance for Doubtful Accounts Receivable		$ 3,000	$ 2,300
Unamortized Debt Issuance Expense		50,400	64,100
Unamortized Debt Issuance Expense Written Off		6,100
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount		$ 1,044	13,503	$ 4,389
Percentage of operations concentrated in geographical areas		61.00%
Percentage of estimated proved reserves in north region		50.00%
Percentage of crude oil and natural gas production concentrated in south region		39.00%
Percentage of estimated proved reserves in south region		50.00%
Percentage Of Crude Oil And Natural Gas Production Concentrated In Crude Oil		59.00%
Percentage Of Crude Oil and Natural Gas Revenue Concentrated in Crude Oil		82.00%
Cash deposits in excess of federally insured amounts		$ 15,000
Net asset retirement costs		77,900	87,500
Capitalized debt issue costs, relating to long-term debt		55,900	71,800
Accumulated amortization, relating to capitalized debt issue costs		56,800	47,000
Amortization expense related to capitalized debt issuance costs		$ 9,800	8,900	$ 9,300
Percentage Of Estimated Proved Reserves Concentrated In Crude Oil		50.00%
Deferred Tax Assets, Valuation Allowance		$ (18,936)	(17,892)
New Accounting Pronouncement or Change in Accounting Principle, Effect of Change on Net Income	$ 4,000
Transportation Costs		230,000
Revolving Credit Facility [Member]
Organization And Summary Of Significant Accounting Policies [Line Items]
Unamortized Debt Issuance Expense		$ 5,500	$ 7,700
7 3/8% Senior Notes due 2020 [Member]
Organization And Summary Of Significant Accounting Policies [Line Items]
Debt instrument interest percentage		7.375%
7 1/8% Senior Notes due 2021 [Member]
Organization And Summary Of Significant Accounting Policies [Line Items]
Debt instrument interest percentage		7.125%
5% Senior Notes due 2022 [Member]
Organization And Summary Of Significant Accounting Policies [Line Items]
Debt instrument interest percentage		5.00%
4.5% Senior Notes due 2023 [Member]
Organization And Summary Of Significant Accounting Policies [Line Items]
Debt instrument interest percentage		4.50%
Largest Customer [Member] | Oil And Natural Gas [Member] | Sales [Member]
Organization And Summary Of Significant Accounting Policies [Line Items]
Percentage of crude oil sales to one single purchaser accounted on total revenues		18.00%
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%

Organization and Summary of S40

Organization and Summary of Significant Accounting Policies - Components of Inventories (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Tubular goods and equipment	$ 15,243	$ 15,633
Crude oil	96,744	78,518
Total	$ 111,987	$ 94,151

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, 2016
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)	10 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, 2016	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations at January 1		$ 102,909	$ 76,708	$ 55,787
Accretion expense		6,086	4,740	3,366
Revisions	[1]	(12,755)	15,068	9,916
Plus: Additions for new assets		2,692	7,404	9,022
Less: Plugging costs and sold assets		(2,754)	(1,011)	(1,383)
Total asset retirement obligations at December 31		96,178	102,909	76,708
Less: Current portion of asset retirement obligations at December 31	[2]	1,742	1,658	1,246
Non-current portion of asset retirement obligations at December 31		$ 94,436	$ 101,251	$ 75,462
[1]	Revisions for the year ended December 31, 2016 primarily represent a decrease in the present value of liabilities resulting from a deferral of the estimated future timing of abandonment prompted by an increase in the economic lives of certain 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, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016		Dec. 31, 2015	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Weighted average number diluted shares excluded from calculation									2,303,000		1,567,000
Income (numerator):
Net income - basic and diluted	$ 27,670	$ (109,621)	$ (119,402)	$ (198,326)	$ (139,677)	$ (82,423)	$ 403	$ (131,971)	$ (399,679)		$ (353,668)	$ 977,341
Weighted average shares - basic									370,380,000		369,540,000	368,829,000
Non-vested restricted stock									0	[1]	0	1,929,000
Weighted average shares - diluted									370,380,000		369,540,000	370,758,000
Net income per share:
Basic (in dollars per share)	$ 0.07	$ (0.30)	$ (0.32)	$ (0.54)	$ (0.38)	$ (0.22)	$ 0	$ (0.36)	$ (1.08)		$ (0.96)	$ 2.65
Diluted (in dollars per share)	$ 0.07	$ (0.30)	$ (0.32)	$ (0.54)	$ (0.38)	$ (0.22)	$ 0	$ (0.36)	$ (1.08)		$ (0.96)	$ 2.64
[1]	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, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Cash Flow Information [Abstract]
Capital Expenditures Incurred but Not yet Paid	$ 223,600	$ 282,800	$ 797,500	$ 507,000
Supplemental cash flow information:
Cash paid for interest	316,116	301,743	267,384
Cash paid for income taxes	2	30	53,457
Cash received for income tax refunds	174	61,403	7
Asset Retirement Obligation, Additions or Revisions	$ (10,063)	$ 22,472	$ 18,938

Net Property and Equipment - Sc

Net Property and Equipment - Schedule of Net Property and Equipment (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment, Net [Abstract]
Capital Expenditures	$ 1,100,000
Property, Plant and Equipment, Disposals	804,000
Unproved property impairments	234,397	$ 263,253	$ 292,586
Proved crude oil and natural gas properties	19,802,395	19,520,724
Unproved crude oil and natural gas properties	429,562	682,988
Service properties, equipment and other	301,788	307,059
Total property and equipment	20,533,745	20,510,771
Accumulated depreciation, depletion and amortization	(7,652,518)	(6,447,443)
Net property and equipment	$ 12,881,227	$ 14,063,328	$ 14,063,328

Accrued Liabilities and Other -

Accrued Liabilities and Other - Schedule of Accrued Liabilities and Other (Detail) - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Accrued Liabilities and Other Liabilities [Abstract]
Prepaid advances from joint interest owners		$ 57,861	$ 49,917
Accrued compensation		38,046	40,060
Accrued production taxes, ad valorem taxes and other non-income taxes		22,053	21,678
Accrued interest		52,657	62,058
Current portion of asset retirement obligations	[1]	1,742	1,658	$ 1,246
Other		4,411	1,576
Accrued liabilities and other		$ 176,770	$ 176,947
[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) - Natural Gas [Member]	12 Months Ended
	Dec. 31, 2016MMBTU$ / MMBTU$ / bbl
January 2017 to December 2017 Swaps [Member]
Derivative [Line Items]
Natural Gas Production Derivative Volume, MMBtus | MMBTU	72,690,000
Swaps Weighted Average Price | $ / MMBTU	3.41
January 2017 to December 2017 Collars [Member]
Derivative [Line Items]
Derivative, Average Cap Price	3.08
Natural Gas Production Derivative Volume, MMBtus | MMBTU	65,700,000
Derivative, Average Floor Price	2.47
Maximum [Member] | January 2017 to December 2017 Collars [Member]
Derivative [Line Items]
Derivative, Floor Price	3
Derivative, Cap Price	3.88
Minimum [Member] | January 2017 to December 2017 Collars [Member]
Derivative [Line Items]
Derivative, Floor Price	2.40
Derivative, Cap Price	2.92

Derivative Instruments - Realiz

Derivative Instruments - Realized and Unrealized Gains and Losses on Derivative Instruments (Detail) $ in Thousands, gal in Millions	3 Months Ended																12 Months Ended
	Dec. 31, 2016USD ($)$ / gal		Sep. 30, 2016USD ($)	[1]	Jun. 30, 2016USD ($)	[1]	Mar. 31, 2016USD ($)	[1]	Dec. 31, 2015USD ($)	[1]	Sep. 30, 2015USD ($)	[1]	Jun. 30, 2015USD ($)	[1]	Mar. 31, 2015USD ($)	[1]	Dec. 31, 2016USD ($)$ / galgal	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Derivatives, Fair Value [Line Items]
Cash Proceeds from Liquidated Derivatives																		$ 433,000
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net																	$ (156,621)	21,532	$ 174,409
Gain (loss) on crude oil and natural gas derivatives, net	$ (47,382)	[1]	$ 15,668		$ (82,257)		$ 42,112		$ 16,540		$ 46,527		$ (4,737)		$ 32,755		(71,859)	91,085	559,759
Fuel [Member]
Cash received (paid) on derivatives:
Cash received on derivatives, net																	700
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net																	4,100
Fixed Price Swaps [Member] | Crude Oil [Member]
Derivatives, Fair Value [Line Items]
Cash Proceeds from Liquidated Derivatives																		373,000
Cash received (paid) on derivatives:
Cash received on derivatives, net																	0	0	331,591
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net																	0	0	84,792
Fixed Price Swaps [Member] | Natural Gas [Member]
Cash received (paid) on derivatives:
Cash received on derivatives, net																	88,823	39,670	(11,551)
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net																	(120,784)	41,828	62,699
Collars [Member] | Crude Oil [Member]
Derivatives, Fair Value [Line Items]
Cash Proceeds from Liquidated Derivatives																		60,000
Cash received (paid) on derivatives:
Cash received on derivatives, net																	0	0	65,310
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net																	0	0	1,121
Collars [Member] | Natural Gas [Member]
Cash received (paid) on derivatives:
Cash received on derivatives, net																	0	29,883	0
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net																	(39,936)	(25,011)	21,816
Call Option [Member] | Crude Oil [Member]
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net																	$ 38	4,715	3,981
July 2016 to December 2017 Swaps [Member] | Fuel [Member]
Non-cash gain (loss) on derivatives:
Derivative, Nonmonetary Notional Amount, Volume | gal																	12
Swaps Weighted Average Price | $ / gal	1.43																1.43
Crude Oil and Natural Gas
Cash received (paid) on derivatives:
Cash received on derivatives, net																	$ 88,823	69,553	385,350	[2]
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net																	(160,682)	21,532	174,409
Gain (loss) on crude oil and natural gas derivatives, net																	$ (71,859)	$ 91,085	$ 559,759
[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]	Net cash receipts for crude oil swaps and collars for the year ended December 31, 2014 include $433 million of proceeds received from crude oil derivative contracts that were settled in the fourth quarter of 2014 prior to their contractual maturities. Of the proceeds, $373 million related to crude oil swap liquidations and $60 million related to crude oil collar liquidations.

Derivative Instruments Derivati

Derivative Instruments Derivative Instruments - Gross Amounts of Recognized Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
Commodity derivative assets, Gross amounts of recognized assets	$ 4,061	$ 120,385
Commodity derivative assets, Gross amounts offset on balance sheet	0	(11,903)
Derivative assets, Net amounts of assets on balance sheet	4,061	108,482
Commodity derivative liability, Gross amounts of recognized liabilities	(59,489)	(19,192)
Commodity derivative liability, Gross amounts offset on balance sheet	0	11,903
Derivative liability, Net amounts of liabilities on balance sheet	$ (59,489)	$ (7,289)

Derivative Instruments Deriva50

Derivative Instruments Derivative Instruments - Reconciles Net Amounts Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative assets	$ 4,061	$ 93,922
Noncurrent derivative assets	0	14,560
Derivative assets, Net amounts of assets on balance sheet	4,061	108,482
Derivative liabilities	(59,489)	(3,583)
Noncurrent derivative liabilities	0	(3,706)
Derivative liability, Net amounts of liabilities on balance sheet	(59,489)	(7,289)
Total derivative assets (liabilities), net	$ (55,428)	$ 101,193

Fair Value Measurements - Valua

Fair Value Measurements - Valuation of Financial Instruments by Pricing Levels (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Derivative assets (liabilities):
Derivative assets (liabilities)	$ (55,428)	$ 101,193
Swap [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	(12,297)	104,426
Collars [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	(43,131)	(3,195)
Call Option [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)		(38)
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	0
Fair Value, Inputs, Level 1 [Member] | Call Option [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)		0
Fair Value, Inputs, Level 2 [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	(55,428)	101,193
Fair Value, Inputs, Level 2 [Member] | Fixed Price Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	(12,297)	104,426
Fair Value, Inputs, Level 2 [Member] | Collars [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	(43,131)	(3,195)
Fair Value, Inputs, Level 2 [Member] | Call Option [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)		(38)
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	0
Fair Value, Inputs, Level 3 [Member] | Call Option [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, 2016	Dec. 31, 2015	Dec. 31, 2014	Sep. 30, 2016
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	$ 2,895	$ 138,878	$ 324,302
Estimated fair value of proved properties				$ 700
Minimum [Member]
Fair Value Measurements [Line Items]
Productive life of field (in years)	0 years
Maximum [Member]
Fair Value Measurements [Line Items]
Productive life of field (in years)	40 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, 2016

[1]

Sep. 30, 2016

Jun. 30, 2016

[1]

Mar. 31, 2016

[1]

Dec. 31, 2015

[1]

Sep. 30, 2015

[1]

Jun. 30, 2015

[1]

Mar. 31, 2015

[1]

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

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

Proved property impairments

$ 2,895

$ 138,878

$ 324,302

Unproved property impairments

234,397

263,253

292,586

Total

$ 34,564

$ 57,689

[1]

$ 66,112

$ 78,927

$ 81,001

$ 96,697

$ 76,872

$ 147,561

$ 237,292

$ 402,131

$ 616,888

Estimated fair value of proved properties

$ 700

[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, 2016	Dec. 31, 2015
Fair Value Measurements [Line Items]
Term Loan	$ 500,000
7 3/8% Senior Notes due 2020 [Member]
Fair Value Measurements [Line Items]
Debt instrument, maturity date	2,020
Debt instrument, stated interest rate	7.375%
7 1/8% Senior Notes due 2021 [Member]
Fair Value Measurements [Line Items]
Debt instrument, maturity date	2,021
Debt instrument, stated interest rate	7.125%
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		$ 989,932
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		691,052
Carrying Amount [Member]
Fair Value Measurements [Line Items]
Revolving credit facility	$ 905,000	853,000
Term Loan	498,865	498,274
Note payable	12,176	14,309
Total debt	6,579,916	7,117,788
Carrying Amount [Member] | 7 3/8% Senior Notes due 2020 [Member]
Fair Value Measurements [Line Items]
Senior notes	0	196,574
Carrying Amount [Member] | 7 1/8% Senior Notes due 2021 [Member]
Fair Value Measurements [Line Items]
Senior notes	0	395,365
Carrying Amount [Member] | 5% Senior Notes due 2022 [Member]
Fair Value Measurements [Line Items]
Senior notes	1,997,188	1,996,831
Carrying Amount [Member] | 4 1/2% Senior Notes due 2023 [Member]
Fair Value Measurements [Line Items]
Senior notes	1,484,524	1,482,451
Carrying Amount [Member] | 3.8% Senior Notes due 2024 [Member]
Fair Value Measurements [Line Items]
Senior notes	990,964	989,932
Carrying Amount [Member] | 4.9% Senior Notes due 2044 [Member]
Fair Value Measurements [Line Items]
Senior notes	691,199	691,052
Fair Value [Member]
Fair Value Measurements [Line Items]
Revolving credit facility	905,000	853,000
Term loan	500,000	500,000
Note payable	10,200	12,500
Total debt	6,447,400	5,605,200
Fair Value [Member] | 7 3/8% Senior Notes due 2020 [Member]
Fair Value Measurements [Line Items]
Senior notes	0	179,200
Fair Value [Member] | 7 1/8% Senior Notes due 2021 [Member]
Fair Value Measurements [Line Items]
Senior notes	0	388,300
Fair Value [Member] | 5% Senior Notes due 2022 [Member]
Fair Value Measurements [Line Items]
Senior notes	2,020,400	1,480,400
Fair Value [Member] | 4 1/2% Senior Notes due 2023 [Member]
Fair Value Measurements [Line Items]
Senior notes	1,474,800	1,061,000
Fair Value [Member] | 3.8% Senior Notes due 2024 [Member]
Fair Value Measurements [Line Items]
Senior notes	929,400	700,300
Fair Value [Member] | 4.9% Senior Notes due 2044 [Member]
Fair Value Measurements [Line Items]
Senior notes	$ 607,600	$ 430,500

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		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Nov. 10, 2016	Jul. 11, 2014
Debt Instrument [Line Items]
Unamortized Loan Commitment and Origination Fees and Unamortized Discounts or Premiums	$ 37,300		$ 37,300	$ 49,600
Total Redemption Amount						$ 623,900	$ 317,500
Less: Current portion of long-term debt	(2,219)		(2,219)	(2,144)
Long-term debt, net of current portion	6,577,697		6,577,697	7,115,644
Loss on extinguishment of debt	26,055	[1]	(26,055)	0	$ (24,517)
Term Loan	$ 500,000		$ 500,000
7 3/8% Senior Notes due 2020 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate	7.375%		7.375%
7 1/8% Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate	7.125%		7.125%
5% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate	5.00%		5.00%
4.5% Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate	4.50%		4.50%
3.8% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Senior notes				989,932
Debt instrument, stated interest rate	3.80%		3.80%
4.9% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Senior notes				691,052
Debt instrument, stated interest rate	4.90%		4.90%
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity	$ 1,840,000		$ 1,840,000
Carrying Amount [Member]
Debt Instrument [Line Items]
Revolving credit facility	905,000		905,000	853,000
Note payable	12,176		12,176	14,309
Total debt	6,579,916		6,579,916	7,117,788
Term Loan	498,865		498,865	498,274
Carrying Amount [Member] | 7 3/8% Senior Notes due 2020 [Member]
Debt Instrument [Line Items]
Senior notes	0		0	196,574
Carrying Amount [Member] | 7 1/8% Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Senior notes	0		0	395,365
Carrying Amount [Member] | 5% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Senior notes	1,997,188		1,997,188	1,996,831
Carrying Amount [Member] | 4.5% Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Senior notes	1,484,524		1,484,524	1,482,451
Carrying Amount [Member] | 3.8% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Senior notes	990,964		990,964	989,932
Carrying Amount [Member] | 4.9% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Senior notes	$ 691,199		$ 691,199	$ 691,052
[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 ($)	3 Months Ended		12 Months Ended
	Dec. 31, 2016		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Nov. 10, 2016	Jul. 11, 2014
Debt Instrument [Line Items]
Proceeds from sale of assets	$ 214,800,000		$ 631,549,000	$ 34,008,000	$ 129,388,000
Loss on extinguishment of debt	26,055,000	[1]	(26,055,000)	0	(24,517,000)
Total Redemption Amount						$ 623,900,000	$ 317,500,000
Aggregate amount of lender commitments on credit facility	2,750,000,000		2,750,000,000
Maximum borrowing capacity	4,000,000,000		$ 4,000,000,000
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			$ 0	0	1,681,834,000
Repayments of Lines of Credit			1,639,000,000	1,313,000,000	$ 1,805,000,000
Current portion of long-term debt	2,219,000		2,219,000	2,144,000
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity	$ 1,840,000,000		$ 1,840,000,000
2020 Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	102.458%
Debt Instrument, Face Amount						200,000,000
2021 Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	103.563%
Debt Instrument, Face Amount						$ 400,000,000
Credit Facility [Domain]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	2.40%		2.40%
Note Payable [Member]
Debt Instrument [Line Items]
Notes Payable	$ 22,000,000		$ 22,000,000
Loan period, in years			10 years
Debt instrument, stated interest rate	3.10%		3.10%
Debt instrument, maturity date			Feb. 26, 2022
5% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate	5.00%		5.00%
Senior Notes Due 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 1,500,000,000		$ 1,500,000,000
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%		4.50%
3.8% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Senior notes				989,932,000
Debt instrument, stated interest rate	3.80%		3.80%
4.9% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Senior notes				691,052,000
Debt instrument, stated interest rate	4.90%		4.90%
8 1/4% Senior Notes due 2019 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount							$ 300,000,000
Loans Payable [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	2.30%		2.30%
Carrying Amount [Member]
Debt Instrument [Line Items]
Line of credit facility, amount outstanding	$ 905,000,000		$ 905,000,000	853,000,000
Notes Payable	12,176,000		12,176,000	14,309,000
Carrying Amount [Member] | 5% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Senior notes	1,997,188,000		1,997,188,000	1,996,831,000
Carrying Amount [Member] | 4.5% Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Senior notes	1,484,524,000		1,484,524,000	1,482,451,000
Carrying Amount [Member] | 3.8% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Senior notes	990,964,000		990,964,000	989,932,000
Carrying Amount [Member] | 4.9% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Senior notes	$ 691,199,000		$ 691,199,000	$ 691,052,000
[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, 2016	Nov. 10, 2016
2020 Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount			$ 200,000
2021 Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount			$ 400,000
2022 Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount		$ 2,000,000
Maturity date		Sep. 15, 2022
Interest Payment Dates		March 15,  Sep 15
Decreasing call premium redemption period	[1]	Mar. 15, 2017
Make-whole redemption period	[2]	Mar. 15, 2017
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	[2]	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	[2]	Mar. 1, 2024
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	[2]	Dec. 1, 2043
[1]	On or after this date, the Company has the option to redeem all or a portion of its 2022 Notes at the decreasing redemption prices specified in the indenture to the 2022 Notes plus any accrued and unpaid interest to the date of redemption.
[2]	At any time prior to these 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.

Income Taxes - Provision for In

Income Taxes - Provision for Income Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Current Federal Tax Expense (Benefit)	$ (22,941)	$ 0	$ 0
Current tax provision, State	2	24	20
Total current income tax provision (benefit)	(22,939)	24	20
Deferred tax provision, Federal	(182,422)	(140,578)	527,315
Deferred tax provision, State	(27,414)	(40,863)	57,362
Total deferred income tax provision (benefit)	(209,836)	(181,441)	584,677
Provision (benefit) for income taxes	$ (232,775)	$ (181,417)	$ 584,697

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Expected income tax expense (benefit) based on US statutory tax rate of 35%	$ (221,359)	$ (187,280)	$ 546,713
State income taxes, net of federal benefit	(18,829)	(16,219)	42,169
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	1,044	13,503	4,389
Effect of differing statutory tax rate in Canada	481	5,239	(1,900)
Other, net	5,888	3,340	(6,674)
Provision (benefit) for income taxes	$ (232,775)	$ (181,417)	$ 584,697
Federal statutory income tax rate	35.00%

Income Taxes - Components of De

Income Taxes - Components of Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Deferred tax assets, Net operating loss carryforwards	$ 478,975	$ 398,024
Deferred tax assets, Canadian net operating loss carryforwards	18,936	17,892
Deferred tax assets, Alternative minimum tax carryforwards	16,663	40,796
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Share-based Compensation Cost	32,924	32,910
Deferred Tax Assets Non-cash Losses On Derivatives	21,064	0
Deferred Tax Assets, Other	11,466	11,048
Total deferred tax assets	580,028	500,670
Deferred Tax Assets, Valuation Allowance	(18,936)	(17,892)
Deferred Tax Assets, Net	561,092	482,778
Deferred tax liabilities, Property and equipment	(2,448,450)	(2,528,125)
Deferred Tax Liabilities Unrealized Gains on Derivatives	0	(38,452)
Deferred tax liabilities, Gain on Derivative Liquidation	0	(4,158)
Deferred Tax Liabilities, Other	(2,947)	(2,271)
Total deferred tax liabilities	(2,451,397)	(2,573,006)
Net deferred tax liabilities	$ (1,890,305)	$ (2,090,228)

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards, State	$ 2,170,000
Alternative minimum tax credit carryforward	17,000
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	1,044	$ 13,503	$ 4,389
Deferred Tax Assets, Valuation Allowance	(18,936)	$ (17,892)
UNITED STATES
Operating Loss Carryforwards [Line Items]
Federal Operating Loss Carryforwards	1,080,000
Oklahoma [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards, State	1,560,000
NORTH DAKOTA
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards, State	$ 530,000

Lease Commitments - Lease Commi

Lease Commitments - Lease Commitments (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Leases [Abstract]
Lease expenses associated with operating leases	$ 4,400	$ 9,600	$ 8,000
2,014	1,624
2,015	1,376
2,016	746
2,017	643
2,018	476
Thereafter	7,629
Total obligations	$ 12,494

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Long-term Purchase Commitment [Line Items]
Total future drilling commitments at balance sheet date	$ 227
Drilling commitments 2017	138
Drilling commitments 2018	59
Drilling commitments 2019	29
Drilling commitments 2020	1
Damages claimed related to contingency matter	200
Legal proceedings recorded as a liability under other noncurrent liabilities	$ 6.5	$ 6.1
Future Drilling Commitments End Date	2020-01
Pipeline Transportation and Processing Commitments [Member]
Long-term Purchase Commitment [Line Items]
Future commitment, end date	2,027
Future commitment, total	$ 840
Future commitment, due in 2017	221
Future commitment, due in 2018	215
Future commitment, due in 2019	162
Future commitment, due in 2020	55
Future commitment, due in 2021	44
Future commitments, thereafter	$ 143

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Revenues from transactions with related party	$ 0	$ 1,400,000	$ 95,128,000
Production expenses to affiliates	0	1,654,000	5,123,000
Total amount paid to related party	100,000	7,700,000	58,200,000
Amount charged to affiliate for aircraft use	9,500	10,000	51,000
Amount charged to company by affiliate for aircraft use	292,000	236,000	97,000
Affiliated Entity [Member]
Related Party Transaction [Line Items]
Expenses from transactions with related party	8,800,000	1,800,000
Capitalized costs	100,000	2,600,000	5,900,000
Production expenses to affiliates	1,700,000	5,100,000
Total amount paid to related party	9,200,000	1,900,000
Officers And Other Key Employees [Member]
Related Party Transaction [Line Items]
Revenues from transactions with related party	300,000	500,000	800,000
Due to affiliates	45,000	52,000
Revenues paid to related party	400,000	700,000	1,700,000
Due from affiliates	90,000	106,000
Other Affiliates [Member]
Related Party Transaction [Line Items]
Total amount paid to related party	195,000	221,000	34,000
Due to affiliates	97,000	15,000
Due from affiliates	3,400	1,000
Total amount received from related party	$ 6,800	$ 33,000	39,000
Affiliated Entity [Member]
Related Party Transaction [Line Items]
Revenues from transactions with related party			$ 95,100,000

Stock Based Compensation - Asso

Stock Based Compensation - Associated Compensation Expense (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-based compensation	$ 48,098	$ 51,834	$ 54,353

Stock-Based Compensation - Addi

Stock-Based Compensation - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Restricted stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value at vesting date	$ 30	$ 23.6	$ 58.2
Unrecognized compensation expense related to non-vested	$ 55
Unrecognized compensation expense related to non-vested, period for recognition, in years	1 year 5 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	15,265,952

Stock Based Compensation - Summ

Stock Based Compensation - Summary of Changes in Non Vested Shares of Restricted Stock (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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	3,249,611	2,678,764	2,714,312
Granted shares	2,064,508	1,462,534	1,424,764
Vested shares	(1,207,235)	(555,517)	(1,007,166)
Forfeited shares	(193,250)	(336,170)	(453,146)
Non-vested shares, ending balance	3,913,634	3,249,611	2,678,764
Non-vested, weighted average grant-date fair value, beginning of period	$ 48.20	$ 49.40	$ 37.50
Granted, weighted average grant-date fair value	22.36	46.65	61.11
Vested, weighted average grant-date fair value	41.27	48.07	35.91
Forfeited, weighted average grant-date fair value	39.79	51.23	44.90
Non-vested, weighted average grant-date fair value, end of period	$ 37.12	$ 48.20	$ 49.40

Accumulated Other Comprehensi68

Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Foreign Currency [Abstract]
Foreign currency translation adjustments		$ 3,094	$ (2,969)	$ (385)
Translation Adjustment Functional to Reporting Currency, Tax Benefit (Expense)	[1]	0	0	0
Other Comprehensive Income (Loss), Net of Tax		3,094	(2,969)	(385)
Accumulated other comprehensive loss		$ (260)	$ (3,354)	$ (385)	$ 0
[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	3 Months Ended			12 Months Ended
	Dec. 31, 2016USD ($)	Sep. 30, 2016aBoe	Jun. 30, 2016USD ($)a	Dec. 31, 2016USD ($)Boe	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Oct. 14, 2016a
Property Acquisition And Dispositions [Line Items]
Proceeds from sale of assets	$ 214,800			$ 631,549	$ 34,008	$ 129,388
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
SCOOP [Member]
Property Acquisition And Dispositions [Line Items]
Land Subject to Ground Leases | a							30,000
Production, Barrels of Oil Equivalents | Boe				700
Niobrara [Domain]
Property Acquisition And Dispositions [Line Items]
Proceeds from sale of assets						30,300
WYOMING
Property Acquisition And Dispositions [Line Items]
Land Subject to Ground Leases | a			132,000
Northwest Cana [Member]
Property Acquisition And Dispositions [Line Items]
Proceeds from sale of assets						$ 85,800
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 Pro70

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Crude oil and natural gas sales	$ 2,026,958	$ 2,552,531	$ 4,203,022
Production expenses	(289,289)	(348,897)	(352,472)
Production taxes and other expenses	(142,388)	(200,637)	(349,760)
Exploration Expense	(16,972)	(19,413)	(50,067)
Depreciation, depletion, amortization and accretion	(1,679,485)	(1,722,336)	(1,338,351)
Property impairments	(237,292)	(402,131)	(616,888)
Income tax benefit (provision)	126,794	33,680	(559,311)
Results from crude oil and natural gas producing activities	$ (211,674)	$ (107,203)	$ 936,173

Crude Oil and Natural Gas Pro71

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Property Acquisition Costs - Proved	$ 5,008	$ 557	$ 48,917
Property Acquisition Costs - Unproved	149,962	168,492	409,529
Total property acquisition costs	154,970	169,049	458,446
Exploration Costs	182,355	241,523	863,606
Development Costs	767,148	2,148,530	3,670,448
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities	$ 1,104,473	$ 2,559,102	$ 4,992,500

Crude Oil and Natural Gas Pro72

Crude Oil and Natural Gas Property Information - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Development costs included in asset retirement costs	$ (9.6)	$ 22.8	$ 20.3

Crude Oil and Natural Gas Pro73

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, 2016	Dec. 31, 2015
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Proved crude oil and natural gas properties	$ 19,802,395	$ 19,520,724
Unproved crude oil and natural gas properties	429,562	682,988
Total	20,231,957	20,203,712
Less accumulated depreciation, depletion and amortization	(7,553,255)	(6,374,218)
Net capitalized costs	$ 12,678,702	$ 13,829,494

Crude Oil and Natural Gas Pro74

Crude Oil and Natural Gas Property Information - Schedule of Capitalized Exploratory Drilling Costs Pending Evaluation (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)Well	Dec. 31, 2015USD ($)Well	Dec. 31, 2014USD ($)Well
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Balance at January 1	$ 59,397	$ 93,421	$ 152,775
Additions to capitalized exploratory well costs pending determination of proved reserves	123,980	132,806	627,853
Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves	(141,941)	(160,779)	(671,618)
Capitalized exploratory well costs charged to expense	(6,584)	(6,051)	(15,589)
Balance at December 31	$ 34,852	$ 59,397	$ 93,421
Number of wells | Well	54	73	119

Supplemental Crude Oil and Na75

Supplemental Crude Oil and Natural Gas Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2016MBoe	Dec. 31, 2016MMcf	Dec. 31, 2016MBbls	Dec. 31, 2016$ / Barrels	Dec. 31, 2015$ / bbl$ / McfMBoeMMcfMBbls	Dec. 31, 2014$ / bbl$ / McfMBoeMMcfMBbls
Reserve Quantities [Line Items]
Percentage of discounted future net cash flows prepared by external reserve engineers	99.00%					99.00%	99.00%
Extensions, discoveries, and other additions		249,430				253,173	440,621
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					35.57	41.63	84.54
Crude Oil [Member]
Reserve Quantities [Line Items]
Percentage change in average SEC price	15.00%
Revisions of previous estimates | MBbls				(99,966)		(246,840)	(67,151)
Extensions, discoveries and other additions | MBbls				97,587		134,764	239,526
Natural Gas [Member]
Reserve Quantities [Line Items]
Percentage change in average SEC price	3.00%
Revisions of previous estimates | MMcf			(63,057)			(302,143)	(244,783)
Extensions, discoveries and other additions | MMcf			911,062			710,453	1,206,569
Weighted average price utilized in computation of future cash inflows					2.14	2.35	6.06
Proved Reserves [Domain] | Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls				37
Proved Undeveloped Reserves [Domain]
Reserve Quantities [Line Items]
Revisions of previous estimates		70
Proved Undeveloped Reserves [Domain] | Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MMcf			118
Proved Undeveloped Reserves [Domain] | Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls				51
Bakken [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions			105,000	55,000
Extensions, discoveries, and other additions		73,000
SCOOP [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates		97,000
Extensions, discoveries and other additions			475,000	18,000
Northwest Cana [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates		79,000
Extensions, discoveries and other additions			331,000	24,000
Production [Domain] | Proved Reserves [Domain]
Reserve Quantities [Line Items]
Revisions of previous estimates		9
Production [Domain] | Proved Reserves [Domain] | Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MMcf			166
Price Driven [Domain] | Proved Reserves [Domain]
Reserve Quantities [Line Items]
Revisions of previous estimates		28
Price Driven [Domain] | Proved Reserves [Domain] | Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MMcf			50
Price Driven [Domain] | Proved Reserves [Domain] | Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls				20

Supplemental Crude Oil and Na76

Supplemental Crude Oil and Natural Gas Information - Schedule of Proved Crude Oil and Natural Gas Reserves (Detail)	12 Months Ended
	Dec. 31, 2016$ / BarrelsMBoeMMcfMBbls	Dec. 31, 2015$ / BarrelsMBoeMMcfMBbls	Dec. 31, 2014MBoeMMcfMBbls	Dec. 31, 2013MBoe
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Net (Energy) | MBoe	1,274,864	1,225,811	1,351,091	1,084,125
Percentage of discounted future net cash flows prepared by external reserve engineers	99.00%	99.00%	99.00%
Changes in Proved Reserves [Roll Forward]
Revisions of previous estimates | MBoe	(110,474)	(297,198)	(107,949)
Extensions, discoveries, and other additions | MBoe	249,430	253,173	440,621
Proved Developed and Undeveloped Reserve, Production (Energy) | MBoe	79,390	80,926	63,579
Sales of minerals in place, Total | MBoe	(10,513)	(329)	(3,227)
Purchases of minerals in place, Total | MBoe	0	0	1,100
Percent of proved crude oil reserve estimates prepared by external reserve engineers	99.00%	98.00%	98.00%
Natural Gas [Member]
Reserve Quantities [Line Items]
Twelve month average SEC price | $ / Barrels	2.49	2.58
Changes in Proved Reserves [Roll Forward]
Proved reserves at beginning of period | MMcf	3,151,786	2,908,386	2,078,020
Revisions of previous estimates | MMcf	(63,057)	(302,143)	(244,783)
Extensions, discoveries and other additions | MMcf	911,062	710,453	1,206,569
Production | MMcf	(195,240)	(164,454)	(114,295)
Sales of minerals in place | MMcf	(14,733)	(456)	(18,623)
Purchases of minerals in place | MMcf	0	0	1,498
Proved reserves at end of period | MMcf	3,789,818	3,151,786	2,908,386
Crude Oil [Member]
Reserve Quantities [Line Items]
Twelve month average SEC price | $ / Barrels	42.75	50.28
Changes in Proved Reserves [Roll Forward]
Proved reserves at beginning of period | MBbls	700,514	866,360	737,788
Revisions of previous estimates | MBbls	(99,966)	(246,840)	(67,151)
Extensions, discoveries and other additions | MBbls	97,587	134,764	239,526
Production | MBbls	(46,850)	(53,517)	(44,530)
Sales of minerals in place | MBbls	(8,057)	(253)	(123)
Purchases of minerals in place | MBbls	0	0	850
Proved reserves at end of period | MBbls	643,228	700,514	866,360

Supplemental Crude Oil and Na77

Supplemental Crude Oil and Natural Gas Information - Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities (Detail)	12 Months Ended
	Dec. 31, 2016MBoeMMcfMBbls	Dec. 31, 2015MBoeMMcfMBbls	Dec. 31, 2014MBoeMMcfMBbls	Dec. 31, 2013MBoeMMcf
Reserve Quantities [Line Items]
Proved Developed Reserves (MBOE) | MBoe	518,646	525,188	502,479
Proved Undeveloped Reserve (MBOE) | MBoe	756,218	700,623	848,612
Proved Developed and Undeveloped Reserve, Net (MBOE) | MBoe	1,274,864	1,225,811	1,351,091	1,084,125
Crude Oil [Member]
Reserve Quantities [Line Items]
Proved Developed Reserves (Volume) | MBbls	290,210	326,798	342,137
Proved Undeveloped Reserve (Volume) | MBbls	353,018	373,716	524,223
Proved Developed and Undeveloped Reserves, Net | MBbls	643,228	700,514	866,360
Proved Undeveloped Reserves [Domain]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBoe	70
Proved Undeveloped Reserves [Domain] | Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls	51
Proved Undeveloped Reserves [Domain] | Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MMcf	118
Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MMcf	(63,057)	(302,143)	(244,783)
Proved Developed Reserves (Volume) | MMcf	1,370,620	1,190,343	962,051
Proved Undeveloped Reserve (Volume) | MMcf	2,419,198	1,961,443	1,946,335
Proved Developed and Undeveloped Reserves, Net | MMcf	3,789,818	3,151,786	2,908,386	2,078,020
Proved Reserves [Domain] | Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls	37
Other [Domain] | Proved Reserves [Domain]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBoe	3
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 | MMcf	61

Supplemental Crude Oil and Na78

Supplemental Crude Oil and Natural Gas Information - Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Crude Oil and Natural Gas Information [Abstract]
Discount factor utilized as standardized measure for future net cash flows	10.00%
Future cash inflows	$ 31,008,587	$ 36,551,672	$ 90,867,459
Future production costs	(9,175,410)	(10,869,493)	(25,799,221)
Future development and abandonment costs	(6,452,647)	(6,935,958)	(12,842,174)
Future income taxes	(3,018,839)	(3,717,612)	(13,800,737)
Future net cash flows	12,361,691	15,028,609	38,425,327
10% annual discount for estimated timing of cash flows	(6,851,468)	(8,552,325)	(19,992,293)
Standardized measure of discounted future net cash flows	$ 5,510,223	$ 6,476,284	$ 18,433,034	$ 16,295,767

Supplemental Crude Oil and Na79

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, 2016	Dec. 31, 2015	Dec. 31, 2014
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	$ 6,476,284	$ 18,433,034	$ 16,295,767
Extensions, discoveries and improved recoveries, less related costs	786,587	1,091,283	5,516,528
Revisions of previous quantity estimates	(794,785)	(2,156,028)	(1,755,366)
Changes in estimated future development and abandonment costs	1,651,218	5,008,731	476,665
Sales of Minerals in Place	(90,390)	(7,768)
Purchases of minerals in place			(3,196)
Net change in prices and production costs	(2,003,163)	(16,111,142)	(1,925,349)
Accretion of discount	798,597	1,843,303	1,629,576
Sales of crude oil and natural gas produced, net of production costs	(1,595,281)	(2,002,997)	(3,500,790)
Development costs incurred during the period	454,983	1,394,584	2,466,748
Change in timing of estimated future production and other	(538,665)	(3,844,259)	(309,902)
Change in income taxes	364,838	2,827,543	(457,647)
Net change	(966,061)	(11,956,750)	2,137,267
Standardized measure of discounted future net cash flows at end of year	$ 5,510,223	$ 6,476,284	$ 18,433,034

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, 2016		Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Dec. 31, 2015		Sep. 30, 2015		Jun. 30, 2015		Mar. 31, 2015		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Loss on extinguishment of debt	$ (26,055)	[1]															$ 26,055	$ 0	$ 24,517
Total revenues	549,689	[2]	$ 526,199	[2]	$ 451,211	[2]	$ 453,174	[2]	$ 575,480	[2]	$ 682,669	[2]	$ 796,374	[2]	$ 625,644	[2]	1,980,273	2,680,167	4,801,618
Gain (loss) on derivative instruments, net	(47,382)	[2]	15,668	[2]	(82,257)	[2]	42,112	[2]	16,540	[2]	46,527	[2]	(4,737)	[2]	32,755	[2]	(71,859)	91,085	559,759
Property impairments	34,564	[3]	57,689	[3]	66,112	[3]	78,927	[3]	81,001	[3]	96,697	[3]	76,872	[3]	147,561	[3]	237,292	402,131	616,888
Gain (Loss) on Disposition of Property Plant Equipment	201,315	[4]	6,158	[4]	96,907	[4]	109	[4]	218	[4]	288	[4]	20,573	[4]	2,070	[4]	(304,489)	(23,149)	(600)
Income from operations	155,299		(93,183)		(110,547)		(239,103)		(142,816)		(52,356)		82,447		(111,276)		(287,534)	(224,001)	1,867,836
Net income (loss)	$ 27,670		$ (109,621)		$ (119,402)		$ (198,326)		$ (139,677)		$ (82,423)		$ 403		$ (131,971)		$ (399,679)	$ (353,668)	$ 977,341
Net income per share: Basic	$ 0.07		$ (0.30)		$ (0.32)		$ (0.54)		$ (0.38)		$ (0.22)		$ 0		$ (0.36)		$ (1.08)	$ (0.96)	$ 2.65
Net income per share: Diluted	$ 0.07		$ (0.30)		$ (0.32)		$ (0.54)		$ (0.38)		$ (0.22)		$ 0		$ (0.36)		$ (1.08)	$ (0.96)	$ 2.64
[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]	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.