Continental Resources Inc (CLR) 10-Q 4 Nov 15 2015 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2015	Oct. 31, 2015
Subsequent Event [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q3
Trading Symbol	CLR
Entity Registrant Name	CONTINENTAL RESOURCES, INC
Entity Central Index Key	732,834
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		373,008,223

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 16,955	$ 24,381
Receivables:
Crude oil and natural gas sales	429,350	552,476
Affiliated parties	104	13,360
Joint interest and other, net	355,250	567,476
Derivative assets	78,610	52,423
Inventories	93,010	102,179
Deferred and prepaid taxes	2,137	63,266
Prepaid expenses and other	11,492	14,040
Total current assets	986,908	1,389,601
Net property and equipment, based on successful efforts method of accounting	14,173,563	13,635,852
Noncurrent derivative assets	27,271	31,992
Other noncurrent assets	18,135	18,588
Total assets	15,205,877	15,076,033
Current liabilities:
Accounts payable trade	613,780	1,263,724
Revenues and royalties payable	227,724	272,755
Payables to affiliated parties	482	7,305
Accrued liabilities and other	305,705	404,506
Derivative liabilities	99	1,645
Current portion of long-term debt	2,127	2,078
Total current liabilities	1,149,917	1,952,013
Long-term debt, net of current portion	7,108,702	5,926,800
Other noncurrent liabilities:
Deferred income tax liabilities	2,048,413	2,141,447
Asset retirement obligations, net of current portion	84,179	75,462
Noncurrent derivative liabilities	110	3,109
Other noncurrent liabilities	15,979	9,358
Total other noncurrent liabilities	2,148,681	$ 2,229,376
Commitments and contingencies (Note 7)
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; 372,968,752 shares issued and outstanding at September 30, 2015; 372,005,502 shares issued and outstanding at December 31, 2014	3,730	3,720
Additional paid-in capital	1,335,574	1,287,941
Accumulated Other Comprehensive Income (Loss), Net of Tax	(3,303)	(385)
Retained earnings	3,462,576	3,676,568
Total shareholders’ equity	4,798,577	4,967,844
Total liabilities and shareholders’ equity	$ 15,205,877	$ 15,076,033

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets (Parenthetical) - $ / shares	Sep. 30, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	25,000,000	25,000,000
Preferred stock, shares issued
Preferred stock, shares outstanding
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	1,000,000,000	500,000,000
Common Stock, Shares, Issued	372,968,752	372,005,502
Common Stock, Shares, Outstanding	372,968,752	372,005,502

Unaudited Condensed Consolidate

Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Revenues
Crude oil and natural gas sales	$ 628,457	$ 1,138,460	$ 1,999,751	$ 3,223,605
Crude oil and natural gas sales to affiliates	0	21,821	1,400	77,094
Gain on derivative instruments, net	46,527	473,999	74,545	171,801
Crude oil and natural gas service operations	7,685	11,048	28,991	31,418
Total revenues	682,669	1,645,328	2,104,687	3,503,918
Operating costs and expenses
Production expenses	84,036	95,700	267,058	255,911
Production expenses to affiliates	0	1,674	1,654	2,870
Production taxes and other expenses	47,682	97,399	157,589	272,726
Exploration expenses	232	13,514	14,680	29,532
Crude oil and natural gas service operations	4,059	4,337	15,045	18,390
Depreciation, depletion, amortization and accretion	448,809	363,677	1,288,278	963,409
Property impairments	96,697	85,561	321,130	223,085
General and administrative expenses	53,798	43,980	143,368	134,435
(Gain) loss on sale of assets, net	(288)	(5,411)	(22,930)	952
Total operating costs and expenses	735,025	700,431	2,185,872	1,901,310
Income (loss) from operations	(52,356)	944,897	(81,185)	1,602,608
Other income (expense):
Interest expense	(79,399)	(73,912)	(232,904)	(209,728)
Loss on Extinguishment of Debt	0	(24,517)	0	(24,517)
Other	588	393	1,474	1,945
Total other income (expense)	(78,811)	(98,036)	(231,430)	(232,300)
Income (loss) before income taxes	(131,167)	846,861	(312,615)	1,370,308
Provision (benefit) for income taxes	(48,744)	313,340	(98,623)	507,015
Net income (loss)	(82,423)	533,521	(213,992)	863,293
Foreign Currency Transaction and Translation Loss Arising During Period, Net of Tax	(438)	0	(2,918)	0
Other Comprehensive Loss, Net of Tax (unaudited)	(438)	0	(2,918)	0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	$ (82,861)	$ 533,521	$ (216,910)	$ 863,293
Basic net income (loss) per share (in dollars per share)	$ (0.22)	$ 1.45	$ (0.58)	$ 2.34
Diluted net income (loss) per share (in dollars per share)	$ (0.22)	$ 1.44	$ (0.58)	$ 2.33

Condensed Consolidated Statemen

Condensed Consolidated Statements of Shareholders Equity - 9 months ended Sep. 30, 2015 - USD ($) $ in Thousands	Total	Common Stock [Member]	Additional Paid-In Capital [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Retained Earnings [Member]
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	372,005,502
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net loss (unaudited)	$ (213,992)				(213,992)
Foreign Currency Transaction and Translation Loss Arising During Period, Net of Tax	(2,918)
Other Comprehensive Loss, Net of Tax (unaudited)	(2,918)
Stock-based compensation (unaudited)	40,273		40,273
Adjustments to Additional Paid in Capital, Income Tax Benefit from Share-based Compensation	13,177		13,177
Restricted stock:
Granted (unaudited)	$ 14	$ 14
Granted (unaudited), shares	1,383,557	1,383,557
Repurchased and canceled (unaudited)	$ (5,818)	$ (1)	(5,817)
Repurchased and canceled (unaudited), shares		(128,308)
Forfeited (unaudited), shares	291,999	(291,999)
Forfeitures (unaudited)	$ (3)	$ (3)
Balance at Sep. 30, 2015	$ 4,798,577	$ 3,730	$ 1,335,574	$ (3,303)	$ 3,462,576
Balance, shares at Sep. 30, 2015	372,968,752	372,968,752

Unaudited Condensed Consolidat6

Unaudited Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Cash flows from operating activities
Net income (loss)	$ (213,992)	$ 863,293
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	1,286,158	970,273
Property impairments	321,130	223,085
Non-cash gain on derivatives, net	(26,011)	(269,018)
Stock-based compensation	40,290	39,419
Provision (benefit) for deferred income taxes	(98,645)	504,737
Excess Tax Benefit from Share-based Compensation, Operating Activities	(13,177)	0
Dry hole costs	8,183	9,142
(Gain) loss on sale of assets, net	(22,930)	952
Loss on Extinguishment of Debt	0	24,517
Other, net	10,143	5,986
Changes in assets and liabilities:
Accounts receivable	351,309	(192,178)
Inventories	9,137	(28,124)
Other current assets	64,271	(7,017)
Accounts payable trade	(178,000)	82,297
Revenues and royalties payable	(45,030)	32,500
Accrued liabilities and other	(78,947)	16,645
Other noncurrent assets and liabilities	1,603	1,342
Net cash provided by operating activities	1,415,492	2,277,851
Cash flows from investing activities
Exploration and development	(2,598,367)	(3,255,327)
Purchase of producing crude oil and natural gas properties	(557)	(48,305)
Purchase of other property and equipment	(31,991)	(51,974)
Proceeds from sale of assets	33,216	129,346
Net cash used in investing activities	(2,597,699)	(3,226,260)
Cash flows from financing activities
Credit facility borrowings	1,780,000	1,105,000
Repayment of credit facility	(600,000)	(1,380,000)
Proceeds from Issuance of Senior Notes	0	1,681,834
Redemption of Senior Notes	0	(300,000)
Premium on redemption of Senior Notes	0	(17,497)
Repayment of other debt	(1,552)	(1,503)
Debt issuance costs	(2,110)	(7,999)
Repurchase of restricted stock for tax withholdings	(5,818)	(7,618)
Excess Tax Benefit from Share-based Compensation, Financing Activities	13,177	0
Net cash provided by financing activities	1,183,697	1,072,217
Effect of Exchange Rate on Cash and Cash Equivalents	(8,916)	0
Net change in cash and cash equivalents	(7,426)	123,808
Cash and cash equivalents at beginning of period	24,381	28,482
Cash and cash equivalents at end of period	$ 16,955	$ 152,290

Organization and Nature of Busi

Organization and Nature of Business	9 Months Ended
	Sep. 30, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Nature of Business	Organization and Nature of Business 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 Kansas and all properties south of Kansas and west of the Mississippi River including various plays in the South Central Oklahoma Oil Province (“SCOOP”), Northwest Cana, and Arkoma areas of Oklahoma. The East region is comprised of undeveloped leasehold acreage east of the Mississippi River with no current drilling or production operations. The Company’s operations are geographically concentrated in the North region, with that region comprising 68% of the Company’s crude oil and natural gas production and 77% of its crude oil and natural gas revenues for the nine months ended September 30, 2015 . The Company's principal producing properties in the North region are located in the Bakken field of North Dakota and Montana. In recent years, the Company has significantly expanded its activity in the South region with its discovery and announcement of the SCOOP play in Oklahoma. The South region now comprises 32% of the Company's crude oil and natural gas production and 23% of its crude oil and natural gas revenues for the nine months ended September 30, 2015 . The Company has focused its operations on the exploration and development of crude oil since the 1980s. For the nine months ended September 30, 2015 , crude oil accounted for 67% of the Company’s total production and 86% of its crude oil and natural gas revenues.

Basis of Presentation and Signi

Basis of Presentation and Significant Accounting Policies	9 Months Ended
	Sep. 30, 2015
Accounting Policies [Abstract]
Basis of Presentation and Significant Accounting Policies	Basis of Presentation and Significant Accounting Policies Basis of presentation The condensed consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are 100% owned. All significant intercompany accounts and transactions have been eliminated upon consolidation. This report has been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”) applicable to interim financial information. Because this is an interim period filing presented using a condensed format, it does not include all disclosures required by accounting principles generally accepted in the United States (“U.S. GAAP”), although the Company believes the disclosures are adequate to make the information not misleading. You should read this Quarterly Report on Form 10-Q ("Form 10-Q") together with the Company’s Annual Report on Form 10-K for the year ended December 31, 2014 (“ 2014 Form 10-K”), which includes a summary of the Company’s significant accounting policies and other disclosures. The condensed consolidated financial statements as of September 30, 2015 and for the three and nine month periods ended September 30, 2015 and 2014 are unaudited. The condensed consolidated balance sheet as of December 31, 2014 was derived from the audited balance sheet included in the 2014 Form 10-K. The Company has evaluated events or transactions through the date this report on Form 10-Q was filed with the SEC in conjunction with its preparation of these condensed consolidated financial statements. The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure and estimation of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Actual results may differ from those estimates. The most significant 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. In the opinion of management, all adjustments (consisting only of normal recurring adjustments) necessary for a fair presentation in accordance with U.S. GAAP have been included in these unaudited interim condensed consolidated financial statements. The results of operations for any interim period are not necessarily indicative of the results of operations that may be expected for any other interim period or for an entire year. 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. Diluted net income (loss) 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 three and nine months ended September 30, 2015 and 2014. Three months ended September 30, Nine months ended September 30, In thousands, except per share data 2015 2014 2015 2014 Income (loss) (numerator): Net income (loss) - basic and diluted $ (82,423 ) $ 533,521 $ (213,992 ) $ 863,293 Weighted average shares (denominator): Weighted average shares - basic 369,599 368,814 369,499 368,740 Non-vested restricted stock (1) — 1,714 — 1,892 Weighted average shares - diluted 369,599 370,528 369,499 370,632 Net income (loss) per share: Basic $ (0.22 ) $ 1.45 $ (0.58 ) $ 2.34 Diluted $ (0.22 ) $ 1.44 $ (0.58 ) $ 2.33 (1) The potential dilutive effect of approximately 688,800 and 1,521,000 weighted average restricted shares were not included in the calculation of diluted net loss per share for the three and nine months ended September 30, 2015 , respectively, because to do so would have been anti-dilutive. 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 September 30, 2015 and December 31, 2014 consisted of the following: In thousands September 30, 2015 December 31, 2014 Tubular goods and equipment $ 15,936 $ 15,659 Crude oil 77,074 86,520 Total $ 93,010 $ 102,179 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 period-end. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized. The Company recorded valuation allowances of $0.9 million and $13.3 million for the three and nine months ended September 30, 2015 , respectively, against deferred tax assets associated with operating loss carryforwards generated by its Canadian subsidiary in 2015 for which the Company does not expect to realize a benefit. Affiliate transactions The affiliate transactions reflected in the accompanying unaudited condensed 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 affiliate transactions recognized in the Company's financial statements at September 30, 2015 and for the three and nine months then ended. Adoption of new accounting pronouncement In April 2015, the Financial Accounting Standards Board issued Accounting Standards Update 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs ("ASU 2015-03") . The new standard requires debt issuance costs related to a recognized term debt liability, such as the Company's senior notes and note payable, be presented in the balance sheet as a direct deduction from the carrying amount of that term debt liability, consistent with the presentation of a debt discount. Under previous guidance, debt issuance costs were required to be presented in the balance sheet as an asset. The new standard does not affect the existing recognition and measurement guidance for debt issuance costs. The new standard is effective for annual and interim periods beginning after December 15, 2015, with early adoption permitted. The Company early adopted ASU 2015-03 as of June 30, 2015 on a retrospective basis to all prior balance sheet periods presented. As a result of the adoption, the Company reclassified unamortized debt issuance costs associated with its senior notes and note payable, which totaled $65.7 million and $69.0 million as of June 30, 2015 and December 31, 2014 , respectively, from "Other noncurrent assets" to a reduction of "Long-term debt, net of current portion" on the condensed consolidated balance sheets. Unamortized debt issuance costs reflected as a reduction of long-term debt subsequently totaled $64.0 million as of September 30, 2015 . Adoption of ASU 2015-03 had no impact on the Company's current and previously reported shareholders' equity, results of operations, or cash flows. The December 31, 2014 carrying amounts for the Company's senior notes and note payable presented throughout this report on Form 10-Q have been adjusted to reflect the retroactive adoption of ASU 2015-03. Unamortized debt issuance costs associated with the Company's credit facility, which amounted to $7.6 million and $7.0 million as of September 30, 2015 and December 31, 2014 , respectively, have not been reclassified and remain reflected in "Other noncurrent assets" on the condensed consolidated balance sheets.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	9 Months Ended
	Sep. 30, 2015
Supplemental Cash Flow Elements [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. Nine months ended September 30, In thousands 2015 2014 Supplemental cash flow information: Cash paid for interest $ 204,180 $ 173,057 Cash paid for income taxes 27 4,012 Cash received for income tax refunds 59,117 5 Non-cash investing activities: Increase (decrease) in accrued capital expenditures (482,475 ) 235,431 Asset retirement obligation additions and revisions, net 6,267 6,232

Derivative Instruments

Derivative Instruments	9 Months Ended
	Sep. 30, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	Derivative Instruments 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 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 unaudited condensed consolidated statements of comprehensive income (loss) under the caption “ Gain on derivative instruments, net .” The Company may utilize swap and collar derivative contracts to economically hedge against the variability in cash flows associated with the sale of future 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. With respect to a 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 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. The Company’s derivative contracts are settled based upon reported settlement prices on commodity exchanges. Crude oil derivative settlements are based on NYMEX West Texas Intermediate (“WTI”) pricing or Inter-Continental Exchange (“ICE”) pricing for Brent crude oil. Natural gas derivative settlements are based on NYMEX Henry Hub pricing. 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 5. Fair Value Measurements . At September 30, 2015 , the Company had outstanding derivative contracts with respect to future production as set forth in the tables below. Crude Oil - NYMEX WTI Ceilings Weighted Average Period and Type of Contract Bbls Range October 2015 - December 2015 Written call options - WTI (1) 1,104,000 $95.85 - $103.75 $ 98.36 Crude Oil - ICE Brent Ceilings Weighted Average Period and Type of Contract Bbls Range October 2015 - December 2015 Written call options - ICE Brent (1) 184,000 $ 107.40 $ 107.40 January 2016 - December 2016 Written call options - ICE Brent (1) 1,464,000 $ 107.70 $ 107.70 Collars Natural Gas - NYMEX Henry Hub Swaps Weighted Average Price Floors Ceilings Weighted Average Price Weighted Average Price Period and Type of Contract MMBtus Range Range October 2015 - December 2015 Swaps - Henry Hub 9,780,000 $ 3.37 Collars - Henry Hub 7,360,000 $3.50 - $3.75 $ 3.69 $4.89 - $5.48 $ 5.04 January 2016 - December 2016 Swaps - Henry Hub 75,930,000 $ 3.85 January 2017 - December 2017 Swaps - Henry Hub 25,550,000 $ 3.35 Collars - Henry Hub 7,300,000 $ 3.00 $ 3.00 $ 3.88 $ 3.88 (1) Written call options represent the ceiling positions remaining from the Company's previous crude oil collar contracts. The floor positions of the collars were liquidated in the fourth quarter of 2014. For these written call options, the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price. Derivative gains and losses The following table presents cash settlements on matured derivative instruments and non-cash gains and losses on open derivative instruments for the periods presented. Cash receipts and payments below 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. Three months ended September 30, Nine months ended September 30, In thousands 2015 2014 2015 2014 Cash received (paid) on derivatives: Crude oil fixed price swaps $ — $ (4,126 ) $ — $ (77,148 ) Crude oil collars — (233 ) — (2,270 ) Natural gas fixed price swaps 5,142 4,549 29,084 (17,799 ) Natural gas collars 6,775 — 19,450 — Cash received (paid) on derivatives, net 11,917 190 48,534 (97,217 ) Non-cash gain (loss) on derivatives: Crude oil fixed price swaps — 416,637 — 228,845 Crude oil collars — 27,386 — 28,300 Crude oil written call options 617 — 4,544 — Natural gas fixed price swaps 36,257 25,851 33,453 7,944 Natural gas collars (2,264 ) 3,935 (11,986 ) 3,929 Non-cash gain on derivatives, net 34,610 473,809 26,011 269,018 Gain on derivative instruments, net $ 46,527 $ 473,999 $ 74,545 $ 171,801 Balance sheet offsetting of derivative assets and liabilities All of the Company’s derivative contracts are recorded at fair value in the condensed 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 condensed consolidated balance sheets. The following table presents the gross amounts of recognized derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the condensed consolidated balance sheets for the periods presented, all at fair value. In thousands September 30, 2015 December 31, 2014 Commodity derivative assets: Gross amounts of recognized assets $ 105,881 $ 84,415 Gross amounts offset on balance sheet — — Net amounts of assets on balance sheet 105,881 84,415 Commodity derivative liabilities: Gross amounts of recognized liabilities (209 ) (4,770 ) Gross amounts offset on balance sheet — 16 Net amounts of liabilities on balance sheet $ (209 ) $ (4,754 ) The following table reconciles the net amounts disclosed above to the individual financial statement line items in the condensed consolidated balance sheets. In thousands September 30, 2015 December 31, 2014 Derivative assets $ 78,610 $ 52,423 Noncurrent derivative assets 27,271 31,992 Net amounts of assets on balance sheet 105,881 84,415 Derivative liabilities (99 ) (1,645 ) Noncurrent derivative liabilities (110 ) (3,109 ) Net amounts of liabilities on balance sheet (209 ) (4,754 ) Total derivative assets, net $ 105,672 $ 79,661

Fair Value Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2015
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 commodity prices, 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 September 30, 2015 and December 31, 2014 . Fair value measurements at September 30, 2015 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets (liabilities): Fixed price swaps $ — $ 96,052 $ — $ 96,052 Collars — 9,829 — 9,829 Written call options — (209 ) — (209 ) Total $ — $ 105,672 $ — $ 105,672 Fair value measurements at December 31, 2014 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets (liabilities): Fixed price swaps $ — $ 62,599 $ — $ 62,599 Collars — 21,816 — 21,816 Written call options — (4,754 ) — (4,754 ) Total $ — $ 79,661 $ — $ 79,661 Assets Measured at Fair Value on a Nonrecurring Basis Certain assets are reported at fair value on a nonrecurring basis in the condensed 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, 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 strip prices through 2019 (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 50 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. During the three and nine month periods ended September 30, 2015 and September 30, 2014 , 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 $36.3 million and $111.3 million for the three and nine months ended September 30, 2015 , respectively, resulting from declines in commodity prices that indicated the carrying amounts for certain fields were not recoverable. The 2015 year to date impairments reflect fair value adjustments primarily concentrated in an emerging area with minimal production and costly reserve additions ( $42.5 million , including $1.3 million in the third quarter), the Buffalo Red River units ( $26.3 million , all in the third quarter), the Medicine Pole Hills units ( $22.9 million , including $8.2 million in the third quarter), various non-core areas in the South region ( $11.4 million , including $0.4 million in the third quarter), and non-Bakken areas of North Dakota and Montana ( $8.2 million , including $0.1 million in the third quarter). The impaired properties were written down to their estimated fair value totaling approximately $48.5 million . Impairments of proved properties totaled $38.0 million and $69.3 million for the three and nine months ended September 30, 2014 , respectively, which primarily reflected fair value adjustments made for certain properties in non-core areas of the South region. The impaired properties were written down to their estimated fair value totaling approximately $15.4 million as of September 30, 2014 . Certain unproved crude oil and natural gas properties were impaired during the three and nine months ended September 30, 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 unaudited condensed consolidated statements of comprehensive income (loss). Three months ended September 30, Nine months ended September 30, In thousands 2015 2014 2015 2014 Proved property impairments $ 36,302 $ 38,046 $ 111,346 $ 69,337 Unproved property impairments 60,395 47,515 209,784 153,748 Total $ 96,697 $ 85,561 $ 321,130 $ 223,085 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 condensed consolidated financial statements. September 30, 2015 December 31, 2014 In thousands Carrying Amount Fair Value Carrying Amount Fair Value Debt: Credit facility $ 1,345,000 $ 1,345,000 $ 165,000 $ 165,000 Note payable 14,832 13,300 16,375 14,900 7.375% Senior Notes due 2020 196,424 204,100 195,997 213,000 7.125% Senior Notes due 2021 395,184 412,000 394,668 421,000 5% Senior Notes due 2022 1,996,747 1,760,100 1,996,507 1,857,900 4.5% Senior Notes due 2023 1,481,945 1,290,000 1,480,479 1,372,800 3.8% Senior Notes due 2024 989,681 820,400 988,940 868,700 4.9% Senior Notes due 2044 691,016 504,800 690,912 572,400 Total debt $ 7,110,829 $ 6,349,700 $ 5,928,878 $ 5,485,700 The fair value of credit facility borrowings approximates carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and is 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	9 Months Ended
	Sep. 30, 2015
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $49.1 million and $52.6 million at September 30, 2015 and December 31, 2014 , respectively, consists of the following. See Note 2. Basis of Presentation and Significant Accounting Policies—Adoption of new accounting pronouncement for a discussion of the impact on long-term debt from the Company's adoption of ASU 2015-03. In thousands September 30, 2015 December 31, 2014 Credit facility $ 1,345,000 $ 165,000 Note payable 14,832 16,375 7.375% Senior Notes due 2020 196,424 195,997 7.125% Senior Notes due 2021 395,184 394,668 5% Senior Notes due 2022 1,996,747 1,996,507 4.5% Senior Notes due 2023 1,481,945 1,480,479 3.8% Senior Notes due 2024 989,681 988,940 4.9% Senior Notes due 2044 691,016 690,912 Total debt $ 7,110,829 $ 5,928,878 Less: Current portion of long-term debt 2,127 2,078 Long-term debt, net of current portion $ 7,108,702 $ 5,926,800 Credit Facility The Company has an unsecured credit facility, maturing on May 16, 2019 , with aggregate commitments totaling $2.5 billion as of September 30, 2015 , which may be increased up to a total of $4.0 billion upon agreement between the Company and participating lenders. The Company had $1.35 billion and $165 million of outstanding borrowings on its credit facility at September 30, 2015 and December 31, 2014 , respectively. Borrowings bear interest at market-based interest rates plus a margin that is based on the terms of the borrowing and the credit ratings assigned to the Company's senior unsecured debt. The weighted-average interest rate on outstanding borrowings at September 30, 2015 was 1.7% . The Company had approximately $1.15 billion of borrowing availability on its credit facility at September 30, 2015 and incurs commitment fees based on currently assigned credit ratings of 0.225% per annum on the daily average amount of unused borrowing availability. The 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 (total debt 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 this covenant at September 30, 2015 . See Note 11. Subsequent Events for a discussion of changes to the Company's credit facility and other borrowings subsequent to September 30, 2015 . 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 September 30, 2015 . 2020 Notes 2021 Notes 2022 Notes 2023 Notes 2024 Notes 2044 Notes Face value (in thousands) $200,000 $400,000 $2,000,000 $1,500,000 $1,000,000 $700,000 Maturity date Oct 1, 2020 April 1, 2021 Sep 15, 2022 April 15, 2023 June 1, 2024 June 1, 2044 Interest payment dates April 1, Oct 1 April 1, Oct 1 March 15, Sep 15 April 15, Oct 15 June 1, Dec 1 June 1, Dec 1 Call premium redemption period (1) Oct 1, 2015 April 1, 2016 March 15, 2017 — — — Make-whole redemption period (2) Oct 1, 2015 April 1, 2016 March 15, 2017 Jan 15, 2023 Mar 1, 2024 Dec 1, 2043 (1) On or after these dates, the Company has the option to redeem all or a portion of its senior notes of the applicable series at the decreasing redemption prices specified in the respective senior note indentures (together, the “Indentures”) 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 Indentures 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 and 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 September 30, 2015 . Two of the Company’s subsidiaries, Banner Pipeline Company, L.L.C. and CLR Asset Holdings, LLC, which have no material assets or operations, fully and unconditionally guarantee the senior notes. The Company’s other subsidiaries, the value of whose assets and operations are minor, do not guarantee the senior notes. Note Payable In February 2012, 20 Broadway Associates LLC, a 100% owned subsidiary of the Company, borrowed $22 million under a 10 -year amortizing term loan secured by the Company’s corporate office building in Oklahoma City, Oklahoma. The loan bears interest at a fixed rate of 3.14% per annum. Principal and interest are payable monthly through the loan’s maturity date of February 26, 2022 . Accordingly, approximately $2.1 million is reflected as a current liability under the caption “Current portion of long-term debt” in the condensed consolidated balance sheets as of September 30, 2015 . 2014 Redemption of Senior Notes In July 2014, the Company redeemed its then outstanding 8.25% Senior Notes due 2019 ("2019 Notes") using a portion of the proceeds from the May 2014 issuances of 2024 Notes and 2044 Notes. The 2019 Notes were redeemed for $317.5 million , representing a make-whole amount calculated in accordance with the terms of the 2019 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 unaudited condensed consolidated statements of comprehensive income (loss) for the three and nine months ended September 30, 2014 .

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2015
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 September 30, 2015 . The commitments under these arrangements are not recorded in the accompanying condensed consolidated balance sheets. Drilling commitments – As of September 30, 2015 , the Company had drilling rig contracts with various terms extending through March 2019 . These contracts were entered into in the ordinary course of business to ensure rig availability to allow the Company to execute its business objectives in its strategic plays. Future commitments as of September 30, 2015 total approximately $475 million , of which $59 million is expected to be incurred in the remainder of 2015 , $220 million in 2016 , $129 million in 2017 , $62 million in 2018 , and $5 million in 2019. Pipeline transportation commitments – The Company has entered into firm transportation commitments to guarantee pipeline access capacity on operational crude oil and natural gas pipelines. The commitments, which have varying terms extending as far as 2027, require the Company to pay per-unit transportation charges regardless of the amount of pipeline capacity used. Future commitments remaining as of September 30, 2015 under the operational pipeline transportation arrangements amount to approximately $1.1 billion , of which $52 million is expected to be incurred in the remainder of 2015 , $213 million in 2016 , $210 million in 2017 , $206 million in 2018 , $170 million in 2019, and $217 million thereafter. Further, the Company was a party to a five year firm transportation commitment (the "Agreement") for a future crude oil pipeline project being considered for development that is not yet operational. The project requires the granting of regulatory approvals and requires additional construction efforts by the counterparty before being completed. The project has faced significant delays and has failed to gain the necessary permits and approvals. As a result of the persistent delays and continuous uncertainty, the Agreement’s basic assumptions and purpose have become commercially impracticable. Accordingly, in 2015 the Company provided a shipper termination notice pursuant to the Agreement and formally provided the counterparty with the Company’s termination of the Agreement in its entirety. The Company's previously disclosed commitments under the Agreement totaled approximately $260 million , which is no longer expected to be incurred. The Company’s pipeline commitments are for production primarily in the North region where the Company allocates a significant portion of its capital expenditures. The Company is not committed under these contracts to deliver fixed and determinable quantities of crude oil or natural gas in the future. Fuel purchase commitment – The Company has entered into a forward purchase contract with a third party to purchase specified quantities of diesel fuel at specified prices each month through June 2016 for use in the normal course of drilling operations. Over the remaining contract term, the Company has committed to purchase approximately 16 million gallons of diesel fuel at varying prices depending on the grade of diesel fuel purchased and the timing and location of delivery. The contract satisfies a significant portion of the Company's anticipated diesel fuel needs and provides for physical delivery to desired locations. Future commitments under the arrangement as of September 30, 2015 total approximately $47 million , of which $16 million is expected to be incurred in the remainder of 2015 and $31 million is expected to be incurred in 2016. 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 1st and 2nd, 2015. On June 11, 2015, the trial court certified a “hybrid” class as requested by plaintiffs. The Company has appealed the trial court’s class certification order, which will be reviewed de novo by the appellate court. A mediation is scheduled for December 7, 2015. The Company is not currently able to estimate a reasonably possible loss or range of loss or what impact, if any, 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. Although not currently at issue in the “hybrid” certification, 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 that the case meets the requirements for a class action and is vigorously defending the case. The Company will continue to assert its defenses to the case as certified as well as any future attempt to certify a money damages class. 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 and other matters. While the outcome of these legal matters cannot be predicted with certainty, the Company does not expect them to have a material effect on its financial condition, results of operations or cash flows. As of September 30, 2015 and December 31, 2014 , the Company had recorded a liability in the condensed consolidated balance sheets under the caption “Other noncurrent liabilities” of $6.1 million and $2.9 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.

Stock-Based Compensation

Stock-Based Compensation	9 Months Ended
	Sep. 30, 2015
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. 2005 Long-Term Incentive Plan (“2005 Plan”) and 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 unaudited condensed consolidated statements of comprehensive income (loss), was $12.9 million and $13.4 million for the three months ended September 30, 2015 and 2014 , respectively, and $40.3 million and $39.4 million for the nine months ended September 30, 2015 and 2014 , respectively. In May 2013, the Company adopted the 2013 Plan and reserved a maximum of 19,680,072 shares of common stock that may be issued pursuant to the plan. The 2013 Plan replaced the Company's 2005 Plan as the instrument used to grant long-term incentive awards and no further awards will be granted under the 2005 Plan. However, restricted stock awards granted under the 2005 Plan prior to the adoption of the 2013 Plan will remain outstanding in accordance with their terms. As of September 30, 2015 , the Company had a maximum of 17,027,803 shares of restricted stock available to grant to officers, directors and employees 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 outstanding for the nine months ended September 30, 2015 is presented below: Number of Weighted Non-vested restricted shares outstanding at December 31, 2014 2,678,764 $ 49.40 Granted 1,383,557 47.36 Vested (420,852 ) 45.92 Forfeited (291,999 ) 50.99 Non-vested restricted shares outstanding at September 30, 2015 3,349,470 $ 48.86 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. The expected life of restricted stock is based on the non-vested period that remains subsequent to the date of grant. There are no post-vesting restrictions related to the Company’s restricted stock. The fair value of restricted stock that vested during the nine months ended September 30, 2015 at the vesting date was approximately $19.1 million . As of September 30, 2015 , there was approximately $81 million of unrecognized compensation expense related to non-vested restricted stock. This expense is expected to be recognized ratably over a weighted average period of 1.4 years.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income (Notes)	9 Months Ended
	Sep. 30, 2015
Accumulated Other Comprehensive Income [Abstract]
Schedule of Accumulated Other Comprehensive Income (Loss) [Table 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 condensed consolidated balance sheets. The following table summarizes the change in accumulated other comprehensive loss for the three and nine months ended September 30, 2015 : In thousands Three months ended September 30, 2015 Nine months ended September 30, 2015 Beginning accumulated other comprehensive loss, net of tax $ (2,865 ) $ (385 ) Foreign currency translation adjustments (438 ) (2,918 ) Income tax benefit (1) — — Other comprehensive loss, net of tax (438 ) (2,918 ) Ending accumulated other comprehensive loss, net of tax $ (3,303 ) $ (3,303 ) (1) A valuation allowance has been recognized against deferred tax assets associated with losses generated by the Company's Canadian operations, thereby resulting in no income taxes on other comprehensive loss for the period.

Property Dispositions

Property Dispositions	9 Months Ended
	Sep. 30, 2015
Property Dispositions [Abstract]
Property Acquisitions and Dispositions [Text Block]	Property Dispositions During the nine months ended September 30, 2015 , the Company sold certain non-strategic properties in various areas to third parties for proceeds totaling $33.2 million . The proceeds primarily related to the assignment 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 assigned properties represented an immaterial portion of the Company’s leasehold acreage. During the nine months ended September 30, 2014 , the Company sold certain non-strategic properties in various areas to third parties for proceeds totaling $129.3 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 a portion of the Company's Northwest Cana properties in Oklahoma in September 2014. The disposed properties represented an immaterial portion of the Company’s total proved reserves, production, and revenues.

Subsequent Events (Notes)

Subsequent Events (Notes)	9 Months Ended
	Sep. 30, 2015
Subsequent Events [Abstract]
Subsequent Events [Text Block]	Subsequent Events New term loan On November 4, 2015 , the Company, as borrower, and its subsidiaries Banner Pipeline Company, L.L.C. and CLR Asset Holdings, LLC, as guarantors, entered into a Term Loan Agreement with MUFG Union Bank, N.A., as Administrative Agent, Bank of America, N.A., Citibank, N.A., JPMorgan Chase Bank, N.A. and Mizuho Bank, LTD., as Co-Syndication Agents, and Compass Bank, Toronto Dominion (Texas) LLC and U.S. Bank National Association, as Co-Documentation Agents, and the other lenders party thereto (the "Term Loan"). The Term Loan provides for aggregate lender commitments of $500 million , the full amount of which the Company borrowed at the closing of the Term Loan. The proceeds from the Term Loan were used to repay a portion of the borrowings outstanding on the Company's credit facility, which had a balance prior to repayment of $1.38 billion . The Term Loan will mature on November 4, 2018 and will bear interest at a market-based interest rate plus a margin that is based on the terms of the borrowing and the credit ratings assigned to the Company's senior, unsecured, long-term indebtedness. The initial per annum interest rate on the Term Loan is LIBOR plus 1.375%, which is 0.125% lower than the interest rate currently available under the Company's credit facility for similar borrowings. The terms of the Term Loan include covenants limiting the amount of debt that can be incurred by the Company’s subsidiaries that do not guarantee the Term Loan and that restrict the ability of the Company and its Restricted Subsidiaries (as such term is defined in the Term Loan) to incur liens and engage in sale and leaseback transactions. The Term Loan also contains a financial covenant that requires the Company to maintain a debt to capitalization ratio that does not exceed 0.65 to 1.0 and a covenant that restricts the ability of the Company to merge, consolidate or sell all or substantially all of its assets. The Term Loan includes events of default relating to customary matters, including, among other things, nonpayment of principal, interest or other amounts; violation of covenants; incorrectness of representations and warranties in any material respect; cross default and cross acceleration with respect to certain non-payments in connection with indebtedness in an aggregate principal amount of $100 million or more; bankruptcy; judgments involving liability of $100 million or more that are not paid; and ERISA events. Many events of default are subject to customary notice and cure periods. MUFG Union Bank, N.A. was the arranger and book runner for the Term Loan. In addition, certain of the lenders party to the Term Loan, and their respective affiliates, have performed, and may in the future perform, various commercial banking, investment banking and other financial advisory services for the Company and its subsidiaries for which they have received, and will receive, customary fees and expenses. The above description of the material terms and conditions of the Term Loan does not purport to be complete and is qualified in its entirety by reference to the full text of the Term Loan, which is filed as Exhibit 10.1 to this Form 10-Q. Increase in credit facility commitments On November 4, 2015 , the aggregate lender commitments on the Company's credit facility were increased from $2.5 billion to $2.75 billion to provide enhanced liquidity for the Company. After giving effect to the increased commitments and the use of proceeds from the $500 million Term Loan discussed above to repay borrowings outstanding under the Company's credit facility, the Company had approximately $880 million of outstanding borrowings and $1.87 billion of availability on its credit facility at November 4, 2015 .

Basis of Presentation and Sig18

Basis of Presentation and Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2015
Accounting Policies [Abstract]
Description of the Company	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 Kansas and all properties south of Kansas and west of the Mississippi River including various plays in the South Central Oklahoma Oil Province (“SCOOP”), Northwest Cana, and Arkoma areas of Oklahoma. The East region is comprised of undeveloped leasehold acreage east of the Mississippi River with no current drilling or production operations. The Company’s operations are geographically concentrated in the North region, with that region comprising 68% of the Company’s crude oil and natural gas production and 77% of its crude oil and natural gas revenues for the nine months ended September 30, 2015 . The Company's principal producing properties in the North region are located in the Bakken field of North Dakota and Montana. In recent years, the Company has significantly expanded its activity in the South region with its discovery and announcement of the SCOOP play in Oklahoma. The South region now comprises 32% of the Company's crude oil and natural gas production and 23% of its crude oil and natural gas revenues for the nine months ended September 30, 2015 . The Company has focused its operations on the exploration and development of crude oil since the 1980s. For the nine months ended September 30, 2015 , crude oil accounted for 67% of the Company’s total production and 86% of its crude oil and natural gas revenues.
Basis of Presentation	Basis of presentation The condensed consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are 100% owned. All significant intercompany accounts and transactions have been eliminated upon consolidation. This report has been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”) applicable to interim financial information. Because this is an interim period filing presented using a condensed format, it does not include all disclosures required by accounting principles generally accepted in the United States (“U.S. GAAP”), although the Company believes the disclosures are adequate to make the information not misleading. You should read this Quarterly Report on Form 10-Q ("Form 10-Q") together with the Company’s Annual Report on Form 10-K for the year ended December 31, 2014 (“ 2014 Form 10-K”), which includes a summary of the Company’s significant accounting policies and other disclosures. The condensed consolidated financial statements as of September 30, 2015 and for the three and nine month periods ended September 30, 2015 and 2014 are unaudited. The condensed consolidated balance sheet as of December 31, 2014 was derived from the audited balance sheet included in the 2014 Form 10-K. The Company has evaluated events or transactions through the date this report on Form 10-Q was filed with the SEC in conjunction with its preparation of these condensed consolidated financial statements. The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure and estimation of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Actual results may differ from those estimates. The most significant 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. In the opinion of management, all adjustments (consisting only of normal recurring adjustments) necessary for a fair presentation in accordance with U.S. GAAP have been included in these unaudited interim condensed consolidated financial statements. The results of operations for any interim period are not necessarily indicative of the results of operations that may be expected for any other interim period or for an entire year.
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. Diluted net income (loss) per share reflects the potential dilution of non-vested restricted stock awards, which are calculated using the treasury stock method.
Income Tax	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 period-end. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized. The Company recorded valuation allowances of $0.9 million and $13.3 million for the three and nine months ended September 30, 2015 , respectively, against deferred tax assets associated with operating loss carryforwards generated by its Canadian subsidiary in 2015 for which the Company does not expect to realize a benefit.
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.
New Accounting Pronouncements, Policy [Policy Text Block]	Adoption of new accounting pronouncement In April 2015, the Financial Accounting Standards Board issued Accounting Standards Update 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs ("ASU 2015-03") . The new standard requires debt issuance costs related to a recognized term debt liability, such as the Company's senior notes and note payable, be presented in the balance sheet as a direct deduction from the carrying amount of that term debt liability, consistent with the presentation of a debt discount. Under previous guidance, debt issuance costs were required to be presented in the balance sheet as an asset. The new standard does not affect the existing recognition and measurement guidance for debt issuance costs. The new standard is effective for annual and interim periods beginning after December 15, 2015, with early adoption permitted. The Company early adopted ASU 2015-03 as of June 30, 2015 on a retrospective basis to all prior balance sheet periods presented. As a result of the adoption, the Company reclassified unamortized debt issuance costs associated with its senior notes and note payable, which totaled $65.7 million and $69.0 million as of June 30, 2015 and December 31, 2014 , respectively, from "Other noncurrent assets" to a reduction of "Long-term debt, net of current portion" on the condensed consolidated balance sheets. Unamortized debt issuance costs reflected as a reduction of long-term debt subsequently totaled $64.0 million as of September 30, 2015 . Adoption of ASU 2015-03 had no impact on the Company's current and previously reported shareholders' equity, results of operations, or cash flows. The December 31, 2014 carrying amounts for the Company's senior notes and note payable presented throughout this report on Form 10-Q have been adjusted to reflect the retroactive adoption of ASU 2015-03. Unamortized debt issuance costs associated with the Company's credit facility, which amounted to $7.6 million and $7.0 million as of September 30, 2015 and December 31, 2014 , respectively, have not been reclassified and remain reflected in "Other noncurrent assets" on the condensed consolidated balance sheets.

Basis of Presentation and Sig19

Basis of Presentation and Significant Accounting Policies (Tables)	9 Months Ended
	Sep. 30, 2015
Accounting Policies [Abstract]
Components of Inventories	The components of inventory as of September 30, 2015 and December 31, 2014 consisted of the following: In thousands September 30, 2015 December 31, 2014 Tubular goods and equipment $ 15,936 $ 15,659 Crude oil 77,074 86,520 Total $ 93,010 $ 102,179
Calculation of Basic and Diluted Weighted Average Shares and Net Income Per Share	The following table presents the calculation of basic and diluted weighted average shares outstanding and net income (loss) per share for the three and nine months ended September 30, 2015 and 2014. Three months ended September 30, Nine months ended September 30, In thousands, except per share data 2015 2014 2015 2014 Income (loss) (numerator): Net income (loss) - basic and diluted $ (82,423 ) $ 533,521 $ (213,992 ) $ 863,293 Weighted average shares (denominator): Weighted average shares - basic 369,599 368,814 369,499 368,740 Non-vested restricted stock (1) — 1,714 — 1,892 Weighted average shares - diluted 369,599 370,528 369,499 370,632 Net income (loss) per share: Basic $ (0.22 ) $ 1.45 $ (0.58 ) $ 2.34 Diluted $ (0.22 ) $ 1.44 $ (0.58 ) $ 2.33 (1) The potential dilutive effect of approximately 688,800 and 1,521,000 weighted average restricted shares were not included in the calculation of diluted net loss per share for the three and nine months ended September 30, 2015 , respectively, because to do so would have been anti-dilutive.

Supplemental Cash Flow Inform20

Supplemental Cash Flow Information (Tables)	9 Months Ended
	Sep. 30, 2015
Supplemental Cash Flow Elements [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. Nine months ended September 30, In thousands 2015 2014 Supplemental cash flow information: Cash paid for interest $ 204,180 $ 173,057 Cash paid for income taxes 27 4,012 Cash received for income tax refunds 59,117 5 Non-cash investing activities: Increase (decrease) in accrued capital expenditures (482,475 ) 235,431 Asset retirement obligation additions and revisions, net 6,267 6,232

Derivative Instruments (Tables)

Derivative Instruments (Tables)	9 Months Ended
	Sep. 30, 2015
Summary of Outstanding Contracts with Respect to Natural Gas	Collars Natural Gas - NYMEX Henry Hub Swaps Weighted Average Price Floors Ceilings Weighted Average Price Weighted Average Price Period and Type of Contract MMBtus Range Range October 2015 - December 2015 Swaps - Henry Hub 9,780,000 $ 3.37 Collars - Henry Hub 7,360,000 $3.50 - $3.75 $ 3.69 $4.89 - $5.48 $ 5.04 January 2016 - December 2016 Swaps - Henry Hub 75,930,000 $ 3.85 January 2017 - December 2017 Swaps - Henry Hub 25,550,000 $ 3.35 Collars - Henry Hub 7,300,000 $ 3.00 $ 3.00 $ 3.88 $ 3.88
Realized and Unrealized Gains and Losses on Derivative Instruments	The following table presents cash settlements on matured derivative instruments and non-cash gains and losses on open derivative instruments for the periods presented. Cash receipts and payments below 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. Three months ended September 30, Nine months ended September 30, In thousands 2015 2014 2015 2014 Cash received (paid) on derivatives: Crude oil fixed price swaps $ — $ (4,126 ) $ — $ (77,148 ) Crude oil collars — (233 ) — (2,270 ) Natural gas fixed price swaps 5,142 4,549 29,084 (17,799 ) Natural gas collars 6,775 — 19,450 — Cash received (paid) on derivatives, net 11,917 190 48,534 (97,217 ) Non-cash gain (loss) on derivatives: Crude oil fixed price swaps — 416,637 — 228,845 Crude oil collars — 27,386 — 28,300 Crude oil written call options 617 — 4,544 — Natural gas fixed price swaps 36,257 25,851 33,453 7,944 Natural gas collars (2,264 ) 3,935 (11,986 ) 3,929 Non-cash gain on derivatives, net 34,610 473,809 26,011 269,018 Gain on derivative instruments, net $ 46,527 $ 473,999 $ 74,545 $ 171,801
Gross Amounts of Recognized Derivative Assets and Liabilities	The following table presents the gross amounts of recognized derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the condensed consolidated balance sheets for the periods presented, all at fair value. In thousands September 30, 2015 December 31, 2014 Commodity derivative assets: Gross amounts of recognized assets $ 105,881 $ 84,415 Gross amounts offset on balance sheet — — Net amounts of assets on balance sheet 105,881 84,415 Commodity derivative liabilities: Gross amounts of recognized liabilities (209 ) (4,770 ) Gross amounts offset on balance sheet — 16 Net amounts of liabilities on balance sheet $ (209 ) $ (4,754 )
Reconciles Net Amounts Derivative Assets and Liabilities	The following table reconciles the net amounts disclosed above to the individual financial statement line items in the condensed consolidated balance sheets. In thousands September 30, 2015 December 31, 2014 Derivative assets $ 78,610 $ 52,423 Noncurrent derivative assets 27,271 31,992 Net amounts of assets on balance sheet 105,881 84,415 Derivative liabilities (99 ) (1,645 ) Noncurrent derivative liabilities (110 ) (3,109 ) Net amounts of liabilities on balance sheet (209 ) (4,754 ) Total derivative assets, net $ 105,672 $ 79,661
NYMEX WTI [Member]
Summary of Outstanding Contracts with Respect to Crude Oil	At September 30, 2015 , the Company had outstanding derivative contracts with respect to future production as set forth in the tables below. Crude Oil - NYMEX WTI Ceilings Weighted Average Period and Type of Contract Bbls Range October 2015 - December 2015 Written call options - WTI (1) 1,104,000 $95.85 - $103.75 $ 98.36
ICE Brent [Member]
Summary of Outstanding Contracts with Respect to Crude Oil	Crude Oil - ICE Brent Ceilings Weighted Average Period and Type of Contract Bbls Range October 2015 - December 2015 Written call options - ICE Brent (1) 184,000 $ 107.40 $ 107.40 January 2016 - December 2016 Written call options - ICE Brent (1) 1,464,000 $ 107.70 $ 107.70

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2015
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 September 30, 2015 and December 31, 2014 . Fair value measurements at September 30, 2015 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets (liabilities): Fixed price swaps $ — $ 96,052 $ — $ 96,052 Collars — 9,829 — 9,829 Written call options — (209 ) — (209 ) Total $ — $ 105,672 $ — $ 105,672 Fair value measurements at December 31, 2014 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets (liabilities): Fixed price swaps $ — $ 62,599 $ — $ 62,599 Collars — 21,816 — 21,816 Written call options — (4,754 ) — (4,754 ) Total $ — $ 79,661 $ — $ 79,661
Quantitative Information about Significant Unobservable Inputs	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 strip prices through 2019 (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 50 years Discount rate 10%
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 unaudited condensed consolidated statements of comprehensive income (loss). Three months ended September 30, Nine months ended September 30, In thousands 2015 2014 2015 2014 Proved property impairments $ 36,302 $ 38,046 $ 111,346 $ 69,337 Unproved property impairments 60,395 47,515 209,784 153,748 Total $ 96,697 $ 85,561 $ 321,130 $ 223,085
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 condensed consolidated financial statements. September 30, 2015 December 31, 2014 In thousands Carrying Amount Fair Value Carrying Amount Fair Value Debt: Credit facility $ 1,345,000 $ 1,345,000 $ 165,000 $ 165,000 Note payable 14,832 13,300 16,375 14,900 7.375% Senior Notes due 2020 196,424 204,100 195,997 213,000 7.125% Senior Notes due 2021 395,184 412,000 394,668 421,000 5% Senior Notes due 2022 1,996,747 1,760,100 1,996,507 1,857,900 4.5% Senior Notes due 2023 1,481,945 1,290,000 1,480,479 1,372,800 3.8% Senior Notes due 2024 989,681 820,400 988,940 868,700 4.9% Senior Notes due 2044 691,016 504,800 690,912 572,400 Total debt $ 7,110,829 $ 6,349,700 $ 5,928,878 $ 5,485,700

Long-Term Debt (Tables)

Long-Term Debt (Tables)	9 Months Ended
	Sep. 30, 2015
Debt Disclosure [Abstract]
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 September 30, 2015 . 2020 Notes 2021 Notes 2022 Notes 2023 Notes 2024 Notes 2044 Notes Face value (in thousands) $200,000 $400,000 $2,000,000 $1,500,000 $1,000,000 $700,000 Maturity date Oct 1, 2020 April 1, 2021 Sep 15, 2022 April 15, 2023 June 1, 2024 June 1, 2044 Interest payment dates April 1, Oct 1 April 1, Oct 1 March 15, Sep 15 April 15, Oct 15 June 1, Dec 1 June 1, Dec 1 Call premium redemption period (1) Oct 1, 2015 April 1, 2016 March 15, 2017 — — — Make-whole redemption period (2) Oct 1, 2015 April 1, 2016 March 15, 2017 Jan 15, 2023 Mar 1, 2024 Dec 1, 2043 (1) On or after these dates, the Company has the option to redeem all or a portion of its senior notes of the applicable series at the decreasing redemption prices specified in the respective senior note indentures (together, the “Indentures”) 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 Indentures plus any accrued and unpaid interest to the date of redemption.
Schedule of Long-term Debt Instruments [Table Text Block]	Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $49.1 million and $52.6 million at September 30, 2015 and December 31, 2014 , respectively, consists of the following. See Note 2. Basis of Presentation and Significant Accounting Policies—Adoption of new accounting pronouncement for a discussion of the impact on long-term debt from the Company's adoption of ASU 2015-03. In thousands September 30, 2015 December 31, 2014 Credit facility $ 1,345,000 $ 165,000 Note payable 14,832 16,375 7.375% Senior Notes due 2020 196,424 195,997 7.125% Senior Notes due 2021 395,184 394,668 5% Senior Notes due 2022 1,996,747 1,996,507 4.5% Senior Notes due 2023 1,481,945 1,480,479 3.8% Senior Notes due 2024 989,681 988,940 4.9% Senior Notes due 2044 691,016 690,912 Total debt $ 7,110,829 $ 5,928,878 Less: Current portion of long-term debt 2,127 2,078 Long-term debt, net of current portion $ 7,108,702 $ 5,926,800

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	9 Months Ended
	Sep. 30, 2015
Restricted stock [Member]
Summary of Changes in Non-vested Shares of Restricted Stock Outstanding	A summary of changes in non-vested restricted shares outstanding for the nine months ended September 30, 2015 is presented below: Number of Weighted Non-vested restricted shares outstanding at December 31, 2014 2,678,764 $ 49.40 Granted 1,383,557 47.36 Vested (420,852 ) 45.92 Forfeited (291,999 ) 50.99 Non-vested restricted shares outstanding at September 30, 2015 3,349,470 $ 48.86

Accumulated Other Comprehensi25

Accumulated Other Comprehensive Income (Tables)	9 Months Ended
	Sep. 30, 2015
Accumulated Other 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 three and nine months ended September 30, 2015 : In thousands Three months ended September 30, 2015 Nine months ended September 30, 2015 Beginning accumulated other comprehensive loss, net of tax $ (2,865 ) $ (385 ) Foreign currency translation adjustments (438 ) (2,918 ) Income tax benefit (1) — — Other comprehensive loss, net of tax (438 ) (2,918 ) Ending accumulated other comprehensive loss, net of tax $ (3,303 ) $ (3,303 ) (1) A valuation allowance has been recognized against deferred tax assets associated with losses generated by the Company's Canadian operations, thereby resulting in no income taxes on other comprehensive loss for the period.

Organization and Nature of Bu26

Organization and Nature of Business - Additional Information (Detail)	9 Months Ended
	Sep. 30, 2015
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Percentage of crude oil and natural gas production concentrated in crude oil	67.00%
Percentage of crude oil and natural gas revenue concentrated in crude oil	86.00%
North Region [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Percentage of operations concentrated in geographic areas	68.00%
Percentage of revenues concentrated in geographic areas	77.00%
South Region [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Percentage of operations concentrated in geographic areas	32.00%
Percentage of revenues concentrated in geographic areas	23.00%

Basis of Presentation and Sig27

Basis of Presentation and Significant Accounting Policies - Components of Inventories (Detail) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Tubular goods and equipment	$ 15,936	$ 15,659
Crude oil	77,074	86,520
Total	$ 93,010	$ 102,179

Basis of Presentation and Sig28

Basis of Presentation and Significant Accounting Policies - Earnings Per Share (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Accounting Policies [Abstract]
Weighted Average Number Diluted Shares Outstanding Adjustment	688,800		1,521,000
Income (loss) (numerator):
Net income (loss) - basic and diluted	$ (82,423)	$ 533,521	$ (213,992)	$ 863,293
Weighted average shares - basic	369,599,000	368,814,000	369,499,000	368,740,000
Non-vested restricted stock (1)	0	1,714,000	0	1,892,000
Weighted average shares - diluted	369,599,000	370,528,000	369,499,000	370,632,000
Net income (loss) per share:
Basic (in dollars per share)	$ (0.22)	$ 1.45	$ (0.58)	$ 2.34
Diluted (in dollars per share)	$ (0.22)	$ 1.44	$ (0.58)	$ 2.33

Basis of Presentation and Sig29

Basis of Presentation and Significant Accounting Policies Basis of Presentation and Significant Accounting Policies - New Accounting Pronouncements (Details) - USD ($) $ in Millions	Sep. 30, 2015	Jun. 30, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Net debt issuance costs and other	$ 64	$ 65.7	$ 69
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Net debt issuance costs and other	$ 7.6		$ 7

Basis of Presentation and Sig30

Basis of Presentation and Significant Accounting Policies Basis of Presentation and Significant Accounting Policies - Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2015
Income Tax Disclosure [Abstract]
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	$ 0.9	$ 13.3

Supplemental Cash Flow Inform31

Supplemental Cash Flow Information - Summary of Supplemental Cash Flow Information (Detail) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Supplemental Cash Flow Elements [Abstract]
Cash paid for interest	$ 204,180	$ 173,057
Cash paid for income taxes	27	4,012
Cash received for income tax refunds	59,117	5
Noncash Investing Activities [Abstract]
Increase (decrease) in accrued capital expenditures	(482,475)	235,431
Increase (Decrease) in Asset Retirement Obligations	$ 6,267	$ 6,232

Derivative Instruments - Summar

Derivative Instruments - Summary of Outstanding Contracts with Respect to Crude Oil (Detail)	9 Months Ended
	Sep. 30, 2015$ / Barrelsbbl
West Texas Intermediate [Member] | Call Option October 2015 to December 2015
Derivative [Line Items]
Oil Production Derivative Volume | bbl	1,104,000
Derivative, Average Price Risk Option Strike Price	98.36
West Texas Intermediate [Member] | Minimum [Member] | Call Option October 2015 to December 2015
Derivative [Line Items]
Derivative, Price Risk Option Strike Price	95.85
West Texas Intermediate [Member] | Maximum [Member] | Call Option October 2015 to December 2015
Derivative [Line Items]
Derivative, Price Risk Option Strike Price	103.75
ICE Brent [Member] | Call Option October 2015 to December 2015
Derivative [Line Items]
Oil Production Derivative Volume | bbl	184,000
Derivative, Average Price Risk Option Strike Price	107.40
ICE Brent [Member] | Call Option January 2016 to December 2016 [Member]
Derivative [Line Items]
Oil Production Derivative Volume | bbl	1,464,000
Derivative, Average Price Risk Option Strike Price	107.70

Derivative Instruments - Summ33

Derivative Instruments - Summary of Outstanding Contracts with Respect to Natural Gas (Detail) - Natural Gas [Member]	9 Months Ended
	Sep. 30, 2015MMBTU$ / MMBTU$ / bbl
October 2015 to December 2015 Swaps
Derivative [Line Items]
Natural Gas Production Derivative Volume, MMBtus | MMBTU	9,780,000
Swaps Weighted Average Price	3.37
October 2015 to December 2015 Collars
Derivative [Line Items]
Natural Gas Production Derivative Volume, MMBtus | MMBTU	7,360,000
Floors, Weighted Average Price	3.69
Ceilings, Weighted Average Price	5.04
January 2016 to December 2016 Swaps
Derivative [Line Items]
Natural Gas Production Derivative Volume, MMBtus | MMBTU	75,930,000
Swaps Weighted Average Price | $ / MMBTU	3.85
January 2017 to December 2017 Swaps
Derivative [Line Items]
Natural Gas Production Derivative Volume, MMBtus | MMBTU	25,550,000
Swaps Weighted Average Price | $ / MMBTU	3.35
January 2017 to December 2017 Collars
Derivative [Line Items]
Natural Gas Production Derivative Volume, MMBtus | MMBTU	7,300,000
Floors, Weighted Average Price	3
Ceilings, Weighted Average Price	3.88
Minimum [Member] | October 2015 to December 2015 Collars
Derivative [Line Items]
Derivative, Floor Price	3.50
Derivative, Cap Price	4.89
Maximum [Member] | October 2015 to December 2015 Collars
Derivative [Line Items]
Derivative, Floor Price	3.75
Derivative, Cap Price	5.48

Derivative Instruments - Realiz

Derivative Instruments - Realized and Unrealized Gains and Losses on Derivative Instruments (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net	$ 11,917	$ 190	$ 48,534	$ (97,217)
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net	34,610	473,809	26,011	269,018
Gain on derivative instruments, net	46,527	473,999	74,545	171,801
Swap [Member] | Crude Oil [Member]
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net	0	(4,126)	0	(77,148)
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net	0	416,637	0	228,845
Swap [Member] | Natural Gas [Member]
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net	5,142	4,549	29,084	(17,799)
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net	36,257	25,851	33,453	7,944
Collars | Crude Oil [Member]
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net	0	(233)	0	(2,270)
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net	0	27,386	0	28,300
Collars | Natural Gas [Member]
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net	6,775	0	19,450	0
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net	(2,264)	3,935	(11,986)	3,929
Call Option [Member] | Crude Oil [Member]
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net	$ 617	$ 0	$ 4,544	$ 0

Derivative Instruments - Gross

Derivative Instruments - Gross Amounts of Recognized Derivative Assets and Liabilities (Detail) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Gross amounts of recognized assets	$ 105,881	$ 84,415
Derivative Asset, Fair Value, Gross Asset	0	0
Net amounts of assets on balance sheet	105,881	84,415
Gross amounts of recognized liabilities	(209)	(4,770)
Derivative Liability, Fair Value, Gross Asset	0	16
Net amounts of liabilities on balance sheet	$ (209)	$ (4,754)

Derivative Instruments - Reconc

Derivative Instruments - Reconciles Net Amounts Derivative Assets and Liabilities (Detail) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative assets	$ 78,610	$ 52,423
Noncurrent derivative assets	27,271	31,992
Net amounts of assets on balance sheet	105,881	84,415
Derivative liabilities	(99)	(1,645)
Noncurrent derivative liabilities	(110)	(3,109)
Net amounts of liabilities on balance sheet	(209)	(4,754)
Total derivative assets, net	$ 105,672	$ 79,661

Fair Value Measurements - Valua

Fair Value Measurements - Valuation of Financial Instruments by Pricing Levels (Detail) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Derivative assets (liabilities):
Derivative assets (liabilities)	$ 105,672	$ 79,661
Fixed price swaps
Derivative assets (liabilities):
Derivative assets (liabilities)	96,052	62,599
Collars
Derivative assets (liabilities):
Derivative assets (liabilities)	9,829	21,816
Call Option [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	(209)	(4,754)
Fair Value, Inputs, Level 1 [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0	0
Fair Value, Inputs, Level 1 [Member] | Fixed price swaps
Derivative assets (liabilities):
Derivative assets (liabilities)	0	0
Fair Value, Inputs, Level 1 [Member] | Collars
Derivative assets (liabilities):
Derivative assets (liabilities)	0	0
Fair Value, Inputs, Level 1 [Member] | Call Option [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0	0
Fair Value, Inputs, Level 2 [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	105,672	79,661
Fair Value, Inputs, Level 2 [Member] | Fixed price swaps
Derivative assets (liabilities):
Derivative assets (liabilities)	96,052	62,599
Fair Value, Inputs, Level 2 [Member] | Collars
Derivative assets (liabilities):
Derivative assets (liabilities)	9,829	21,816
Fair Value, Inputs, Level 2 [Member] | Call Option [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	(209)	(4,754)
Fair Value, Inputs, Level 3 [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0	0
Fair Value, Inputs, Level 3 [Member] | Fixed price swaps
Derivative assets (liabilities):
Derivative assets (liabilities)	0	0
Fair Value, Inputs, Level 3 [Member] | Collars
Derivative assets (liabilities):
Derivative assets (liabilities)	0	0
Fair Value, Inputs, Level 3 [Member] | Call Option [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	$ 0	$ 0

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Detail)	9 Months Ended
	Sep. 30, 2015
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%
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)	50 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		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved property impairments	$ 36,302	$ 38,046	$ 111,346	$ 69,337
Unproved property impairments	60,395	47,515	209,784	153,748
Oil and gas property fair value after impairment	48,500	15,400	48,500	15,400
Property impairments	96,697	$ 85,561	321,130	$ 223,085
Emerging Areas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved property impairments	1,300		42,500
Red River Units [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved property impairments	26,300		26,300
Non-Bakken North Region [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved property impairments	100		8,200
Medicine Pole Hill Units [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved property impairments	8,200		22,900
South Region [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved property impairments	$ 400		$ 11,400

Fair Value Measurements - Fair

Fair Value Measurements - Fair Values of Financial Instruments not Recorded at Fair Value (Detail) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
7.375% Senior Notes due 2020
Fair Value Measurements [Line Items]
Debt Instrument, stated interest rate	7.375%
Debt Instrument, Maturity Date, Description	2,020
7.125% Senior Notes due 2021
Fair Value Measurements [Line Items]
Debt Instrument, stated interest rate	7.125%
Debt Instrument, Maturity Date, Description	2,021
5% Senior Notes due 2022
Fair Value Measurements [Line Items]
Debt Instrument, stated interest rate	5.00%
Debt Instrument, Maturity Date, Description	2,022
4.5% Senior Notes due 2023
Fair Value Measurements [Line Items]
Debt Instrument, stated interest rate	4.50%
Debt Instrument, Maturity Date, Description	2,023
3.8% Senior Notes due 2024
Fair Value Measurements [Line Items]
Debt Instrument, stated interest rate	3.80%
Debt Instrument, Maturity Date, Description	2,024
4.9% Senior Notes due 2044
Fair Value Measurements [Line Items]
Debt Instrument, stated interest rate	4.90%
Debt Instrument, Maturity Date, Description	2,044
Carrying Amount
Fair Value Measurements [Line Items]
Credit facility	$ 1,345,000	$ 165,000
Note payable	14,832	16,375
Total debt	7,110,829	5,928,878
Carrying Amount | 7.375% Senior Notes due 2020
Fair Value Measurements [Line Items]
Senior notes	196,424	195,997
Carrying Amount | 7.125% Senior Notes due 2021
Fair Value Measurements [Line Items]
Senior notes	395,184	394,668
Carrying Amount | 5% Senior Notes due 2022
Fair Value Measurements [Line Items]
Senior notes	1,996,747	1,996,507
Carrying Amount | 4 1/2% Senior Notes Due 2023
Fair Value Measurements [Line Items]
Senior notes	1,481,945	1,480,479
Carrying Amount | 3.8% Senior Notes due 2024
Fair Value Measurements [Line Items]
Senior notes	989,681	988,940
Carrying Amount | 4.9% Senior Notes due 2044
Fair Value Measurements [Line Items]
Senior notes	691,016	690,912
Fair Value
Fair Value Measurements [Line Items]
Credit facility	1,345,000	165,000
Note payable	13,300	14,900
Total debt	6,349,700	5,485,700
Fair Value | 7.375% Senior Notes due 2020
Fair Value Measurements [Line Items]
Senior notes	204,100	213,000
Fair Value | 7.125% Senior Notes due 2021
Fair Value Measurements [Line Items]
Senior notes	412,000	421,000
Fair Value | 5% Senior Notes due 2022
Fair Value Measurements [Line Items]
Senior notes	1,760,100	1,857,900
Fair Value | 4 1/2% Senior Notes Due 2023
Fair Value Measurements [Line Items]
Senior notes	1,290,000	1,372,800
Fair Value | 3.8% Senior Notes due 2024
Fair Value Measurements [Line Items]
Senior notes	820,400	868,700
Fair Value | 4.9% Senior Notes due 2044
Fair Value Measurements [Line Items]
Senior notes	$ 504,800	$ 572,400

Long-Term Debt - Long-Term Debt

Long-Term Debt - Long-Term Debt (Detail) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Less: Current portion of long-term debt	$ (2,127)	$ (2,078)
Long-term debt, net of current portion	$ 7,108,702	5,926,800
7.375% Senior Notes due 2020
Debt Instrument [Line Items]
Debt Instrument, stated interest rate	7.375%
7.125% Senior Notes due 2021
Debt Instrument [Line Items]
Debt Instrument, stated interest rate	7.125%
5% Senior Notes due 2022
Debt Instrument [Line Items]
Debt Instrument, stated interest rate	5.00%
Note Payable [Member]
Debt Instrument [Line Items]
Debt Instrument, stated interest rate	3.14%
Note payable	$ 22,000
3.8% Senior Notes due 2024
Debt Instrument [Line Items]
Debt Instrument, stated interest rate	3.80%
4.9% Senior Notes due 2044
Debt Instrument [Line Items]
Debt Instrument, stated interest rate	4.90%
Carrying Amount
Debt Instrument [Line Items]
Credit facility	$ 1,345,000	165,000
Note payable	14,832	16,375
Total debt	7,110,829	5,928,878
Carrying Amount | 7.375% Senior Notes due 2020
Debt Instrument [Line Items]
Senior notes	196,424	195,997
Carrying Amount | 7.125% Senior Notes due 2021
Debt Instrument [Line Items]
Senior notes	395,184	394,668
Carrying Amount | 5% Senior Notes due 2022
Debt Instrument [Line Items]
Senior notes	1,996,747	1,996,507
Carrying Amount | 4 1/2% Senior Notes Due 2023
Debt Instrument [Line Items]
Senior notes	1,481,945	1,480,479
Carrying Amount | 3.8% Senior Notes due 2024
Debt Instrument [Line Items]
Senior notes	989,681	988,940
Carrying Amount | 4.9% Senior Notes due 2044
Debt Instrument [Line Items]
Senior notes	691,016	690,912
Fair Value
Debt Instrument [Line Items]
Credit facility	1,345,000	165,000
Note payable	13,300	14,900
Total debt	6,349,700	5,485,700
Fair Value | 7.375% Senior Notes due 2020
Debt Instrument [Line Items]
Senior notes	204,100	213,000
Fair Value | 7.125% Senior Notes due 2021
Debt Instrument [Line Items]
Senior notes	412,000	421,000
Fair Value | 5% Senior Notes due 2022
Debt Instrument [Line Items]
Senior notes	1,760,100	1,857,900
Fair Value | 4 1/2% Senior Notes Due 2023
Debt Instrument [Line Items]
Senior notes	1,290,000	1,372,800
Fair Value | 3.8% Senior Notes due 2024
Debt Instrument [Line Items]
Senior notes	820,400	868,700
Fair Value | 4.9% Senior Notes due 2044
Debt Instrument [Line Items]
Senior notes	$ 504,800	$ 572,400

Long-Term Debt - Additional Inf

Long-Term Debt - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	1.70%		1.70%
Line of credit facility, maturity date			May 16, 2019
Aggregate amount of lender commitments on credit facility	$ 2,500,000		$ 2,500,000
Line of Credit Facility, Maximum Borrowing Capacity	4,000,000		$ 4,000,000
Line of credit facility, commitment fee percentage, per annum			0.225%
Current portion of long-term debt	2,127		$ 2,127		$ 2,078
Total Redemption Amount		$ 317,500		$ 317,500
Line of Credit Facility, Covenant Terms			0.65
Loss on Extinguishment of Debt	0	$ (24,517)	$ 0	$ (24,517)
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity	$ 1,150,000		$ 1,150,000
4.5% Senior Notes due 2023
Debt Instrument [Line Items]
Debt Instrument, stated interest rate	4.50%		4.50%
Debt Instrument, Maturity Date, Description			2,023
Note Payable [Member]
Debt Instrument [Line Items]
Notes Payable	$ 22,000		$ 22,000
Loan term			10 years
Debt Instrument, stated interest rate	3.14%		3.14%
Debt Instrument, Maturity Date			Feb. 26, 2022
7.375% Senior Notes due 2020
Debt Instrument [Line Items]
Debt Instrument, stated interest rate	7.375%		7.375%
Debt Instrument, Maturity Date, Description			2,020
7.125% Senior Notes due 2021
Debt Instrument [Line Items]
Debt Instrument, stated interest rate	7.125%		7.125%
Debt Instrument, Maturity Date, Description			2,021
5% Senior Notes due 2022
Debt Instrument [Line Items]
Debt Instrument, stated interest rate	5.00%		5.00%
Debt Instrument, Maturity Date, Description			2,022
3.8% Senior Notes due 2024
Debt Instrument [Line Items]
Debt Instrument, stated interest rate	3.80%		3.80%
Debt Instrument, Maturity Date, Description			2,024
4.9% Senior Notes due 2044
Debt Instrument [Line Items]
Debt Instrument, stated interest rate	4.90%		4.90%
Debt Instrument, Maturity Date, Description			2,044
Carrying Amount
Debt Instrument [Line Items]
Credit facility	$ 1,345,000		$ 1,345,000		165,000
Notes Payable	14,832		14,832		16,375
Carrying Amount | 7.375% Senior Notes due 2020
Debt Instrument [Line Items]
Senior notes	196,424		196,424		195,997
Carrying Amount | 7.125% Senior Notes due 2021
Debt Instrument [Line Items]
Senior notes	395,184		395,184		394,668
Carrying Amount | 5% Senior Notes due 2022
Debt Instrument [Line Items]
Senior notes	1,996,747		1,996,747		1,996,507
Carrying Amount | 3.8% Senior Notes due 2024
Debt Instrument [Line Items]
Senior notes	989,681		989,681		988,940
Carrying Amount | 4.9% Senior Notes due 2044
Debt Instrument [Line Items]
Senior notes	$ 691,016		$ 691,016		$ 690,912

Long-Term Debt Long-Term Debt -

Long-Term Debt Long-Term Debt - Summary of Maturity Dates, Semi-Annual Interest Payment Dates, and Optional Redemption Periods of Outstanding Senior Note Obligations (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2015USD ($)
2020 Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 200,000
Maturity date	Oct. 1, 2020
Interest payment dates	April 1, Oct 1
Call premium redemption period	Oct. 1, 2015
Make-whole redemption period	Oct. 1, 2015
2021 Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 400,000
Maturity date	Apr. 1, 2021
Interest payment dates	April 1, Oct 1
Call premium redemption period	Apr. 1, 2016
Make-whole redemption period	Apr. 1, 2016
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
Call premium redemption period	Mar. 15, 2017
Make-whole redemption period	Mar. 15, 2017
2023 Notes [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	Jan. 15, 2023
2024 Notes [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	Mar. 1, 2024
2044 Notes [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	Dec. 1, 2043

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail) - USD ($) $ in Millions	1 Months Ended	9 Months Ended
	Nov. 30, 2010	Sep. 30, 2015	Dec. 31, 2014
Long-term Purchase Commitment [Line Items]
Total future drilling commitments at balance sheet date		$ 475
Drilling commitments due remainder of current year		59
Drilling commitments Year Two		220
Drilling Commitments Year Three		129
Drilling Commitments Year Four		62
Drilling Commitments Year Five		$ 5
Future Drilling Commitments End Date		2019-03
Damages sought in litigation matter	$ 200
Legal proceedings recorded as a liability under other noncurrent liabilities		$ (6.1)	$ (2.9)
Fuel Purchase Commitment End Date		2016-06
Pipeline Transportation Commitments [Member]
Long-term Purchase Commitment [Line Items]
Pipeline commitments, end date		2,027
Purchase Obligation, total		$ 1,100
Purchase Obligation, due in remainder of current year		52
Purchase Obligation, due second year		213
Purchase Obligation, due third year		210
Purchase Obligation, due fourth year		206
Purchase Obligation, due fifth year		170
Purchase Obligation, Due after Fifth Year		217
Non-operational [Member]
Long-term Purchase Commitment [Line Items]
Previous crude oil non-op transportation commitment, total		260
Fuel [Member]
Long-term Purchase Commitment [Line Items]
Purchase Obligation, total		47
Purchase Obligation, due in remainder of current year		16
Purchase Obligation, due second year		$ 31

Stock Based Compensation - Stoc

Stock Based Compensation - Stock Based Compensation Expenses (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Non-cash equity compensation	$ 12.9	$ 13.4	$ 40.3	$ 39.4

Stock-Based Compensation - Addi

Stock-Based Compensation - Additional Information (Detail) $ in Millions	9 Months Ended
	Sep. 30, 2015USD ($)shares
Restricted stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock available to grant	17,027,803
Fair value at vesting date | $	$ 19.1
Unrecognized compensation expense related to non-vested | $	$ 81
Unrecognized compensation expense related to non-vested, period for recognition, in years	1 year 5 months 1 day
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

Stock Based Compensation - Summ

Stock Based Compensation - Summary of Changes in Non Vested Shares of Restricted Stock Outstanding (Detail)	9 Months Ended
	Sep. 30, 2015$ / sharesshares
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	2,678,764
Granted (unaudited), shares	1,383,557
Vested shares	(420,852)
Forfeited (unaudited), shares	(291,999)
Non-vested shares, ending balance	3,349,470
Non-vested, weighted average grant-date fair value, beginning of period | $ / shares	$ 49.40
Granted, weighted average grant-date fair value | $ / shares	47.36
Vested, weighted average grant-date fair value | $ / shares	45.92
Forfeited, weighted average grant-date fair value | $ / shares	50.99
Non-vested, weighted average grant-date fair value, end of period | $ / shares	$ 48.86

Accumulated Other Comprehensi48

Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Jun. 30, 2015	Dec. 31, 2014
Accumulated Other Comprehensive Income [Abstract]
Accumulated Other Comprehensive Income (Loss), Net of Tax	$ (3,303)		$ (3,303)		$ (2,865)	$ (385)
Foreign Currency Transaction and Translation Loss Arising During Period, Net of Tax	(438)	$ 0	(2,918)	$ 0
Translation Adjustment Functional to Reporting Currency, Tax Benefit (Expense)	0		0
Other Comprehensive Loss, Net of Tax (unaudited)	$ (438)	$ 0	$ (2,918)	$ 0

Property Dispositions - Additio

Property Dispositions - Additional Information (Detail) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Property Dispositions (Line Items)
Proceeds from sale of assets	$ 33,216	$ 129,346
OKLAHOMA
Property Dispositions (Line Items)
Proceeds from sale of assets	25,900
Recognized pre-tax gain (loss)	$ 20,500
COLORADO
Property Dispositions (Line Items)
Proceeds from sale of assets		30,300
Northwest Cana [Member]
Property Dispositions (Line Items)
Proceeds from sale of assets		$ 85,800

Subsequent Events (Details)

Subsequent Events (Details) - USD ($) $ in Millions	Nov. 02, 2015	Oct. 31, 2015	Sep. 30, 2015
Subsequent Event [Line Items]
Aggregate amount of lender commitments on credit facility			$ 2,500
Subsequent Event [Member]
Subsequent Event [Line Items]
Other Loans Payable, Long-term, Noncurrent	$ 500
Aggregate amount of lender commitments on credit facility	2,750
Credit facility	880	$ 1,380
Revolving Credit Facility [Member]
Subsequent Event [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity			$ 1,150
Revolving Credit Facility [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity	$ 1,870