Continental Resources Inc (CLR) 10-Q 9 Aug 17 2017 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2017	Jul. 31, 2017
Document Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q2
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		375,219,152

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 17,190	$ 16,643
Receivables:
Crude oil and natural gas sales	385,975	404,750
Affiliated parties	58	99
Joint interest and other, net	402,391	364,850
Derivative assets	17,809	4,061
Inventories	97,003	111,987
Prepaid expenses and other	13,616	10,843
Total current assets	934,042	913,233
Net property and equipment, based on successful efforts method of accounting	12,921,875	12,881,227
Other noncurrent assets	15,340	17,316
Total assets	13,871,257	13,811,776
Current liabilities:
Accounts payable trade	689,772	476,342
Revenues and royalties payable	238,530	217,425
Payables to affiliated parties	218	148
Accrued liabilities and other	159,391	176,770
Derivative liabilities	4,817	59,489
Current portion of long-term debt	2,250	2,219
Total current liabilities	1,094,978	932,393
Long-term debt, net of current portion	6,553,740	6,577,697
Other noncurrent liabilities:
Deferred income tax liabilities, net	1,853,321	1,890,305
Asset retirement obligations, net of current portion	100,470	94,436
Other noncurrent liabilities	14,413	14,949
Total other noncurrent liabilities	1,968,204	1,999,690
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; 375,206,922 shares issued and outstanding at June 30, 2017; 374,492,357 shares issued and outstanding at December 31, 2016	3,752	3,745
Additional paid-in capital	1,385,233	1,375,290
Accumulated other comprehensive income (loss)	67	(260)
Retained earnings	2,865,283	2,923,221
Total shareholders’ equity	4,254,335	4,301,996
Total liabilities and shareholders’ equity	$ 13,871,257	$ 13,811,776

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets (Parenthetical) - $ / shares	Jun. 30, 2017	Dec. 31, 2016
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	1,000,000,000
Common Stock, Shares, Issued	375,206,922	374,492,357
Common Stock, Shares, Outstanding	375,206,922	374,492,357

Unaudited Condensed Consolidate

Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Revenues:
Crude oil and natural gas sales	$ 626,548	$ 525,711	$ 1,260,398	$ 929,302
Gain (loss) on crude oil and natural gas derivatives, net	28,022	(82,257)	74,880	(40,145)
Crude oil and natural gas service operations	6,916	7,757	11,636	15,227
Total revenues	661,486	451,211	1,346,914	904,384
Operating costs and expenses:
Production expenses	82,474	74,083	155,328	152,724
Production taxes	41,965	39,141	83,198	69,634
Exploration expenses	3,204	1,674	8,202	4,739
Crude oil and natural gas service operations	4,478	3,576	7,315	6,618
Depreciation, depletion, amortization and accretion	395,770	441,761	777,926	905,752
Property impairments	123,316	66,112	174,689	145,039
General and administrative expenses	39,186	36,246	86,407	68,654
Net (gain) loss on sale of assets and other	134	(100,835)	5,669	(99,127)
Total operating costs and expenses	690,527	561,758	1,298,734	1,254,033
Income (loss) from operations	(29,041)	(110,547)	48,180	(349,649)
Other income (expense):
Interest expense	(72,744)	(81,922)	(143,916)	(162,875)
Other	373	435	815	819
Total other income (expense)	(72,371)	(81,487)	(143,101)	(162,056)
Loss before income taxes	(101,412)	(192,034)	(94,921)	(511,705)
Benefit for income taxes	37,855	72,632	31,833	193,978
Net loss	(63,557)	(119,402)	(63,088)	(317,727)
Foreign currency translation adjustments	189	25	327	451
Total other comprehensive income, net of tax	189	25	327	451
Comprehensive loss	$ (63,368)	$ (119,377)	$ (62,761)	$ (317,276)
Basic net income (loss) per share (in dollars per share)	$ (0.17)	$ (0.32)	$ (0.17)	$ (0.86)
Diluted net income (loss) per share (in dollars per share)	$ (0.17)	$ (0.32)	$ (0.17)	$ (0.86)

Condensed Consolidated Statemen

Condensed Consolidated Statements of Shareholders Equity - 6 months ended Jun. 30, 2017 - USD ($) $ in Thousands	Total	Common Stock [Member]	Additional Paid-In Capital [Member]	Accumulated Other Comprehensive Loss [Member]	Retained Earnings [Member]
Balance at Dec. 31, 2016	$ 4,301,996	$ 3,745	$ 1,375,290	$ (260)	$ 2,923,221
Balance, shares at Dec. 31, 2016	374,492,357	374,492,357
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Adoption of ASU 2016-09 cumulative effect on retained earnings	$ 5,150				5,150
Net income (unaudited)	(63,088)				(63,088)
Other comprehensive income, net of tax (unaudited)	327			327
Stock-based compensation (unaudited)	20,561		20,561
Restricted stock:
Granted (unaudited)	$ 14	$ 14
Granted (unaudited), shares	1,464,944	1,464,944
Repurchased and canceled (unaudited)	$ (10,620)	$ (2)	(10,618)
Repurchased and canceled (unaudited), shares	(230,377)	(230,377)
Forfeited (unaudited), shares	(520,002)	(520,002)
Forfeitures (unaudited)	$ (5)	$ (5)
Balance at Jun. 30, 2017	$ 4,254,335	$ 3,752	$ 1,385,233	$ 67	$ 2,865,283
Balance, shares at Jun. 30, 2017	375,206,922	375,206,922

Unaudited Condensed Consolidat6

Unaudited Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Cash flows from operating activities
Net loss	$ (63,088)	$ (317,727)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, Depletion, Amortization and Accretion	774,810	908,021
Property impairments	174,689	145,039
Non-cash (gain) loss on derivatives, net	(68,420)	114,972
Stock-based compensation	20,571	21,046
Benefit for deferred income taxes	(31,834)	(193,990)
Dry hole costs	157	206
(Gain) loss on sale of assets, net	2,859	(97,016)
Other, net	5,089	4,752
Changes in assets and liabilities:
Accounts receivable	(19,347)	(34,939)
Inventories	14,984	(8,745)
Other current assets	(2,225)	(2,125)
Accounts payable trade	105,441	(53,859)
Revenues and royalties payable	21,105	(742)
Accrued liabilities and other	(17,968)	15,347
Other noncurrent assets and liabilities	(251)	(2,519)
Net cash provided by operating activities	916,572	497,721
Cash flows from investing activities
Exploration and development	(877,115)	(625,126)
Purchase of producing crude oil and natural gas properties	(812)	0
Purchase of other property and equipment	(9,372)	(4,867)
Proceeds from sale of assets	7,979	112,199
Net cash used in investing activities	(879,320)	(517,794)
Cash flows from financing activities
Credit facility borrowings	540,000	638,000
Repayment of credit facility	(565,000)	(606,000)
Repayment of other debt	(1,099)	(1,064)
Debt issuance costs	0	(40)
Repurchase of restricted stock for tax withholdings	(10,620)	(5,735)
Net cash (used in) provided by financing activities	(36,719)	25,161
Effect of Exchange Rate on Cash and Cash Equivalents	14	9
Net change in cash and cash equivalents	547	5,097
Cash and cash equivalents at beginning of period	16,643	11,463
Cash and cash equivalents at end of period	$ 17,190	$ 16,560

Organization and Nature of Busi

Organization and Nature of Business	6 Months Ended
	Jun. 30, 2017
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 all properties south of Nebraska and west of the Mississippi River including various plays in the SCOOP (South Central Oklahoma Oil Province), STACK (Sooner Trend Anadarko Canadian Kingfisher), and Arkoma Woodford areas of Oklahoma. The East region is primarily comprised of undeveloped leasehold acreage east of the Mississippi River with no significant drilling or production operations. A substantial portion of the Company’s operations are located in the North region, with that region comprising approximately 57% of the Company’s crude oil and natural gas production and approximately 66% of its crude oil and natural gas revenues for the six months ended June 30, 2017 . 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 operations in the South region with its increased activity in the SCOOP and STACK plays. The South region comprised approximately 43% of the Company's crude oil and natural gas production and approximately 34% of its crude oil and natural gas revenues for the six months ended June 30, 2017 . For the six months ended June 30, 2017 , crude oil accounted for approximately 56% of the Company’s total production and approximately 76% of its crude oil and natural gas revenues.

Basis of Presentation and Signi

Basis of Presentation and Significant Accounting Policies	6 Months Ended
	Jun. 30, 2017
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, after 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, 2016 (“ 2016 Form 10-K”), which includes a summary of the Company’s significant accounting policies and other disclosures. The condensed consolidated financial statements as of June 30, 2017 and for the three and six month periods ended June 30, 2017 and 2016 are unaudited. The condensed consolidated balance sheet as of December 31, 2016 was derived from the audited balance sheet included in the 2016 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 and diluted net loss per share is computed by dividing net loss by the weighted-average number of shares outstanding for the period. In periods where the Company has net income, diluted earnings per share reflects the potential dilution of non-vested restricted stock awards, which are calculated using the treasury stock method. The following table presents the calculation of basic and diluted weighted average shares outstanding and net loss per share for the three and six months ended June 30, 2017 and 2016 . Three months ended June 30, Six months ended June 30, In thousands, except per share data 2017 2016 2017 2016 Net loss (numerator) $ (63,557 ) $ (119,402 ) $ (63,088 ) $ (317,727 ) Weighted average shares (denominator): Weighted average shares - basic 371,111 370,435 370,972 370,248 Non-vested restricted stock (1) — — — — Weighted average shares - diluted 371,111 370,435 370,972 370,248 Net loss per share: Basic $ (0.17 ) $ (0.32 ) $ (0.17 ) $ (0.86 ) Diluted $ (0.17 ) $ (0.32 ) $ (0.17 ) $ (0.86 ) (1) For the three and six months ended June 30, 2017, the Company had a net loss and therefore the potential dilutive effect of approximately 1,933,200 and 2,546,200 weighted average non-vested restricted shares, respectively, were not included in the calculation of diluted net loss per share because to do so would have been anti-dilutive to the computations. The Company also had net losses for the three and six months ended June 30, 2016, and therefore approximately 1,940,700 and 1,486,200 weighted average non-vested restricted shares, respectively, were not included in the calculation of diluted net loss per share for those periods. 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 June 30, 2017 and December 31, 2016 consisted of the following: In thousands June 30, 2017 December 31, 2016 Tubular goods and equipment $ 15,723 $ 15,243 Crude oil 81,280 96,744 Total $ 97,003 $ 111,987 Adoption of new accounting pronouncements Stock-based compensation – In March 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting , which changes how companies account for certain aspects of share-based payment awards, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. The Company adopted the new standard on January 1, 2017 as required. The impact of adoption is described below. ASU 2016-09 removes the requirement to delay recognition of an excess tax benefit until it reduces current taxes payable. An excess tax benefit (tax deficiency) arises when stock-based compensation expense recognized in an entity’s tax return exceeds (is less than) the expense recognized in an entity’s financial statements. Under the new standard, effective January 1, 2017 excess tax benefits are recorded when they arise. This change was required to be applied on a modified retrospective basis by recording a cumulative effect adjustment to opening retained earnings upon adoption to account for previously unrecognized excess tax benefits. The Company's cumulative effect adjustment recorded under the new standard resulted in a $5.2 million increase in retained earnings and corresponding decrease in deferred income tax liabilities at January 1, 2017. Additionally, under ASU 2016-09 companies no longer record excess tax benefits and deficiencies in additional paid-in capital. Instead, excess tax benefits and deficiencies are recognized as income tax benefit or expense in the income statement, effective January 1, 2017 on a prospective basis. This is expected to result in increased volatility in income tax expense/benefit and corresponding variations in the relationship between income tax expense/benefit and pre-tax income/loss from period to period. The Company recognized $0.5 million ( $0.00 per share) and $3.8 million ( $0.01 per share) of tax deficiencies from stock-based compensation as income tax expense for the three and six months ended June 30, 2017 , respectively, under the new standard, which are reflected in "Benefit for income taxes" in the unaudited condensed consolidated statements of comprehensive loss. ASU 2016-09 also removed the requirement that entities present excess tax benefits and deficiencies as offsetting cash flows from financing and operating activities in the statement of cash flows. Instead, ASU 2016-09 requires cash flows related to excess tax benefits and deficiencies be classified as operating activities in the same manner as other cash flows related to income taxes. The Company has elected to apply this guidance on a prospective basis. Accordingly, the cash flow presentation of excess tax benefits and deficiencies in periods prior to January 1, 2017, if applicable, will not be adjusted to conform to current period presentation. The Company has elected to continue its historical accounting practice of estimating forfeitures in determining the amount of stock-based compensation expense to recognize. Therefore, the adoption of ASU 2016-09 does not have an impact on the amount of stock-based compensation expense to be recognized by the Company on non-vested restricted stock awards. Business combinations – In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business , which changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities is deemed to be a business. Determining whether a transferred set constitutes a business is important because the accounting for a business combination differs from that of an asset acquisition. The definition of a business also affects the accounting for dispositions. Under the new standard, when substantially all of the fair value of assets acquired is concentrated in a single asset, or a group of similar assets, the assets acquired would not represent a business and business combination accounting would not be required. The new standard may result in more transactions being accounted for as asset acquisitions rather than business combinations. The standard is effective for interim and annual periods beginning after December 15, 2017 and shall be applied prospectively. The Company early adopted ASU 2017-01 as of January 1, 2017, which had no significant impact on the Company's financial statements as of and for the three and six months ended June 30, 2017 . New accounting pronouncements not yet adopted Revenue recognition and presentation – In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) , which generally requires an entity to identify performance obligations in its contracts, estimate the amount of consideration to be received in the transaction price, allocate the transaction price to each separate performance obligation, and recognize revenue as obligations are satisfied. Additionally, the standard requires expanded disclosures related to revenue recognition. Subsequent to the issuance of ASU 2014-09, the FASB issued various clarifications and interpretive guidance to assist entities with implementation efforts, including guidance pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis. Under this guidance, an entity generally shall record revenue on a gross basis if it controls a promised good or service before transferring it to a customer, whereas an entity shall record revenue on a net basis if its role is to arrange for another entity to provide the goods or services to a customer. Significant judgment may be required in some circumstances to determine whether gross or net presentation is appropriate. ASU 2014-09 and related interpretive guidance will be effective for interim and annual periods beginning after December 15, 2017 and allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. The Company plans to adopt the standard on January 1, 2018 using the modified retrospective approach. The Company continues to evaluate the impact of the new standard on its financial statements, accounting policies and internal controls. Based on assessments performed to date, the standard is not expected to have a material effect on the timing of the Company's revenue recognition or its financial position, results of operations, net income, or cash flows, but is expected to have an impact on the Company's revenue-related disclosures. Additionally, the standard is expected to impact the presentation of future revenues and expenses under the gross-versus-net presentation guidance. Historically, the Company has generally presented its revenues net of transportation costs. The new guidance is expected to result in future revenues and associated transportation expenses for certain of the Company's operated properties being reported on a gross basis. The Company expects changes from net to gross presentation will result in an increase in revenues and a corresponding increase in separately reported transportation expenses, with no net effect on the Company's results of operations, net income, or cash flows. For the three and six months ended June 30, 2017 , the Company estimates it had approximately $50 million and $100 million , respectively, of transportation-related charges on operated properties included in "Crude oil and natural gas sales" on the unaudited condensed consolidated statements of comprehensive loss. The Company is not currently able to estimate the impact on the presentation of its future revenues and expenses under the new guidance due to uncertainties with respect to future sales volumes, service costs, locations of producing properties, sales destinations, transportation methods utilized, and changes in the nature, timing, and extent of its arrangements from period to period. Leases – In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) , which requires companies to recognize a right of use asset and related liability on the balance sheet for the rights and obligations arising from leases with durations greater than 12 months. The standard is effective for interim and annual reporting periods beginning after December 15, 2018 and requires adoption by application of a modified retrospective transition approach. The Company continues to evaluate the impact of ASU 2016-02 and is in the process of developing systems and processes to identify, classify, and account for leases within the scope of the new guidance and to comply with the related disclosure requirements. Based on an initial review of the new guidance and the Company’s current commitments, the Company anticipates it may be required to recognize lease assets and liabilities related to drilling rig commitments, certain equipment rentals and leases, certain surface use agreements, and potentially certain firm transportation agreements, as well as other arrangements, the effect of which cannot be estimated at this time. Credit losses – In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments . This standard changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. The standard is effective for interim and annual periods beginning after December 15, 2019 and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. The Company continues to evaluate the new standard and is unable to estimate its financial statement impact at this time.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	6 Months Ended
	Jun. 30, 2017
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. Six months ended June 30, In thousands 2017 2016 Supplemental cash flow information: Cash paid for interest $ 138,346 $ 156,358 Cash paid for income taxes 2 — Cash received for income tax refunds 148 20 Non-cash investing activities: Asset retirement obligation additions and revisions, net 3,771 1,042 As of June 30, 2017 and December 31, 2016 , the Company had $331.7 million and $223.6 million , respectively, of accrued capital expenditures included in "Net property and equipment" and "Accounts payable trade" in the condensed consolidated balance sheets.

Derivative Instruments

Derivative Instruments	6 Months Ended
	Jun. 30, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	Derivative Instruments Crude oil and natural gas derivatives The Company may utilize crude oil and natural gas swap and collar derivative contracts to economically hedge against the variability in cash flows associated with future sales of crude oil and natural gas production. While the use of these derivative instruments limits the downside risk of adverse price movements, their use also limits future revenues from upward price movements. The Company recognizes all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The Company has not designated its crude oil and natural gas derivative instruments as hedges for accounting purposes and, as a result, marks such derivative instruments to fair value and recognizes the changes in fair value in the unaudited condensed consolidated statements of comprehensive loss under the caption “ Gain (loss) on crude oil and natural gas derivatives, net ”. The estimated fair value of derivative contracts is based upon various factors, including commodity exchange prices, over-the-counter quotations, and, in the case of collars and written call options, volatility, the risk-free interest rate, and the time to expiration. The calculation of the fair value of collars and written call options requires the use of an option-pricing model. See Note 5. Fair Value Measurements . With respect to a crude oil or natural gas fixed price swap contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the swap price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. For a crude oil or natural gas collar contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price. Neither party is required to make a payment to the other party if the settlement price for any settlement period is between the floor price and the ceiling price. At June 30, 2017 , the Company had outstanding natural gas derivative contracts as set forth in the table below. The volumes reflected below represent an aggregation of multiple derivative contracts having similar remaining durations that are expected to be realized ratably over the respective 2017 and 2018 periods. At June 30, 2017 the Company had no outstanding crude oil derivative contracts. 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 July 2017 - December 2017 Swaps - Henry Hub 66,240,000 $ 3.39 Collars - Henry Hub 33,120,000 $2.40 - $3.00 $ 2.47 $2.92 - $3.88 $ 3.08 January 2018 - March 2018 Swaps - Henry Hub 6,300,000 $ 3.28 Crude oil and natural gas derivative gains and losses Cash receipts and payments in the following table reflect the gain or loss on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price of matured contracts. Non-cash gains and losses below represent the change in fair value of derivative instruments which continue to be held at period end and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period. Three months ended June 30, Six months ended June 30, In thousands 2017 2016 2017 2016 Cash received (paid) on derivatives: Natural gas fixed price swaps $ 6,709 $ 38,778 $ 12,187 $ 77,967 Natural gas collars (3,050 ) — (9,456 ) — Cash received on derivatives, net 3,659 38,778 2,731 77,967 Non-cash gain (loss) on derivatives: Crude oil written call options — 6 — 38 Natural gas fixed price swaps 12,520 (101,308 ) 35,416 (98,915 ) Natural gas collars 11,843 (19,733 ) 36,733 (19,235 ) Non-cash gain (loss) on derivatives, net 24,363 (121,035 ) 72,149 (118,112 ) Gain (loss) on crude oil and natural gas derivatives, net $ 28,022 $ (82,257 ) $ 74,880 $ (40,145 ) Diesel fuel derivatives The Company has entered into diesel fuel swap derivative contracts to economically hedge against the variability in cash flows associated with future purchases of diesel fuel for use in drilling activities. The Company has hedged approximately six million gallons of diesel fuel over the period from July 2017 to December 2017 at a weighted average price of $1.45 per gallon. With respect to these diesel fuel swap contracts, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is greater than the swap price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is less than the swap price. The diesel fuel swap contracts are settled based upon reported NYMEX settlement prices for New York Harbor ultra-low sulfur diesel fuel. The Company recognizes its diesel fuel derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The estimated fair value is based upon various factors, including commodity exchange prices, over-the-counter quotations, the risk-free interest rate, and time to expiration. The Company has not designated its diesel fuel derivative instruments as hedges for accounting purposes and, as a result, marks the derivative instruments to fair value and recognizes the changes in fair value in the unaudited condensed consolidated statements of comprehensive loss under the caption “Operating costs and expenses — Net (gain) loss on sale of assets and other.” Cash receipts in the following table reflect gains on diesel fuel derivatives which matured during the period, calculated as the difference between the contract price and the market settlement price of matured contracts. Non-cash gains and losses below represent the change in fair value of diesel fuel derivatives 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 June 30, Six months ended June 30, In thousands 2017 2016 2017 2016 Cash received on diesel fuel derivatives $ 185 $ — $ 919 $ — Non-cash gain (loss) on diesel fuel derivatives (1,098 ) 4,200 (3,729 ) 3,140 Gain (loss) on diesel fuel derivatives, net $ (913 ) $ 4,200 $ (2,810 ) $ 3,140 Balance sheet offsetting of derivative assets and liabilities 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”, as applicable. Derivative assets and liabilities with the same counterparty that are subject to contractual terms which provide for net settlement are reported on a net basis in the condensed consolidated balance sheets. The following table presents the gross amounts of recognized crude oil, natural gas, and diesel fuel derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the condensed consolidated balance sheets for the periods presented, all at fair value. In thousands June 30, 2017 December 31, 2016 Commodity derivative assets: Gross amounts of recognized assets $ 19,746 $ 4,061 Gross amounts offset on balance sheet (1,937 ) — Net amounts of assets on balance sheet 17,809 4,061 Commodity derivative liabilities: Gross amounts of recognized liabilities (6,754 ) (59,489 ) Gross amounts offset on balance sheet 1,937 — Net amounts of liabilities on balance sheet $ (4,817 ) $ (59,489 ) The following table reconciles the net amounts disclosed above to the individual financial statement line items in the condensed consolidated balance sheets. In thousands June 30, 2017 December 31, 2016 Derivative assets $ 17,809 $ 4,061 Noncurrent derivative assets — — Net amounts of assets on balance sheet 17,809 4,061 Derivative liabilities (4,817 ) (59,489 ) Noncurrent derivative liabilities — — Net amounts of liabilities on balance sheet (4,817 ) (59,489 ) Total derivative assets (liabilities), net $ 12,992 $ (55,428 )

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements The Company follows a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows: • Level 1: Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. • Level 2: Observable market-based inputs or unobservable inputs 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 swap contracts, a discounted cash flow method is used due to the unavailability of relevant comparable market data for the Company’s exact contracts. The discounted cash flow method estimates future cash flows based on quoted market prices for forward commodity prices and a risk-adjusted discount rate. The fair values of swap contracts are calculated mainly using significant observable inputs (Level 2). Calculation of the fair values of collars requires the use of an industry-standard option pricing model that considers various inputs including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. These assumptions are observable in the marketplace or can be corroborated by active markets or broker quotes and are therefore designated as Level 2 within the valuation hierarchy. The Company’s calculation of fair value for each of its derivative positions is compared to the counterparty valuation for reasonableness. The following tables summarize the valuation of financial instruments by pricing levels that were accounted for at fair value on a recurring basis as of June 30, 2017 and December 31, 2016 . Fair value measurements at June 30, 2017 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets (liabilities): Swaps $ — $ 19,390 $ — $ 19,390 Collars — (6,398 ) — (6,398 ) Total $ — $ 12,992 $ — $ 12,992 Fair value measurements at December 31, 2016 using: In thousands Level 1 Level 2 Level 3 Total Derivative liabilities: Swaps $ — $ (12,297 ) $ — $ (12,297 ) Collars — (43,131 ) — (43,131 ) Total $ — $ (55,428 ) $ — $ (55,428 ) Assets Measured at Fair Value on a Nonrecurring Basis Certain assets are reported at fair value on a nonrecurring basis in the 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 adjusted for differentials, operating costs, and a risk-adjusted discount rate. The fair value of proved crude oil and natural gas properties is calculated using significant unobservable inputs (Level 3). The following table sets forth quantitative information about the significant unobservable inputs used by the Company to calculate the fair value of proved crude oil and natural gas properties using a discounted cash flow method. Unobservable Input Assumption Future production Future production estimates for each property Forward commodity prices Forward NYMEX strip prices through 2021 (adjusted for differentials), escalating 3% per year thereafter Operating costs Estimated costs for the current year, escalating 3% per year thereafter Productive life of field Ranging from 0 to 39 years Discount rate 10% Unobservable inputs to the fair value assessment are reviewed quarterly and are revised as warranted based on a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Fair value measurements of proved properties are reviewed and approved by certain members of the Company’s management. For the three and six months ended June 30, 2017 the Company determined the carrying amounts of certain proved properties were not recoverable from future cash flows, and therefore, were impaired. Impairments of proved properties amounted to $81.5 million and $82.3 million for the three and six months ended June 30, 2017 , respectively. The 2017 year to date impairments reflect fair value adjustments primarily concentrated in the Arkoma Woodford field ( $81.2 million , all in the second quarter) and various non-core areas in the North and South regions ( $1.1 million , including $0.3 million in the second quarter). The impaired properties were written down to their estimated fair value at the time of impairment of approximately $72 million . For the three and six months ended June 30, 2016 , estimated future net cash flows were determined to be in excess of cost basis, therefore no impairment was recorded for the Company’s proved crude oil and natural gas properties for those periods. Certain unproved crude oil and natural gas properties were impaired during the three and six months ended June 30, 2017 and 2016 , 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 loss. Three months ended June 30, Six months ended June 30, In thousands 2017 2016 2017 2016 Proved property impairments $ 81,469 $ — $ 82,340 $ — Unproved property impairments 41,847 66,112 92,349 145,039 Total $ 123,316 $ 66,112 $ 174,689 $ 145,039 Financial Instruments Not Recorded at Fair Value The following table sets forth the estimated fair values of financial instruments that are not recorded at fair value in the condensed consolidated financial statements. June 30, 2017 December 31, 2016 In thousands Carrying Estimated Fair Value Carrying Estimated Fair Value Debt: Revolving credit facility $ 880,000 $ 880,000 $ 905,000 $ 905,000 Term loan 499,175 500,000 498,865 500,000 Note payable 11,083 11,100 12,176 10,200 5% Senior Notes due 2022 1,997,376 1,962,300 1,997,188 2,020,400 4.5% Senior Notes due 2023 1,485,585 1,434,800 1,484,524 1,474,800 3.8% Senior Notes due 2024 991,495 917,200 990,964 929,400 4.9% Senior Notes due 2044 691,276 587,700 691,199 607,600 Total debt $ 6,555,990 $ 6,293,100 $ 6,579,916 $ 6,447,400 The fair values of revolving credit facility borrowings and the term loan approximate carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and are classified as Level 2 in the fair value hierarchy. The fair value of the note payable is determined using a discounted cash flow approach based on the interest rate and payment terms of the note payable and an assumed discount rate. The fair value of the note payable is significantly influenced by the discount rate assumption, which is derived by the Company and is unobservable. Accordingly, the fair value of the note payable is classified as Level 3 in the fair value hierarchy. The fair values of the 5% Senior Notes due 2022 (“2022 Notes”), the 4.5% Senior Notes due 2023 (“2023 Notes”), the 3.8% Senior Notes due 2024 (“2024 Notes”), 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	6 Months Ended
	Jun. 30, 2017
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $35.1 million and $37.3 million at June 30, 2017 and December 31, 2016 , respectively, consists of the following. In thousands June 30, 2017 December 31, 2016 Revolving credit facility $ 880,000 $ 905,000 Term loan 499,175 498,865 Note payable 11,083 12,176 5% Senior Notes due 2022 1,997,376 1,997,188 4.5% Senior Notes due 2023 1,485,585 1,484,524 3.8% Senior Notes due 2024 991,495 990,964 4.9% Senior Notes due 2044 691,276 691,199 Total debt $ 6,555,990 $ 6,579,916 Less: Current portion of long-term debt 2,250 2,219 Long-term debt, net of current portion $ 6,553,740 $ 6,577,697 Revolving Credit Facility The Company has an unsecured revolving credit facility, maturing on May 16, 2019 , with aggregate commitments totaling $2.75 billion at June 30, 2017 , which may be increased up to a total of $4.0 billion upon agreement between the Company and participating lenders. Credit facility borrowings bear interest at market-based interest rates plus a margin based on the terms of the borrowing and the credit ratings assigned to the Company's senior, unsecured, long-term indebtedness. The weighted-average interest rate on outstanding credit facility borrowings at June 30, 2017 was 2.85% . The Company had approximately $1.87 billion of borrowing availability on its revolving credit facility at June 30, 2017 and incurs commitment fees based on currently assigned credit ratings of 0.30% per annum on the daily average amount of unused borrowing availability under its revolving credit facility. The revolving credit facility contains certain restrictive covenants including a requirement that the Company maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. This ratio represents the ratio of net debt (calculated as total face value of debt plus outstanding letters of credit less cash and cash equivalents) divided by the sum of net debt plus total shareholders' equity plus, to the extent resulting in a reduction of total shareholders’ equity, the amount of any non-cash impairment charges incurred, net of any tax effect, after June 30, 2014. The Company was in compliance with the revolving credit facility covenants at June 30, 2017 . 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 June 30, 2017 . 2022 Notes (1) 2023 Notes 2024 Notes 2044 Notes Face value (in thousands) $2,000,000 $1,500,000 $1,000,000 $700,000 Maturity date Sep 15, 2022 April 15, 2023 June 1, 2024 June 1, 2044 Interest payment dates March 15, Sep 15 April 15, Oct 15 June 1, Dec 1 June 1, Dec 1 Make-whole redemption period (2) — Jan 15, 2023 Mar 1, 2024 Dec 1, 2043 (1) The Company has the option to redeem all or a portion of its 2022 Notes at the decreasing redemption prices specified in the indenture related to the 2022 Notes plus any accrued and unpaid interest to the date of redemption. (2) At any time prior to these dates, the Company has the option to redeem all or a portion of its senior notes of the applicable series at the “make-whole” redemption prices or amounts specified in the respective senior note indentures plus any accrued and unpaid interest to the date of redemption. On or after these dates, the Company may redeem all or a portion of its senior notes at a redemption price equal to 100% of the principal amount of the senior notes being redeemed plus any accrued and unpaid interest to the date of redemption. The Company’s senior notes are not subject to any mandatory redemption or sinking fund requirements. The indentures governing the Company's senior notes contain covenants that, among other things, limit the Company's ability to create liens securing certain indebtedness, enter into certain sale-leaseback transactions, and consolidate, merge or transfer certain assets. The senior note covenants are subject to a number of important exceptions and qualifications. The Company was in compliance with these covenants at June 30, 2017 . Three of the Company’s subsidiaries, Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC, and The Mineral Resources Company, which have no material assets or operations, fully and unconditionally guarantee the senior notes on a joint and several basis. The Company’s other subsidiaries, the value of whose assets and operations are minor, do not guarantee the senior notes. Term Loan In November 2015, the Company borrowed $500 million under a three-year term loan agreement, the proceeds of which were used to repay a portion of the borrowings then outstanding on the Company's revolving credit facility. The term loan matures in full on November 4, 2018 and bears interest at a variable market-based interest rate plus a margin based on the terms of the borrowing and the credit ratings assigned to the Company's senior, unsecured, long-term indebtedness. The interest rate on the term loan at June 30, 2017 was 2.64% . The term loan contains certain restrictive covenants including a requirement that the Company maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00, consistent with the covenant requirement in the Company's revolving credit facility. The Company was in compliance with the term loan covenants at June 30, 2017 . Note Payable In February 2012, 20 Broadway Associates LLC, a 100% owned subsidiary of the Company, borrowed $22 million under a 10 -year amortizing term loan secured by the Company’s corporate office building in Oklahoma City, Oklahoma. The loan bears interest at a fixed rate of 3.14% per annum. Principal and interest are payable monthly through the loan’s maturity date of February 26, 2022 . Accordingly, approximately $2.3 million is reflected as a current liability under the caption “Current portion of long-term debt” in the condensed consolidated balance sheets as of June 30, 2017 .

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Included below is a discussion of various future commitments of the Company as of June 30, 2017 . The commitments under these arrangements are not recorded in the accompanying condensed consolidated balance sheets. Drilling commitments – As of June 30, 2017 , the Company has drilling rig contracts with various terms extending to February 2020 to ensure rig availability in its key operating areas. Future commitments as of June 30, 2017 total approximately $144 million , of which $55 million is expected to be incurred in the remainder of 2017 , $59 million in 2018 , $29 million in 2019 , and $1 million in 2020 . Transportation and processing commitments – The Company has entered into transportation and processing commitments to guarantee capacity on crude oil and natural gas pipelines and natural gas processing facilities. The commitments, which have varying terms extending as far as 2028, require the Company to pay per-unit transportation or processing charges regardless of the amount of capacity used. Future commitments remaining as of June 30, 2017 under the arrangements amount to approximately $1.2 billion , of which $115 million is expected to be incurred in the remainder of 2017 , $245 million in 2018 , $233 million in 2019 , $101 million in 2020 , $89 million in 2021, and $424 million thereafter. The Company is not committed under the above contracts to deliver fixed and determinable quantities of crude oil or natural gas in the future. Litigation – In November 2010, a putative class action was filed in the District Court of Blaine county, Oklahoma by Billy J. Strack and Daniela A. Renner as trustees of certain named trusts and on behalf of other similarly situated parties against the Company. The Petition alleged the Company improperly deducted post-production costs from royalties paid to plaintiffs and other royalty interest owners from crude oil and natural gas wells located in Oklahoma. The plaintiffs alleged a number of claims, including breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the proposed class. On November 3, 2014, plaintiffs filed an Amended Petition that did not add any substantive claims, but sought a “hybrid class action” in which they sought certification of certain claims for injunctive relief, reserving the right to seek a further class certification on money damages in the future. Plaintiffs filed an Amended Motion for Class Certification on January 9, 2015, that modified the proposed class to royalty owners in Oklahoma production from July 1, 1993, to the present (instead of 1980 to the present) and sought certification of over 45 separate “issues” for injunctive or declaratory relief, again, reserving the right to seek a further class certification of money damages in the future. The Company responded to the petition, its amendment, and the motions for class certification denying the allegations and raising a number of affirmative defenses and legal arguments to each of the claims and filings. Certain discovery was undertaken and the “hybrid” motion was briefed by plaintiffs and the Company. A hearing on the “hybrid” class certification was held on June 1 and 2, 2015. On June 11, 2015, the trial court certified a “hybrid” class as requested by plaintiffs. The Company appealed the trial court’s class certification order. On February 8, 2017, the Oklahoma Court of Civil Appeals reversed the trial court’s ruling on certification and remanded the case for further proceedings. The plaintiffs filed a Petition for Rehearing which is pending before the Oklahoma Court of Civil Appeals. The Company is not currently able to estimate a reasonably possible loss or range of loss or what impact, if any, the ultimate resolution of the action will have on its financial condition, results of operations or cash flows due to the preliminary status of the matter, the complexity and number of legal and factual issues presented by the matter and uncertainties with respect to, among other things, the nature of the claims and defenses, the existence and the potential size of the class, the scope and types of the properties and agreements involved, the production years involved, and the ultimate potential outcome of the matter. It is reasonably possible one or more events may occur in the near term that could impact the Company’s ability to estimate the potential effect this matter could have, if any, on its financial condition, results of operations or cash flows. Plaintiffs have alleged underpayments in excess of $200 million that they may claim as damages, which may increase with the passage of time, a majority of which would be comprised of interest. The Company disputes plaintiffs’ claims, disputes the case meets the requirements for a class action and continues to vigorously defend the case. An unsuccessful mediation was conducted on December 7, 2015. The parties continue to negotiate a possible resolution to the case. However, it is unclear and unforeseeable whether the parties' efforts will result in settlement and the Company will continue to defend the case on all merits and certification issues and, absent settlement, intends to defend the case to a final judgment. The Company is involved in various other legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, disputes with tax authorities and other matters. While the outcome of 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 both June 30, 2017 and December 31, 2016 , the Company had recorded a liability in the condensed consolidated balance sheets under the caption “Other noncurrent liabilities” of $6.5 million 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	6 Months Ended
	Jun. 30, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-Based Compensation	Stock-Based Compensation On January 1, 2017, the Company adopted ASU 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting . See Note 2. Basis of Presentation and Significant Accounting Policies—Adoption of new accounting pronouncements for a discussion of the impact of adoption. The Company has granted restricted stock to employees and directors pursuant to the Continental Resources, Inc. 2013 Long-Term Incentive Plan ("2013 Plan") as discussed below. The Company’s associated compensation expense, which is included in the caption “General and administrative expenses” in the unaudited condensed consolidated statements of comprehensive loss, was $9.1 million and $11.8 million for the three months ended June 30, 2017 and 2016 , respectively, and $20.6 million and $21.0 million for the six months ended June 30, 2017 and 2016 , respectively. In May 2013, the Company adopted the 2013 Plan and reserved 19,680,072 shares of common stock that may be issued pursuant to the plan. As of June 30, 2017 , the Company had 14,551,387 shares of common stock available for long-term incentive awards to employees and directors under the 2013 Plan. Restricted stock is awarded in the name of the recipient and constitutes issued and outstanding shares of the Company’s common stock for all corporate purposes during the period of restriction and, except as otherwise provided under the 2013 Plan or agreement relevant to a given award, includes the right to vote the restricted stock or to receive dividends, subject to forfeiture. Restricted stock grants generally vest over periods ranging from one to three years. A summary of changes in non-vested restricted shares outstanding for the six months ended June 30, 2017 is presented below. Number of Weighted average Non-vested restricted shares outstanding at December 31, 2016 3,913,634 $ 37.12 Granted 1,464,944 45.06 Vested (785,487 ) 58.66 Forfeited (520,002 ) 37.47 Non-vested restricted shares outstanding at June 30, 2017 4,073,089 $ 35.78 The grant date fair value of restricted stock represents the closing market price of the Company’s common stock on the date of grant. Compensation expense for a restricted stock grant is determined at the grant date fair value and is recognized over the vesting period as services are rendered by employees and directors. The Company estimates the number of forfeitures expected to occur in determining the amount of stock-based compensation expense to recognize. There are no post-vesting restrictions related to the Company’s restricted stock. The fair value at the vesting date of restricted stock that vested during the six months ended June 30, 2017 was approximately $36.1 million . As of June 30, 2017 , there was approximately $81 million of unrecognized compensation expense related to non-vested restricted stock. This expense is expected to be recognized over a weighted average period of 1.6 years.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income (Notes)	6 Months Ended
	Jun. 30, 2017
Accumulated Other Comprehensive Income [Abstract]
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	Accumulated Other Comprehensive Income (Loss) Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in "Accumulated other comprehensive income (loss)" within shareholders’ equity in the condensed consolidated balance sheets and "Other comprehensive income, net of tax" in the unaudited condensed consolidated statements of comprehensive loss. The following table summarizes the change in accumulated other comprehensive income (loss) for the three and six months ended June 30, 2017 and 2016 : Three months ended June 30, Six months ended June 30, In thousands 2017 2016 2017 2016 Beginning accumulated other comprehensive loss, net of tax $ (122 ) $ (2,928 ) $ (260 ) $ (3,354 ) Foreign currency translation adjustments 189 25 327 451 Income taxes (1) — — — — Other comprehensive income, net of tax 189 25 327 451 Ending accumulated other comprehensive income (loss), net of tax $ 67 $ (2,903 ) $ 67 $ (2,903 ) (1) A valuation allowance has been recognized against all deferred tax assets associated with losses generated by the Company's Canadian operations, thereby resulting in no income taxes on other comprehensive income.

Income Taxes (Notes)

Income Taxes (Notes)	6 Months Ended
	Jun. 30, 2017
Income Taxes [Abstract]
Income Tax Disclosure [Text Block]	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. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. The Company’s policy is to recognize penalties and interest related to unrecognized tax benefits, if any, in income tax expense. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized. The Company's benefit for income taxes totaled $37.9 million and $31.8 million for the three and six months ended June 30, 2017 , respectively. The Company's benefit for income taxes totaled $72.6 million and $194.0 million for the three and six months ended June 30, 2016, respectively. These amounts differ from the amounts computed by applying the United States statutory federal income tax rate to net loss before income taxes. The sources and tax effects of the differences are reflected in the table below: Three months ended June 30, Six months ended June 30, $ in thousands 2017 Tax rate % 2016 Tax rate % 2017 Tax rate % 2016 Tax rate % Expected income tax benefit based on US statutory tax rate of 35% $ 35,494 35 % $ 67,212 35 % $ 33,222 35 % $ 179,097 35 % State income taxes, net of federal benefit 3,043 3 % 5,761 3 % 2,848 3 % 15,351 3 % Tax deficiency from stock-based compensation (1) (473 ) (1 %) — — % (3,773 ) (4 %) — — % Canadian valuation allowance (2) (112 ) — % (217 ) — % (257 ) — % (294 ) — % Effect of differing statutory tax rate in Canada (55 ) — % (90 ) — % (122 ) — % (124 ) — % Other, net (42 ) — % (34 ) — % (85 ) — % (52 ) — % Benefit for income taxes $ 37,855 37 % $ 72,632 38 % $ 31,833 34 % $ 193,978 38 % (1) The Company recognized $0.5 million and $3.8 million of tax deficiencies from stock-based compensation as income tax expense for the three and six months ended June 30, 2017 , respectively, in accordance with ASU 2016-09 as discussed in Note 2. Basis of Presentation and Significant Accounting Policies–Adoption of new accounting pronouncements . (2) Represents valuation allowances recognized against all deferred tax assets associated with operating loss carryforwards generated by the Company's Canadian operations during the respective periods for which the Company does not expect to realize a benefit.

Property Dispositions (Notes)

Property Dispositions (Notes)	6 Months Ended
	Jun. 30, 2017
Property Dispositions [Abstract]
Mergers, Acquisitions and Dispositions Disclosures [Text Block]	Property Disposition In April 2016, the Company sold approximately 132,000 net acres of undeveloped leasehold acreage located in Wyoming to a third party for cash proceeds of $110.0 million . In connection with the transaction, the Company recognized a pre-tax gain of $96.9 million . The disposed properties represented an immaterial portion of the Company’s total acreage and included no production or proved reserves.

Subsequent Events (Notes)

Subsequent Events (Notes)	6 Months Ended
	Jun. 30, 2017
Subsequent Events [Abstract]
Subsequent Events [Text Block]	Subsequent Events Subsequent to June 30, 2017, the Company reached agreements to sell certain non-core properties and facilities in Oklahoma for aggregate proceeds totaling approximately $147.5 million . The sold properties include, in the aggregate, approximately 32,600 net acres of leasehold and producing properties with production totaling approximately 1,800 barrels of oil equivalent per day. The disposed properties represented an immaterial portion of the Company’s proved reserves. In connection with the transactions, the Company expects to recognize pre-tax gains totaling approximately $65 million , which will be reflected in third quarter 2017 results. The Company intends to use the proceeds from the sales to reduce outstanding debt.

Basis of Presentation and Sig19

Basis of Presentation and Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2017
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 all properties south of Nebraska and west of the Mississippi River including various plays in the SCOOP (South Central Oklahoma Oil Province), STACK (Sooner Trend Anadarko Canadian Kingfisher), and Arkoma Woodford areas of Oklahoma. The East region is primarily comprised of undeveloped leasehold acreage east of the Mississippi River with no significant drilling or production operations. A substantial portion of the Company’s operations are located in the North region, with that region comprising approximately 57% of the Company’s crude oil and natural gas production and approximately 66% of its crude oil and natural gas revenues for the six months ended June 30, 2017 . 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 operations in the South region with its increased activity in the SCOOP and STACK plays. The South region comprised approximately 43% of the Company's crude oil and natural gas production and approximately 34% of its crude oil and natural gas revenues for the six months ended June 30, 2017 . For the six months ended June 30, 2017 , crude oil accounted for approximately 56% of the Company’s total production and approximately 76% 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, after 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, 2016 (“ 2016 Form 10-K”), which includes a summary of the Company’s significant accounting policies and other disclosures. The condensed consolidated financial statements as of June 30, 2017 and for the three and six month periods ended June 30, 2017 and 2016 are unaudited. The condensed consolidated balance sheet as of December 31, 2016 was derived from the audited balance sheet included in the 2016 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 and diluted net loss per share is computed by dividing net loss by the weighted-average number of shares outstanding for the period. In periods where the Company has net income, diluted earnings per share reflects the potential dilution of non-vested restricted stock awards, which are calculated using the treasury stock method.
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	Adoption of new accounting pronouncements Stock-based compensation – In March 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting , which changes how companies account for certain aspects of share-based payment awards, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. The Company adopted the new standard on January 1, 2017 as required. The impact of adoption is described below. ASU 2016-09 removes the requirement to delay recognition of an excess tax benefit until it reduces current taxes payable. An excess tax benefit (tax deficiency) arises when stock-based compensation expense recognized in an entity’s tax return exceeds (is less than) the expense recognized in an entity’s financial statements. Under the new standard, effective January 1, 2017 excess tax benefits are recorded when they arise. This change was required to be applied on a modified retrospective basis by recording a cumulative effect adjustment to opening retained earnings upon adoption to account for previously unrecognized excess tax benefits. The Company's cumulative effect adjustment recorded under the new standard resulted in a $5.2 million increase in retained earnings and corresponding decrease in deferred income tax liabilities at January 1, 2017. Additionally, under ASU 2016-09 companies no longer record excess tax benefits and deficiencies in additional paid-in capital. Instead, excess tax benefits and deficiencies are recognized as income tax benefit or expense in the income statement, effective January 1, 2017 on a prospective basis. This is expected to result in increased volatility in income tax expense/benefit and corresponding variations in the relationship between income tax expense/benefit and pre-tax income/loss from period to period. The Company recognized $0.5 million ( $0.00 per share) and $3.8 million ( $0.01 per share) of tax deficiencies from stock-based compensation as income tax expense for the three and six months ended June 30, 2017 , respectively, under the new standard, which are reflected in "Benefit for income taxes" in the unaudited condensed consolidated statements of comprehensive loss. ASU 2016-09 also removed the requirement that entities present excess tax benefits and deficiencies as offsetting cash flows from financing and operating activities in the statement of cash flows. Instead, ASU 2016-09 requires cash flows related to excess tax benefits and deficiencies be classified as operating activities in the same manner as other cash flows related to income taxes. The Company has elected to apply this guidance on a prospective basis. Accordingly, the cash flow presentation of excess tax benefits and deficiencies in periods prior to January 1, 2017, if applicable, will not be adjusted to conform to current period presentation. The Company has elected to continue its historical accounting practice of estimating forfeitures in determining the amount of stock-based compensation expense to recognize. Therefore, the adoption of ASU 2016-09 does not have an impact on the amount of stock-based compensation expense to be recognized by the Company on non-vested restricted stock awards. Business combinations – In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business , which changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities is deemed to be a business. Determining whether a transferred set constitutes a business is important because the accounting for a business combination differs from that of an asset acquisition. The definition of a business also affects the accounting for dispositions. Under the new standard, when substantially all of the fair value of assets acquired is concentrated in a single asset, or a group of similar assets, the assets acquired would not represent a business and business combination accounting would not be required. The new standard may result in more transactions being accounted for as asset acquisitions rather than business combinations. The standard is effective for interim and annual periods beginning after December 15, 2017 and shall be applied prospectively. The Company early adopted ASU 2017-01 as of January 1, 2017, which had no significant impact on the Company's financial statements as of and for the three and six months ended June 30, 2017 . New accounting pronouncements not yet adopted Revenue recognition and presentation – In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) , which generally requires an entity to identify performance obligations in its contracts, estimate the amount of consideration to be received in the transaction price, allocate the transaction price to each separate performance obligation, and recognize revenue as obligations are satisfied. Additionally, the standard requires expanded disclosures related to revenue recognition. Subsequent to the issuance of ASU 2014-09, the FASB issued various clarifications and interpretive guidance to assist entities with implementation efforts, including guidance pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis. Under this guidance, an entity generally shall record revenue on a gross basis if it controls a promised good or service before transferring it to a customer, whereas an entity shall record revenue on a net basis if its role is to arrange for another entity to provide the goods or services to a customer. Significant judgment may be required in some circumstances to determine whether gross or net presentation is appropriate. ASU 2014-09 and related interpretive guidance will be effective for interim and annual periods beginning after December 15, 2017 and allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. The Company plans to adopt the standard on January 1, 2018 using the modified retrospective approach. The Company continues to evaluate the impact of the new standard on its financial statements, accounting policies and internal controls. Based on assessments performed to date, the standard is not expected to have a material effect on the timing of the Company's revenue recognition or its financial position, results of operations, net income, or cash flows, but is expected to have an impact on the Company's revenue-related disclosures. Additionally, the standard is expected to impact the presentation of future revenues and expenses under the gross-versus-net presentation guidance. Historically, the Company has generally presented its revenues net of transportation costs. The new guidance is expected to result in future revenues and associated transportation expenses for certain of the Company's operated properties being reported on a gross basis. The Company expects changes from net to gross presentation will result in an increase in revenues and a corresponding increase in separately reported transportation expenses, with no net effect on the Company's results of operations, net income, or cash flows. For the three and six months ended June 30, 2017 , the Company estimates it had approximately $50 million and $100 million , respectively, of transportation-related charges on operated properties included in "Crude oil and natural gas sales" on the unaudited condensed consolidated statements of comprehensive loss. The Company is not currently able to estimate the impact on the presentation of its future revenues and expenses under the new guidance due to uncertainties with respect to future sales volumes, service costs, locations of producing properties, sales destinations, transportation methods utilized, and changes in the nature, timing, and extent of its arrangements from period to period. Leases – In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) , which requires companies to recognize a right of use asset and related liability on the balance sheet for the rights and obligations arising from leases with durations greater than 12 months. The standard is effective for interim and annual reporting periods beginning after December 15, 2018 and requires adoption by application of a modified retrospective transition approach. The Company continues to evaluate the impact of ASU 2016-02 and is in the process of developing systems and processes to identify, classify, and account for leases within the scope of the new guidance and to comply with the related disclosure requirements. Based on an initial review of the new guidance and the Company’s current commitments, the Company anticipates it may be required to recognize lease assets and liabilities related to drilling rig commitments, certain equipment rentals and leases, certain surface use agreements, and potentially certain firm transportation agreements, as well as other arrangements, the effect of which cannot be estimated at this time. Credit losses – In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments . This standard changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. The standard is effective for interim and annual periods beginning after December 15, 2019 and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. The Company continues to evaluate the new standard and is unable to estimate its financial statement impact at this time.

Basis of Presentation and Sig20

Basis of Presentation and Significant Accounting Policies (Tables)	6 Months Ended
	Jun. 30, 2017
Accounting Policies [Abstract]
Components of Inventories	The components of inventory as of June 30, 2017 and December 31, 2016 consisted of the following: In thousands June 30, 2017 December 31, 2016 Tubular goods and equipment $ 15,723 $ 15,243 Crude oil 81,280 96,744 Total $ 97,003 $ 111,987
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 loss per share for the three and six months ended June 30, 2017 and 2016 . Three months ended June 30, Six months ended June 30, In thousands, except per share data 2017 2016 2017 2016 Net loss (numerator) $ (63,557 ) $ (119,402 ) $ (63,088 ) $ (317,727 ) Weighted average shares (denominator): Weighted average shares - basic 371,111 370,435 370,972 370,248 Non-vested restricted stock (1) — — — — Weighted average shares - diluted 371,111 370,435 370,972 370,248 Net loss per share: Basic $ (0.17 ) $ (0.32 ) $ (0.17 ) $ (0.86 ) Diluted $ (0.17 ) $ (0.32 ) $ (0.17 ) $ (0.86 ) (1) For the three and six months ended June 30, 2017, the Company had a net loss and therefore the potential dilutive effect of approximately 1,933,200 and 2,546,200 weighted average non-vested restricted shares, respectively, were not included in the calculation of diluted net loss per share because to do so would have been anti-dilutive to the computations. The Company also had net losses for the three and six months ended June 30, 2016, and therefore approximately 1,940,700 and 1,486,200 weighted average non-vested restricted shares, respectively, were not included in the calculation of diluted net loss per share for those periods.

Supplemental Cash Flow Inform21

Supplemental Cash Flow Information (Tables)	6 Months Ended
	Jun. 30, 2017
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. Six months ended June 30, In thousands 2017 2016 Supplemental cash flow information: Cash paid for interest $ 138,346 $ 156,358 Cash paid for income taxes 2 — Cash received for income tax refunds 148 20 Non-cash investing activities: Asset retirement obligation additions and revisions, net 3,771 1,042 As of June 30, 2017 and December 31, 2016 , the Company had $331.7 million and $223.6 million , respectively, of accrued capital expenditures included in "Net property and equipment" and "Accounts payable trade" in the condensed consolidated balance sheets.

Derivative Instruments (Tables)

Derivative Instruments (Tables)	6 Months Ended
	Jun. 30, 2017
Summary of Outstanding Contracts with Respect to Natural Gas	At June 30, 2017 , the Company had outstanding natural gas derivative contracts as set forth in the table below. The volumes reflected below represent an aggregation of multiple derivative contracts having similar remaining durations that are expected to be realized ratably over the respective 2017 and 2018 periods. At June 30, 2017 the Company had no outstanding crude oil derivative contracts. 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 July 2017 - December 2017 Swaps - Henry Hub 66,240,000 $ 3.39 Collars - Henry Hub 33,120,000 $2.40 - $3.00 $ 2.47 $2.92 - $3.88 $ 3.08 January 2018 - March 2018 Swaps - Henry Hub 6,300,000 $ 3.28
Realized and Unrealized Gains and Losses on Derivative Instruments	Cash receipts and payments in the following table reflect the gain or loss on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price of matured contracts. Non-cash gains and losses below represent the change in fair value of derivative instruments which continue to be held at period end and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period. Three months ended June 30, Six months ended June 30, In thousands 2017 2016 2017 2016 Cash received (paid) on derivatives: Natural gas fixed price swaps $ 6,709 $ 38,778 $ 12,187 $ 77,967 Natural gas collars (3,050 ) — (9,456 ) — Cash received on derivatives, net 3,659 38,778 2,731 77,967 Non-cash gain (loss) on derivatives: Crude oil written call options — 6 — 38 Natural gas fixed price swaps 12,520 (101,308 ) 35,416 (98,915 ) Natural gas collars 11,843 (19,733 ) 36,733 (19,235 ) Non-cash gain (loss) on derivatives, net 24,363 (121,035 ) 72,149 (118,112 ) Gain (loss) on crude oil and natural gas derivatives, net $ 28,022 $ (82,257 ) $ 74,880 $ (40,145 )
Gross Amounts of Recognized Derivative Assets and Liabilities	The following table presents the gross amounts of recognized crude oil, natural gas, and diesel fuel derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the condensed consolidated balance sheets for the periods presented, all at fair value. In thousands June 30, 2017 December 31, 2016 Commodity derivative assets: Gross amounts of recognized assets $ 19,746 $ 4,061 Gross amounts offset on balance sheet (1,937 ) — Net amounts of assets on balance sheet 17,809 4,061 Commodity derivative liabilities: Gross amounts of recognized liabilities (6,754 ) (59,489 ) Gross amounts offset on balance sheet 1,937 — Net amounts of liabilities on balance sheet $ (4,817 ) $ (59,489 )
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 June 30, 2017 December 31, 2016 Derivative assets $ 17,809 $ 4,061 Noncurrent derivative assets — — Net amounts of assets on balance sheet 17,809 4,061 Derivative liabilities (4,817 ) (59,489 ) Noncurrent derivative liabilities — — Net amounts of liabilities on balance sheet (4,817 ) (59,489 ) Total derivative assets (liabilities), net $ 12,992 $ (55,428 )
Diesel Fuel [Member]
Realized and Unrealized Gains and Losses on Derivative Instruments	Cash receipts in the following table reflect gains on diesel fuel derivatives which matured during the period, calculated as the difference between the contract price and the market settlement price of matured contracts. Non-cash gains and losses below represent the change in fair value of diesel fuel derivatives 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 June 30, Six months ended June 30, In thousands 2017 2016 2017 2016 Cash received on diesel fuel derivatives $ 185 $ — $ 919 $ — Non-cash gain (loss) on diesel fuel derivatives (1,098 ) 4,200 (3,729 ) 3,140 Gain (loss) on diesel fuel derivatives, net $ (913 ) $ 4,200 $ (2,810 ) $ 3,140

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2017
Fair Value Disclosures [Abstract]
Valuation of Financial Instruments by Pricing Levels	The following tables summarize the valuation of financial instruments by pricing levels that were accounted for at fair value on a recurring basis as of June 30, 2017 and December 31, 2016 . Fair value measurements at June 30, 2017 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets (liabilities): Swaps $ — $ 19,390 $ — $ 19,390 Collars — (6,398 ) — (6,398 ) Total $ — $ 12,992 $ — $ 12,992 Fair value measurements at December 31, 2016 using: In thousands Level 1 Level 2 Level 3 Total Derivative liabilities: Swaps $ — $ (12,297 ) $ — $ (12,297 ) Collars — (43,131 ) — (43,131 ) Total $ — $ (55,428 ) $ — $ (55,428 )
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 2021 (adjusted for differentials), escalating 3% per year thereafter Operating costs Estimated costs for the current year, escalating 3% per year thereafter Productive life of field Ranging from 0 to 39 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 loss. Three months ended June 30, Six months ended June 30, In thousands 2017 2016 2017 2016 Proved property impairments $ 81,469 $ — $ 82,340 $ — Unproved property impairments 41,847 66,112 92,349 145,039 Total $ 123,316 $ 66,112 $ 174,689 $ 145,039
Fair Values of Financial Instruments not Recorded at Fair Value	The following table sets forth the estimated fair values of financial instruments that are not recorded at fair value in the condensed consolidated financial statements. June 30, 2017 December 31, 2016 In thousands Carrying Estimated Fair Value Carrying Estimated Fair Value Debt: Revolving credit facility $ 880,000 $ 880,000 $ 905,000 $ 905,000 Term loan 499,175 500,000 498,865 500,000 Note payable 11,083 11,100 12,176 10,200 5% Senior Notes due 2022 1,997,376 1,962,300 1,997,188 2,020,400 4.5% Senior Notes due 2023 1,485,585 1,434,800 1,484,524 1,474,800 3.8% Senior Notes due 2024 991,495 917,200 990,964 929,400 4.9% Senior Notes due 2044 691,276 587,700 691,199 607,600 Total debt $ 6,555,990 $ 6,293,100 $ 6,579,916 $ 6,447,400

Long-Term Debt (Tables)

Long-Term Debt (Tables)	6 Months Ended
	Jun. 30, 2017
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 June 30, 2017 . 2022 Notes (1) 2023 Notes 2024 Notes 2044 Notes Face value (in thousands) $2,000,000 $1,500,000 $1,000,000 $700,000 Maturity date Sep 15, 2022 April 15, 2023 June 1, 2024 June 1, 2044 Interest payment dates March 15, Sep 15 April 15, Oct 15 June 1, Dec 1 June 1, Dec 1 Make-whole redemption period (2) — Jan 15, 2023 Mar 1, 2024 Dec 1, 2043 (1) The Company has the option to redeem all or a portion of its 2022 Notes at the decreasing redemption prices specified in the indenture related to the 2022 Notes plus any accrued and unpaid interest to the date of redemption. (2) At any time prior to these dates, the Company has the option to redeem all or a portion of its senior notes of the applicable series at the “make-whole” redemption prices or amounts specified in the respective senior note indentures plus any accrued and unpaid interest to the date of redemption. On or after these dates, the Company may redeem all or a portion of its senior notes at a redemption price equal to 100% of the principal amount of the senior notes being redeemed plus any accrued and unpaid interest to the date of redemption.
Schedule of Long-term Debt Instruments [Table Text Block]	Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $35.1 million and $37.3 million at June 30, 2017 and December 31, 2016 , respectively, consists of the following. In thousands June 30, 2017 December 31, 2016 Revolving credit facility $ 880,000 $ 905,000 Term loan 499,175 498,865 Note payable 11,083 12,176 5% Senior Notes due 2022 1,997,376 1,997,188 4.5% Senior Notes due 2023 1,485,585 1,484,524 3.8% Senior Notes due 2024 991,495 990,964 4.9% Senior Notes due 2044 691,276 691,199 Total debt $ 6,555,990 $ 6,579,916 Less: Current portion of long-term debt 2,250 2,219 Long-term debt, net of current portion $ 6,553,740 $ 6,577,697

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	6 Months Ended
	Jun. 30, 2017
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 six months ended June 30, 2017 is presented below. Number of Weighted average Non-vested restricted shares outstanding at December 31, 2016 3,913,634 $ 37.12 Granted 1,464,944 45.06 Vested (785,487 ) 58.66 Forfeited (520,002 ) 37.47 Non-vested restricted shares outstanding at June 30, 2017 4,073,089 $ 35.78

Accumulated Other Comprehensi26

Accumulated Other Comprehensive Income (Tables)	6 Months Ended
	Jun. 30, 2017
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 income (loss) for the three and six months ended June 30, 2017 and 2016 : Three months ended June 30, Six months ended June 30, In thousands 2017 2016 2017 2016 Beginning accumulated other comprehensive loss, net of tax $ (122 ) $ (2,928 ) $ (260 ) $ (3,354 ) Foreign currency translation adjustments 189 25 327 451 Income taxes (1) — — — — Other comprehensive income, net of tax 189 25 327 451 Ending accumulated other comprehensive income (loss), net of tax $ 67 $ (2,903 ) $ 67 $ (2,903 ) (1) A valuation allowance has been recognized against all deferred tax assets associated with losses generated by the Company's Canadian operations, thereby resulting in no income taxes on other comprehensive income.

Income Taxes (Tables)

Income Taxes (Tables)	6 Months Ended
	Jun. 30, 2017
Effective Tax Rate Reconciliation Table [Abstract]
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	he sources and tax effects of the differences are reflected in the table below: Three months ended June 30, Six months ended June 30, $ in thousands 2017 Tax rate % 2016 Tax rate % 2017 Tax rate % 2016 Tax rate % Expected income tax benefit based on US statutory tax rate of 35% $ 35,494 35 % $ 67,212 35 % $ 33,222 35 % $ 179,097 35 % State income taxes, net of federal benefit 3,043 3 % 5,761 3 % 2,848 3 % 15,351 3 % Tax deficiency from stock-based compensation (1) (473 ) (1 %) — — % (3,773 ) (4 %) — — % Canadian valuation allowance (2) (112 ) — % (217 ) — % (257 ) — % (294 ) — % Effect of differing statutory tax rate in Canada (55 ) — % (90 ) — % (122 ) — % (124 ) — % Other, net (42 ) — % (34 ) — % (85 ) — % (52 ) — % Benefit for income taxes $ 37,855 37 % $ 72,632 38 % $ 31,833 34 % $ 193,978 38 % (1) The Company recognized $0.5 million and $3.8 million of tax deficiencies from stock-based compensation as income tax expense for the three and six months ended June 30, 2017 , respectively, in accordance with ASU 2016-09 as discussed in Note 2. Basis of Presentation and Significant Accounting Policies–Adoption of new accounting pronouncements . (2) Represents valuation allowances recognized against all deferred tax assets associated with operating loss carryforwards generated by the Company's Canadian operations during the respective periods for which the Company does not expect to realize a benefit.

Organization and Nature of Bu28

Organization and Nature of Business - Additional Information (Detail)	6 Months Ended
	Jun. 30, 2017
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	56.00%
Percentage of crude oil and natural gas revenue concentrated in crude oil	76.00%
North Region [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Percentage of operations concentrated in geographic areas	57.00%
Percentage of revenues concentrated in geographic areas	66.00%
South Region [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Percentage of operations concentrated in geographic areas	43.00%
Percentage of revenues concentrated in geographic areas	34.00%

Basis of Presentation and Sig29

Basis of Presentation and Significant Accounting Policies - Components of Inventories (Detail) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Tubular goods and equipment	$ 15,723	$ 15,243
Crude oil	81,280	96,744
Total	$ 97,003	$ 111,987

Basis of Presentation and Sig30

Basis of Presentation and Significant Accounting Policies - Earnings Per Share (Detail) - USD ($) $ / shares in Units, $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Accounting Policies [Abstract]
Weighted Average Number Diluted Shares Outstanding Adjustment		1,933,200	1,940,700	2,546,200	1,486,200
Net loss (numerator)
Net loss (numerator)		$ (63,557)	$ (119,402)	$ (63,088)	$ (317,727)
Weighted average shares - basic		371,111,000	370,435,000	370,972,000	370,248,000
Non-vested restricted stock (1)	[1]	0	0	0	0
Weighted average shares - diluted		371,111,000	370,435,000	370,972,000	370,248,000
Net loss per share:
Basic (in dollars per share)		$ (0.17)	$ (0.32)	$ (0.17)	$ (0.86)
Diluted (in dollars per share)		$ (0.17)	$ (0.32)	$ (0.17)	$ (0.86)
[1]	For the three and six months ended June 30, 2017, the Company had a net loss and therefore the potential dilutive effect of approximately 1,933,200 and 2,546,200 weighted average non-vested restricted shares, respectively, were not included in the calculation of diluted net loss per share because to do so would have been anti-dilutive to the computations. The Company also had net losses for the three and six months ended June 30, 2016, and therefore approximately 1,940,700 and 1,486,200 weighted average non-vested restricted shares, respectively, were not included in the calculation of diluted net loss per share for those periods.

Basis of Presentation and Sig31

Basis of Presentation and Significant Accounting Policies Basis of Presentation and Significant Accounting Policies - New Accounting Pronouncements (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2017
Accounting Policies [Abstract]
Adoption of ASU 2016-09 cumulative effect on retained earnings		$ 5,150
Share-based Compensation, Tax Deficiency from Compensation Expense	$ 500	$ 3,800
Tax Deficiency from Compensation Expense, Per Share	$ 0	$ 0.01
Results of Operations, Transportation Costs	$ 50,000	$ 100,000

Supplemental Cash Flow Inform32

Supplemental Cash Flow Information - Summary of Supplemental Cash Flow Information (Detail) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Supplemental Cash Flow Elements [Abstract]
Cash paid for interest	$ 138,346	$ 156,358
Cash paid for income taxes	2	0
Cash received for income tax refunds	148	20
Noncash Investing and Financing Items [Abstract]
Accrued capital expenditures	331,700		$ 223,600
Increase (Decrease) in Asset Retirement Obligations	$ 3,771	$ 1,042

Derivative Instruments - Summar

Derivative Instruments - Summary of Outstanding Contracts with Respect to Natural Gas (Detail) - Natural Gas [Member]	6 Months Ended
	Jun. 30, 2017MMBTU$ / MMBTU
July 2017 to December 2017 Swaps
Derivative [Line Items]
Natural Gas Production Derivative Volume, MMBtus | MMBTU	66,240,000
Swaps Weighted Average Price	3.39
July 2017 to December 2017 Collars
Derivative [Line Items]
Natural Gas Production Derivative Volume, MMBtus | MMBTU	33,120,000
Floors, Weighted Average Price	2.47
Ceilings, Weighted Average Price	3.08
January 2018 to March 2018 Swaps
Derivative [Line Items]
Natural Gas Production Derivative Volume, MMBtus | MMBTU	6,300,000
Swaps Weighted Average Price	3.28
Minimum [Member] | July 2017 to December 2017 Collars
Derivative [Line Items]
Derivative, Floor Price	2.40
Derivative, Cap Price	2.92
Maximum [Member] | July 2017 to December 2017 Collars
Derivative [Line Items]
Derivative, Floor Price	3
Derivative, Cap Price	3.88

Derivative Instruments - Realiz

Derivative Instruments - Realized and Unrealized Gains and Losses on Derivative Instruments (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net			$ 68,420	$ (114,972)
Gain (loss) on crude oil and natural gas derivatives, net	$ 28,022	$ (82,257)	74,880	(40,145)
Diesel Fuel [Member]
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net	185	0	919	0
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net	(1,098)	4,200	(3,729)	3,140
Gain (loss) on crude oil and natural gas derivatives, net	(913)	4,200	(2,810)	3,140
Swap [Member] | Natural Gas [Member]
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net	6,709	38,778	12,187	77,967
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net	12,520	(101,308)	35,416	(98,915)
Collars | Natural Gas [Member]
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net	(3,050)	0	(9,456)	0
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net	11,843	(19,733)	36,733	(19,235)
Call Option [Member] | Crude Oil [Member]
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net	0	6	0	38
Crude Oil and Natural Gas [Member]
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net	3,659	38,778	2,731	77,967
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net	24,363	(121,035)	72,149	(118,112)
Gain (loss) on crude oil and natural gas derivatives, net	$ 28,022	$ (82,257)	$ 74,880	$ (40,145)

Derivative Instruments - Gross

Derivative Instruments - Gross Amounts of Recognized Derivative Assets and Liabilities (Detail) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Gross amounts of recognized assets	$ 19,746	$ 4,061
Gross amounts offset on balance sheet	(1,937)	0
Net amounts of assets on balance sheet	17,809	4,061
Gross amounts of recognized liabilities	(6,754)	(59,489)
Gross amounts offset on balance sheet	1,937	0
Net amounts of liabilities on balance sheet	$ (4,817)	$ (59,489)

Derivative Instruments - Reconc

Derivative Instruments - Reconciles Net Amounts Derivative Assets and Liabilities (Detail) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative assets	$ 17,809	$ 4,061
Noncurrent derivative assets	0	0
Net amounts of assets on balance sheet	17,809	4,061
Derivative liabilities	(4,817)	(59,489)
Noncurrent derivative liabilities	0	0
Net amounts of liabilities on balance sheet	(4,817)	(59,489)
Total derivative assets, net	$ 12,992	$ (55,428)

Derivative Instruments Summary

Derivative Instruments Summary of Outstanding Contracts with Respect to Diesel Fuel (Details) $ in Thousands, gal in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017USD ($)$ / gal	Jun. 30, 2016USD ($)	Jun. 30, 2017USD ($)$ / galgal	Jun. 30, 2016USD ($)
Derivative [Line Items]
Non-cash gain (loss) on derivatives, net			$ 68,420	$ (114,972)
Gain (loss) on derivatives, net	$ 28,022	$ (82,257)	74,880	(40,145)
Diesel Fuel [Member]
Derivative [Line Items]
Cash received (paid) on derivatives, net	185	0	919	0
Non-cash gain (loss) on derivatives, net	(1,098)	4,200	(3,729)	3,140
Gain (loss) on derivatives, net	$ (913)	$ 4,200	$ (2,810)	$ 3,140
Diesel Fuel [Member] | July 2017 to December 2017 Swaps [Member]
Derivative [Line Items]
Diesel Fuel Derivative Volume, gallons | gal			6
Swaps Weighted Average Price | $ / gal	1.45		1.45

Fair Value Measurements - Valua

Fair Value Measurements - Valuation of Financial Instruments by Pricing Levels (Detail) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Derivative assets (liabilities):
Derivative assets (liabilities)	$ 12,992	$ (55,428)
Swap [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	19,390	(12,297)
Collars
Derivative assets (liabilities):
Derivative assets (liabilities)	(6,398)	(43,131)
Fair Value, Inputs, Level 1 [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0	0
Fair Value, Inputs, Level 1 [Member] | Swap [Member]
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 2 [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	12,992	(55,428)
Fair Value, Inputs, Level 2 [Member] | Swap [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	19,390	(12,297)
Fair Value, Inputs, Level 2 [Member] | Collars
Derivative assets (liabilities):
Derivative assets (liabilities)	(6,398)	(43,131)
Fair Value, Inputs, Level 3 [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0	0
Fair Value, Inputs, Level 3 [Member] | Swap [Member]
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 Measurements - Addit

Fair Value Measurements - Additional Information (Detail)	6 Months Ended
	Jun. 30, 2017
Fair Value Measurements [Line Items]
Operating cost escalation assumption used in impairment assessment	3.00%
Discount factor utilized as standardized measure for future net cash flows	10.00%
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)	39 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		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved property impairments	$ 81,469	$ 0	$ 82,340	$ 0
Unproved property impairments	41,847	66,112	92,349	145,039
Oil and gas property fair value after impairment	72,000		72,000
Property impairments	123,316	$ 66,112	174,689	$ 145,039
Arkoma Woodford [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved property impairments	81,200		81,200
Non-core [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved property impairments	$ 300		$ 1,100

Fair Value Measurements - Fair

Fair Value Measurements - Fair Values of Financial Instruments not Recorded at Fair Value (Detail) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Fair Value Measurements [Line Items]
Loans Payable to Bank	$ 499,175	$ 498,865
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]
Revolving credit facility	$ 880,000	905,000
Loans Payable to Bank	499,175	498,865
Note payable	11,083	12,176
Total debt	6,555,990	6,579,916
Carrying Amount | 5% Senior Notes due 2022
Fair Value Measurements [Line Items]
Senior notes	1,997,376	1,997,188
Carrying Amount | 4 1/2% Senior Notes Due 2023
Fair Value Measurements [Line Items]
Senior notes	1,485,585	1,484,524
Carrying Amount | 3.8% Senior Notes due 2024
Fair Value Measurements [Line Items]
Senior notes	991,495	990,964
Carrying Amount | 4.9% Senior Notes due 2044
Fair Value Measurements [Line Items]
Senior notes	691,276	691,199
Estimated Fair Value
Fair Value Measurements [Line Items]
Revolving credit facility	880,000	905,000
Loans Payable to Bank	500,000	500,000
Note payable	11,100	10,200
Total debt	6,293,100	6,447,400
Estimated Fair Value | 5% Senior Notes due 2022
Fair Value Measurements [Line Items]
Senior notes	1,962,300	2,020,400
Estimated Fair Value | 4 1/2% Senior Notes Due 2023
Fair Value Measurements [Line Items]
Senior notes	1,434,800	1,474,800
Estimated Fair Value | 3.8% Senior Notes due 2024
Fair Value Measurements [Line Items]
Senior notes	917,200	929,400
Estimated Fair Value | 4.9% Senior Notes due 2044
Fair Value Measurements [Line Items]
Senior notes	$ 587,700	$ 607,600

Long-Term Debt - Long-Term Debt

Long-Term Debt - Long-Term Debt (Detail) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Loans Payable to Bank	$ 499,175	$ 498,865
Less: Current portion of long-term debt	(2,250)	(2,219)
Long-term debt, net of current portion	$ 6,553,740	6,577,697
5% Senior Notes due 2022
Debt Instrument [Line Items]
Debt Instrument, stated interest rate	5.00%
Note payable
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]
Revolving credit facility	$ 880,000	905,000
Loans Payable to Bank	499,175	498,865
Note payable	11,083	12,176
Total debt	6,555,990	6,579,916
Carrying Amount | 5% Senior Notes due 2022
Debt Instrument [Line Items]
Senior notes	1,997,376	1,997,188
Carrying Amount | 4 1/2% Senior Notes Due 2023
Debt Instrument [Line Items]
Senior notes	1,485,585	1,484,524
Carrying Amount | 3.8% Senior Notes due 2024
Debt Instrument [Line Items]
Senior notes	991,495	990,964
Carrying Amount | 4.9% Senior Notes due 2044
Debt Instrument [Line Items]
Senior notes	691,276	691,199
Estimated Fair Value
Debt Instrument [Line Items]
Revolving credit facility	880,000	905,000
Loans Payable to Bank	500,000	500,000
Note payable	11,100	10,200
Total debt	6,293,100	6,447,400
Estimated Fair Value | 5% Senior Notes due 2022
Debt Instrument [Line Items]
Senior notes	1,962,300	2,020,400
Estimated Fair Value | 4 1/2% Senior Notes Due 2023
Debt Instrument [Line Items]
Senior notes	1,434,800	1,474,800
Estimated Fair Value | 3.8% Senior Notes due 2024
Debt Instrument [Line Items]
Senior notes	917,200	929,400
Estimated Fair Value | 4.9% Senior Notes due 2044
Debt Instrument [Line Items]
Senior notes	$ 587,700	$ 607,600

Long-Term Debt - Additional Inf

Long-Term Debt - Additional Information (Detail) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Loans Payable to Bank	$ 499,175	$ 498,865
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net	$ 35,100	37,300
Line of credit facility, maturity date	May 16, 2019
Aggregate amount of lender commitments on credit facility	$ 2,750,000
Line of Credit Facility, Maximum Borrowing Capacity	$ 4,000,000
Line of credit facility, commitment fee percentage, per annum	0.30%
Current portion of long-term debt	$ 2,250	2,219
Line of Credit Facility, Covenant Terms	0.65
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	2.85%
Line of Credit Facility, Remaining Borrowing Capacity	$ 1,870,000
Loans Payable [Member]
Debt Instrument [Line Items]
Debt Instrument, stated interest rate	2.64%
4.5% Senior Notes due 2023
Debt Instrument [Line Items]
Debt Instrument, stated interest rate	4.50%
Debt Instrument, Maturity Date, Description	2,023
Note payable
Debt Instrument [Line Items]
Notes Payable	$ 22,000
Loan term	10 years
Debt Instrument, stated interest rate	3.14%
Debt Instrument, Maturity Date	Feb. 26, 2022
5% Senior Notes due 2022
Debt Instrument [Line Items]
Debt Instrument, stated interest rate	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%
Debt Instrument, Maturity Date, Description	2,024
4.9% Senior Notes due 2044
Debt Instrument [Line Items]
Debt Instrument, stated interest rate	4.90%
Debt Instrument, Maturity Date, Description	2,044
Estimated Fair Value
Debt Instrument [Line Items]
Loans Payable to Bank	$ 500,000	500,000
Credit facility	880,000	905,000
Notes Payable	11,100	10,200
Estimated Fair Value | 5% Senior Notes due 2022
Debt Instrument [Line Items]
Senior notes	1,962,300	2,020,400
Estimated Fair Value | 3.8% Senior Notes due 2024
Debt Instrument [Line Items]
Senior notes	917,200	929,400
Estimated Fair Value | 4.9% Senior Notes due 2044
Debt Instrument [Line Items]
Senior notes	587,700	607,600
Carrying Amount
Debt Instrument [Line Items]
Loans Payable to Bank	499,175	498,865
Credit facility	880,000	905,000
Notes Payable	11,083	12,176
Carrying Amount | 5% Senior Notes due 2022
Debt Instrument [Line Items]
Senior notes	1,997,376	1,997,188
Carrying Amount | 3.8% Senior Notes due 2024
Debt Instrument [Line Items]
Senior notes	991,495	990,964
Carrying Amount | 4.9% Senior Notes due 2044
Debt Instrument [Line Items]
Senior notes	$ 691,276	$ 691,199

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	6 Months Ended
	Jun. 30, 2017USD ($)
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
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
Debt Instrument, Redemption Period, Start Date	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
Debt Instrument, Redemption Period, Start Date	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
Debt Instrument, Redemption Period, Start Date	Dec. 1, 2043

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail) - USD ($) $ in Millions	1 Months Ended	6 Months Ended
	Nov. 30, 2010	Jun. 30, 2017	Dec. 31, 2016
Long-term Purchase Commitment [Line Items]
Total future drilling commitments at balance sheet date		$ 144
Drilling commitments due remainder of current year		55
Drilling commitments Year Two		59
Drilling Commitments Year Three		29
Drilling Commitments Year Four		$ 1
Pipeline commitments, end date		2,028
Future Drilling Commitments End Date		2020-02
Purchase Obligation, total		$ 1,200
Purchase Obligation, due in remainder of current year		115
Purchase Obligation, due second year		245
Purchase Obligation, due third year		233
Purchase Obligation, due fourth year		101
Purchase Obligation, due fifth year		89
Purchase Obligation, due after fifth year		424
Damages sought in litigation matter	$ 200
Legal proceedings recorded as a liability under other noncurrent liabilities		$ (6.5)	$ (6.5)

Stock Based Compensation - Stoc

Stock Based Compensation - Stock Based Compensation Expenses (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Non-cash equity compensation	$ 9.1	$ 11.8	$ 20.6	$ 21

Stock-Based Compensation - Addi

Stock-Based Compensation - Additional Information (Detail) $ in Millions	6 Months Ended
	Jun. 30, 2017USD ($)shares
Restricted stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock available to grant | shares	14,551,387
Fair value at vesting date | $	$ 36.1
Unrecognized compensation expense related to non-vested | $	$ 81
Unrecognized compensation expense related to non-vested, period for recognition, in years	1 year 7 months 17 days
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 | shares	19,680,072

Stock Based Compensation - Summ

Stock Based Compensation - Summary of Changes in Non Vested Shares of Restricted Stock Outstanding (Detail)	6 Months Ended
	Jun. 30, 2017$ / 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 | shares	3,913,634
Granted (unaudited), shares | shares	1,464,944
Vested shares | shares	(785,487)
Forfeited (unaudited), shares | shares	(520,002)
Non-vested shares, ending balance | shares	4,073,089
Non-vested, weighted average grant-date fair value, beginning of period | $ / shares	$ 37.12
Granted, weighted average grant-date fair value | $ / shares	45.06
Vested, weighted average grant-date fair value | $ / shares	58.66
Forfeited, weighted average grant-date fair value | $ / shares	37.47
Non-vested, weighted average grant-date fair value, end of period | $ / shares	$ 35.78

Accumulated Other Comprehensi49

Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2016	Dec. 31, 2015
Accumulated Other Comprehensive Income [Abstract]
Accumulated other comprehensive income (loss)	$ 67	$ (2,903)	$ 67	$ (2,903)	$ (122)	$ (260)	$ (2,928)	$ (3,354)
Foreign currency translation adjustments	189	25	327	451
Translation Adjustment Functional to Reporting Currency, Tax Benefit (Expense)	0	0	0	0
Total other comprehensive income, net of tax	$ 189	$ 25	$ 327	$ 451

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Income Taxes [Abstract]
Share-based Compensation, Tax Deficiency from Compensation Expense		$ 500		$ 3,800
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount		$ 35,494	$ 67,212	$ 33,222	$ 179,097
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		35.00%	35.00%	35.00%	35.00%
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount		$ 3,043	$ 5,761	$ 2,848	$ 15,351
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent		3.00%	3.00%	3.00%	3.00%
Effective Income Tax Rate Reconciliation, Tax Benefit (Deficiency), Amount	[1]	$ (473)	$ 0	$ (3,773)	$ 0
Effective Income Tax Rate Reconciliation, Tax Benefit (Deficiency), Percent		(1.00%)	0.00%	(4.00%)	0.00%
Effective Income Tax Rate Reconciliation, Valuation Allowance, Amount	[2]	$ (112)	$ (217)	$ (257)	$ (294)
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Percent		0.00%	0.00%	0.00%	0.00%
Effective Income Tax Rate Reconciliation, Tax Settlement, Foreign, Amount		$ (55)	$ (90)	$ (122)	$ (124)
Effective Income Tax Rate Reconciliation, Tax Settlement, Foreign, Percent		0.00%	0.00%	0.00%	0.00%
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount		$ (42)	$ (34)	$ (85)	$ (52)
Effective Income Tax Rate Reconciliation, Other Adjustments, Percent		0.00%	0.00%	0.00%	0.00%
Benefit for income taxes		$ 37,855	$ 72,632	$ 31,833	$ 193,978
Effective Income Tax Rate Reconciliation, Percent		37.00%	38.00%	34.00%	38.00%
[1]	The Company recognized $0.5 million and $3.8 million of tax deficiencies from stock-based compensation as income tax expense for the three and six months ended June 30, 2017, respectively, in accordance with ASU 2016-09 as discussed in Note 2. Basis of Presentation and Significant Accounting Policies–Adoption of new accounting pronouncements.
[2]	Represents valuation allowances recognized against all deferred tax assets associated with operating loss carryforwards generated by the Company's Canadian operations during the respective periods for which the Company does not expect to realize a benefit.

Property Dispositions (Details)

Property Dispositions (Details) $ in Millions	3 Months Ended
	Jun. 30, 2016USD ($)	Apr. 29, 2016a
Property Dispositions [Abstract]
Non-producing leasehold | a		132,000
Proceeds from Sale of Oil and Gas Property and Equipment	$ 110
Gain (Loss) on Disposition of Unproved Property	$ 96.9

Subsequent Events (Details)

Subsequent Events (Details) $ in Millions	3 Months Ended
	Sep. 30, 2017USD ($)aBoe	Jun. 30, 2016USD ($)	Apr. 29, 2016a
Subsequent Event [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment		$ 110
Leasehold | a			132,000
Subsequent Event [Member]
Subsequent Event [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	$ 147.5
Leasehold | a	32,600
Production, Barrels of Oil Equivalents | Boe	1,800
Gain (Loss) on Disposition of Assets	$ 65