Document and Entity Information
Document and Entity Information - shares | 3 Months Ended | |
Mar. 31, 2017 | Apr. 30, 2017 | |
Document Document And Entity Information [Abstract] | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Mar. 31, 2017 | |
Document Fiscal Year Focus | 2,017 | |
Document Fiscal Period Focus | Q1 | |
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 | 375,190,967 |
Condensed Consolidated Balance
Condensed Consolidated Balance Sheets - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 |
Current assets: | ||
Cash and cash equivalents | $ 17,188 | $ 16,643 |
Receivables: | ||
Crude oil and natural gas sales | 414,841 | 404,750 |
Affiliated parties | 52 | 99 |
Joint interest and other, net | 376,259 | 364,850 |
Derivative assets | 7,524 | 4,061 |
Inventories | 98,690 | 111,987 |
Prepaid expenses and other | 14,952 | 10,843 |
Total current assets | 929,506 | 913,233 |
Net property and equipment, based on successful efforts method of accounting | 12,880,357 | 12,881,227 |
Noncurrent derivative assets | 0 | 0 |
Other noncurrent assets | 16,197 | 17,316 |
Total assets | 13,826,060 | 13,811,776 |
Current liabilities: | ||
Accounts payable trade | 582,565 | 476,342 |
Revenues and royalties payable | 237,967 | 217,425 |
Payables to affiliated parties | 62 | 148 |
Accrued liabilities and other | 164,694 | 176,770 |
Derivative liabilities | 17,797 | 59,489 |
Current portion of long-term debt | 2,236 | 2,219 |
Total current liabilities | 1,005,321 | 932,393 |
Long-term debt, net of current portion | 6,508,209 | 6,577,697 |
Other noncurrent liabilities: | ||
Deferred income tax liabilities, net | 1,891,177 | 1,890,305 |
Asset retirement obligations, net of current portion | 97,151 | 94,436 |
Noncurrent derivative liabilities | 0 | 0 |
Other noncurrent liabilities | 14,848 | 14,949 |
Total other noncurrent liabilities | 2,003,176 | 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; 375,321,131 shares issued and outstanding at March 31, 2017; 374,492,357 shares issued and outstanding at December 31, 2016 | 3,753 | 3,745 |
Additional paid-in capital | 1,376,883 | 1,375,290 |
Accumulated other comprehensive loss, net of tax | (122) | (260) |
Retained earnings | 2,928,840 | 2,923,221 |
Total shareholders’ equity | 4,309,354 | 4,301,996 |
Total liabilities and shareholders’ equity | $ 13,826,060 | $ 13,811,776 |
Condensed Consolidated Balance3
Condensed Consolidated Balance Sheets (Parenthetical) - $ / shares | Mar. 31, 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 | 375,321,131 | 374,492,357 |
Common Stock, Shares, Outstanding | 375,321,131 | 374,492,357 |
Unaudited Condensed Consolidate
Unaudited Condensed Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Revenues: | ||
Crude oil and natural gas sales | $ 633,850 | $ 403,592 |
Gain on crude oil and natural gas derivatives, net | 46,858 | 42,112 |
Crude oil and natural gas service operations | 4,719 | 7,470 |
Total revenues | 685,427 | 453,174 |
Operating costs and expenses: | ||
Production expenses | 72,854 | 78,640 |
Production taxes | 41,234 | 30,493 |
Exploration expenses | 4,998 | 3,066 |
Crude oil and natural gas service operations | 2,837 | 3,043 |
Depreciation, depletion, amortization and accretion | 382,156 | 463,992 |
Property impairments | 51,372 | 78,927 |
General and administrative expenses | 47,220 | 32,407 |
Net loss on sale of assets and other | 5,535 | 1,709 |
Total operating costs and expenses | 608,206 | 692,277 |
Income (loss) from operations | 77,221 | (239,103) |
Other income (expense): | ||
Interest expense | (71,172) | (80,953) |
Other | 442 | 384 |
Total other income (expense) | (70,730) | (80,569) |
Income (loss) before income taxes | 6,491 | (319,672) |
(Provision) benefit for income taxes | (6,022) | 121,346 |
Net income (loss) | 469 | (198,326) |
Foreign currency translation adjustments | 138 | 426 |
Other Comprehensive Income (Loss), Net of Tax (unaudited) | 138 | 426 |
Comprehensive income (loss), net of tax | $ 607 | $ (197,900) |
Basic net income (loss) per share (in dollars per share) | $ 0 | $ (0.54) |
Diluted net income (loss) per share (in dollars per share) | $ 0 | $ (0.54) |
Condensed Consolidated Statemen
Condensed Consolidated Statements of Shareholders Equity - 3 months ended Mar. 31, 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) | 469 | 469 | |||
Other Comprehensive Income (Loss), Net of Tax (unaudited) | 138 | 138 | |||
Stock-based compensation (unaudited) | 11,428 | 11,428 | |||
Restricted stock: | |||||
Granted (unaudited) | $ 11 | $ 11 | |||
Granted (unaudited), shares | 1,151,041 | 1,151,041 | |||
Repurchased and canceled (unaudited) | $ (9,837) | $ (2) | (9,835) | ||
Repurchased and canceled (unaudited), shares | (212,280) | (212,280) | |||
Forfeited (unaudited), shares | (109,987) | (109,987) | |||
Forfeitures (unaudited) | $ (1) | $ (1) | |||
Balance at Mar. 31, 2017 | $ 4,309,354 | $ 3,753 | $ 1,376,883 | $ (122) | $ 2,928,840 |
Balance, shares at Mar. 31, 2017 | 375,321,131 | 375,321,131 |
Unaudited Condensed Consolidat6
Unaudited Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Cash flows from operating activities | ||
Net income (loss) | $ 469 | $ (198,326) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||
Depreciation, Depletion, Amortization and Accretion | 381,385 | 465,451 |
Property impairments | 51,372 | 78,927 |
Non-cash gain on derivatives, net | (45,155) | (1,863) |
Stock-based compensation | 11,438 | 9,206 |
Provision (benefit) for deferred income taxes | 6,021 | (121,352) |
Dry hole costs | 157 | 0 |
(Gain) loss on sale of assets, net | 3,638 | (109) |
Other, net | 3,099 | 2,514 |
Changes in assets and liabilities: | ||
Accounts receivable | (22,053) | 66,839 |
Inventories | 13,297 | 1,319 |
Other current assets | (3,111) | (2,082) |
Accounts payable trade | 61,745 | (31,531) |
Revenues and royalties payable | 20,543 | (17,380) |
Accrued liabilities and other | (12,338) | 29,806 |
Other noncurrent assets and liabilities | (306) | (2,517) |
Net cash provided by operating activities | 470,201 | 278,902 |
Cash flows from investing activities | ||
Exploration and development | (388,596) | (359,090) |
Purchase of producing crude oil and natural gas properties | (137) | 0 |
Purchase of other property and equipment | (6,336) | (1,927) |
Proceeds from sale of assets | 5,798 | 2,206 |
Net cash used in investing activities | (389,271) | (358,811) |
Cash flows from financing activities | ||
Credit facility borrowings | 256,000 | 288,000 |
Repayment of credit facility | (326,000) | (201,000) |
Repayment of other debt | (548) | (530) |
Debt issuance costs | 0 | (40) |
Repurchase of restricted stock for tax withholdings | (9,837) | (5,088) |
Net cash (used in) provided by financing activities | (80,385) | 81,342 |
Effect of Exchange Rate on Cash and Cash Equivalents | 0 | 31 |
Net change in cash and cash equivalents | 545 | 1,464 |
Cash and cash equivalents at beginning of period | 16,643 | 11,463 |
Cash and cash equivalents at end of period | $ 17,188 | $ 12,927 |
Organization and Nature of Busi
Organization and Nature of Business | 3 Months Ended |
Mar. 31, 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 56% of the Company’s crude oil and natural gas production and approximately 65% of its crude oil and natural gas revenues for the three months ended March 31, 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 44% of the Company's crude oil and natural gas production and approximately 35% of its crude oil and natural gas revenues for the three months ended March 31, 2017 . For the three months ended March 31, 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 | 3 Months Ended |
Mar. 31, 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 March 31, 2017 and for the three month periods ended March 31, 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 net income (loss) per share is computed by dividing net income (loss) by the weighted-average number of shares outstanding for the period. In periods where the Company has net income, diluted earnings per share reflects the potential dilution of non-vested restricted stock awards, which are calculated using the treasury stock method. The following table presents the calculation of basic and diluted weighted average shares outstanding and net income (loss) per share for the three months ended March 31, 2017 and 2016 . Three months ended March 31, In thousands, except per share data 2017 2016 Net income (loss) (numerator): Net income (loss) - basic and diluted $ 469 $ (198,326 ) Weighted average shares (denominator): Weighted average shares - basic 370,831 370,062 Non-vested restricted stock (1) 2,522 — Weighted average shares - diluted 373,353 370,062 Net income (loss) per share: Basic $ — $ (0.54 ) Diluted $ — $ (0.54 ) (1) For the three months ended March 31, 2016 the Company had a net loss and therefore the potential dilutive effect of approximately 42,000 weighted average non-vested restricted shares were not included in the calculation of diluted net loss per share because to do so would have been anti-dilutive to the computations. 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 March 31, 2017 and December 31, 2016 consisted of the following: In thousands March 31, 2017 December 31, 2016 Tubular goods and equipment $ 15,646 $ 15,243 Crude oil 83,044 96,744 Total $ 98,690 $ 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 $3.3 million ( $0.01 per share) of tax deficiencies from stock-based compensation as income tax expense in the first quarter of 2017 under the new standard, which is reflected in “(Provision) benefit for income taxes" in the unaudited condensed consolidated statements of comprehensive income (loss). ASU 2016-09 also removed the requirement that entities present excess tax benefits and deficiencies as offsetting cash flows from financing and operating activities in the statement of cash flows. Instead, ASU 2016-09 requires cash flows related to excess tax benefits and deficiencies be classified as operating activities in the same manner as other cash flows related to income taxes. The Company has elected to apply this guidance on a prospective basis. Accordingly, the cash flow presentation of excess tax benefits and deficiencies in periods prior to January 1, 2017, 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, rather than accounting for forfeitures as they occur. 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 months ended March 31, 2017 . New accounting pronouncements not yet adopted 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. 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. Revenue recognition and presentation – In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) , which generally requires an entity to identify performance obligations in its contracts, estimate the amount of consideration to be received in the transaction price, allocate the transaction price to each separate performance obligation, and recognize revenue as obligations are satisfied. Additionally, the standard requires expanded disclosures related to revenue recognition. Subsequent to the issuance of ASU 2014-09, the FASB has issued various clarifications and interpretive guidance to assist entities with implementation efforts, including guidance pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis. Under this guidance, an entity generally shall record revenue on a gross basis if it controls a promised good or service before transferring it to a customer, whereas an entity shall record revenue on a net basis if its role is to arrange for another entity to provide the goods or services to a customer. Significant judgment may be required in some circumstances to determine whether gross or net presentation is appropriate. ASU 2014-09 and related interpretive guidance will be effective for interim and annual periods beginning after December 15, 2017 and allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. The Company plans to adopt the standard on January 1, 2018 using a modified retrospective approach. The standard is not expected to have a material effect on the timing of the Company's revenue recognition or its financial position, results of operations, net income, or cash flows, but is expected to impact the presentation of future revenues and expenses under the gross-versus-net presentation guidance. Historically, the Company has generally presented its revenues net of transportation costs. The new guidance is expected to result in future revenues and associated transportation expenses for certain of the Company's 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 months ended March 31, 2017 , the Company estimates it had approximately $50 million of transportation-related charges on operated properties included in "Crude oil and natural gas sales" on the unaudited condensed consolidated statements of comprehensive income (loss). The Company is not currently able to estimate the impact on the presentation of its future revenues and expenses under the new guidance due to uncertainties with respect to future sales volumes, service costs, locations of producing properties, sales destinations, transportation methods utilized, and changes in the nature, timing, and extent of its arrangements from period to period. Credit losses – In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments . This standard changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. The standard is effective for interim and annual periods beginning after December 15, 2019 and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. The Company is currently evaluating the new standard and is unable to estimate its financial statement impact at this time. |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | 3 Months Ended |
Mar. 31, 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. Three months ended March 31, In thousands 2017 2016 Supplemental cash flow information: Cash paid for interest $ 57,952 $ 56,825 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 1,565 481 As of March 31, 2017 and December 31, 2016 , the Company had $268.0 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 | 3 Months Ended |
Mar. 31, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Instruments | Derivative Instruments Crude oil and natural gas derivatives The Company may utilize crude oil and natural gas swap and collar derivative contracts to economically hedge against the variability in cash flows associated with future sales of crude oil and natural gas production. While the use of these derivative instruments limits the downside risk of adverse price movements, their use also limits future revenues from upward price movements. The Company recognizes all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The Company has not designated its crude oil and natural gas derivative instruments as hedges for accounting purposes and, as a result, marks such derivative instruments to fair value and recognizes the changes in fair value in the unaudited condensed consolidated statements of comprehensive income (loss) under the caption “ Gain 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 March 31, 2017 , the Company had outstanding natural gas derivative contracts as set forth in the table below. The volumes reflected below represent an aggregation of multiple derivative contracts having similar remaining durations that are expected to be realized ratably over the respective 2017 and 2018 periods. At March 31, 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 April 2017 - December 2017 Swaps - Henry Hub 99,000,000 $ 3.39 Collars - Henry Hub 49,500,000 $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 March 31, In thousands 2017 2016 Cash received (paid) on derivatives: Natural gas fixed price swaps $ 5,478 $ 39,189 Natural gas collars (6,406 ) — Cash received (paid) on derivatives, net (928 ) 39,189 Non-cash gain on derivatives: Crude oil written call options — 32 Natural gas fixed price swaps 22,896 2,393 Natural gas collars 24,890 498 Non-cash gain on derivatives, net 47,786 2,923 Gain on crude oil and natural gas derivatives, net $ 46,858 $ 42,112 Diesel fuel derivatives In March 2016, the Company entered into diesel fuel swap derivative contracts to economically hedge against the variability in cash flows associated with future purchases of diesel fuel for use in drilling activities. The Company has hedged approximately nine million gallons of diesel fuel over the period from April 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 income (loss) under the caption “Operating costs and expenses — Net loss on sale of assets and other.” For the three months ended March 31, 2017 , the Company recognized cash gains of $0.7 million on its matured diesel fuel derivatives. For the three months ended March 31, 2017 and March 31, 2016 , the Company recognized non-cash losses of $2.6 million and $1.1 million , respectively, on diesel fuel derivatives that continued to be held at the end of those respective periods. 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 March 31, 2017 December 31, 2016 Commodity derivative assets: Gross amounts of recognized assets $ 10,060 $ 4,061 Gross amounts offset on balance sheet (2,536 ) — Net amounts of assets on balance sheet 7,524 4,061 Commodity derivative liabilities: Gross amounts of recognized liabilities (20,333 ) (59,489 ) Gross amounts offset on balance sheet 2,536 — Net amounts of liabilities on balance sheet $ (17,797 ) $ (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 March 31, 2017 December 31, 2016 Derivative assets $ 7,524 $ 4,061 Noncurrent derivative assets — — Net amounts of assets on balance sheet 7,524 4,061 Derivative liabilities (17,797 ) (59,489 ) Noncurrent derivative liabilities — — Net amounts of liabilities on balance sheet (17,797 ) (59,489 ) Total derivative liabilities, net $ (10,273 ) $ (55,428 ) |
Fair Value Measurements
Fair Value Measurements | 3 Months Ended |
Mar. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Fair Value Measurements The Company follows a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows: • Level 1: Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. • Level 2: Observable market-based inputs or unobservable inputs 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 March 31, 2017 and December 31, 2016 . Fair value measurements at March 31, 2017 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets (liabilities): Swaps $ — $ 7,968 $ — $ 7,968 Collars — (18,241 ) — (18,241 ) Total $ — $ (10,273 ) $ — $ (10,273 ) 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 months ended March 31, 2017 the Company determined the carrying amounts of certain proved properties were not recoverable from future cash flows, and therefore, were impaired. Impairments of proved properties amounted to $0.9 million for the period, primarily for properties in a non-core area of the North region. The impaired properties were written down to their estimated fair value of approximately $3.4 million as of March 31, 2017 . For the three months ended March 31, 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. Certain unproved crude oil and natural gas properties were impaired during the three months ended March 31, 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 income (loss). Three months ended March 31, In thousands 2017 2016 Proved property impairments $ 871 $ — Unproved property impairments 50,501 78,927 Total $ 51,372 $ 78,927 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. March 31, 2017 December 31, 2016 In thousands Carrying Estimated Fair Value Carrying Estimated Fair Value Debt: Revolving credit facility $ 835,000 $ 835,000 $ 905,000 $ 905,000 Term loan 499,020 500,000 498,865 500,000 Note payable 11,631 9,700 12,176 10,200 5% Senior Notes due 2022 1,997,280 2,019,500 1,997,188 2,020,400 4.5% Senior Notes due 2023 1,485,049 1,465,600 1,484,524 1,474,800 3.8% Senior Notes due 2024 991,228 930,900 990,964 929,400 4.9% Senior Notes due 2044 691,237 601,200 691,199 607,600 Total debt $ 6,510,445 $ 6,361,900 $ 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 | 3 Months Ended |
Mar. 31, 2017 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | Long-Term Debt Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $36.2 million and $37.3 million at March 31, 2017 and December 31, 2016 , respectively, consists of the following. In thousands March 31, 2017 December 31, 2016 Revolving credit facility $ 835,000 $ 905,000 Term loan 499,020 498,865 Note payable 11,631 12,176 5% Senior Notes due 2022 1,997,280 1,997,188 4.5% Senior Notes due 2023 1,485,049 1,484,524 3.8% Senior Notes due 2024 991,228 990,964 4.9% Senior Notes due 2044 691,237 691,199 Total debt $ 6,510,445 $ 6,579,916 Less: Current portion of long-term debt 2,236 2,219 Long-term debt, net of current portion $ 6,508,209 $ 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 March 31, 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 March 31, 2017 was 2.60% . The Company had approximately $1.91 billion of borrowing availability on its revolving credit facility at March 31, 2017 and incurs commitment fees based on currently assigned credit ratings of 0.30% per annum on the daily average amount of unused borrowing availability under its revolving credit facility. The revolving credit facility contains certain restrictive covenants including a requirement that the Company maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. This ratio represents the ratio of net debt (calculated as total face value of debt plus outstanding letters of credit less cash and cash equivalents) divided by the sum of net debt plus total shareholders' equity plus, to the extent resulting in a reduction of total shareholders’ equity, the amount of any non-cash impairment charges incurred, net of any tax effect, after June 30, 2014. The Company was in compliance with the revolving credit facility covenants at March 31, 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 March 31, 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 March 31, 2017 . Three of the Company’s subsidiaries, Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC, and The Mineral Resources Company, which have no material assets or operations, fully and unconditionally guarantee the senior notes on a joint and several basis. The Company’s other subsidiaries, the value of whose assets and operations are minor, do not guarantee the senior notes. 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 March 31, 2017 was 2.35% . The term loan contains certain restrictive covenants including a requirement that the Company maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.0, consistent with the covenant requirement in the Company's revolving credit facility. The Company was in compliance with the term loan covenants at March 31, 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 $2.2 million is reflected as a current liability under the caption “Current portion of long-term debt” in the condensed consolidated balance sheets as of March 31, 2017 . |
Commitments and Contingencies
Commitments and Contingencies | 3 Months Ended |
Mar. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Included below is a discussion of various future commitments of the Company as of March 31, 2017 . The commitments under these arrangements are not recorded in the accompanying condensed consolidated balance sheets. Drilling commitments – As of March 31, 2017 , the Company has drilling rig contracts with various terms extending to February 2020 to ensure rig availability in its key operating areas. Future commitments as of March 31, 2017 total approximately $183 million , of which $94 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 2027, require the Company to pay per-unit transportation or processing charges regardless of the amount of capacity used. Future commitments remaining as of March 31, 2017 under the arrangements amount to approximately $839 million , of which $169 million is expected to be incurred in the remainder of 2017 , $217 million in 2018 , $191 million in 2019 , $59 million in 2020 , $47 million in 2021, and $156 million thereafter. Additionally, in April 2017 the Company entered into a natural gas firm transportation agreement that commits the Company to pay transportation charges totaling approximately $380 million over a 10-year period anticipated to begin in April 2018 regardless of the transportation capacity used. 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 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 March 31, 2017 and December 31, 2016 , the Company had recorded a liability in the condensed consolidated balance sheets under the caption “Other noncurrent liabilities” of $6.7 million and $6.5 million , respectively, for various matters, none of which are believed to be individually significant. Environmental risk – Due to the nature of the crude oil and natural gas business, the Company is exposed to possible environmental risks. The Company is not aware of any material environmental issues or claims. |
Stock-Based Compensation
Stock-Based Compensation | 3 Months Ended |
Mar. 31, 2017 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Stock-Based Compensation | Stock-Based Compensation On January 1, 2017, the Company adopted ASU 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting . See Note 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 income (loss), was $11.4 million and $9.2 million for the three months ended March 31, 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 March 31, 2017 , the Company had 14,437,178 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 three months ended March 31, 2017 is presented below. Number of Weighted average Non-vested restricted shares outstanding at December 31, 2016 3,913,634 $ 37.12 Granted 1,151,041 46.21 Vested (715,222 ) 58.48 Forfeited (109,987 ) 33.71 Non-vested restricted shares outstanding at March 31, 2017 4,239,466 $ 36.08 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 three months ended March 31, 2017 was approximately $33.1 million . As of March 31, 2017 , there was approximately $93 million of unrecognized compensation expense related to non-vested restricted stock. This expense is expected to be recognized over a weighted average period of 1.8 years. |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Income (Notes) | 3 Months Ended |
Mar. 31, 2017 | |
Accumulated Other Comprehensive Income [Abstract] | |
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block] | Accumulated Other Comprehensive Loss Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in "Accumulated other comprehensive loss" within shareholders’ equity on the condensed consolidated balance sheets. The following table summarizes the change in accumulated other comprehensive loss for the three months ended March 31, 2017 and 2016 : Three months ended March 31, In thousands 2017 2016 Beginning accumulated other comprehensive loss, net of tax $ (260 ) $ (3,354 ) Foreign currency translation adjustments 138 426 Income taxes (1) — — Other comprehensive income, net of tax 138 426 Ending accumulated other comprehensive loss, net of tax $ (122 ) $ (2,928 ) (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) | 3 Months Ended |
Mar. 31, 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 (provision) benefit for income taxes totaled ($6.0) million and $121.3 million for the three months ended March 31, 2017 and 2016 , respectively. These amounts differ from the amounts computed by applying the United States statutory federal income tax rate to income (loss) before income taxes. The sources and tax effects of the differences are reflected in the table below: Three months ended March 31, $ in thousands 2017 Tax rate % 2016 Tax rate % Expected income tax (provision) benefit based on US statutory tax rate of 35% $ (2,272 ) 35 % $ 111,885 35 % State income taxes, net of federal benefit (195 ) 3 % 9,590 3 % Tax deficiency from stock-based compensation (1) (3,300 ) 51 % — — % Canadian valuation allowance (2) (145 ) 2 % (77 ) — % Effect of differing statutory tax rate in Canada (67 ) 1 % (34 ) — % Other, net (43 ) 1 % (18 ) — % (Provision) benefit for income taxes $ (6,022 ) 93 % $ 121,346 38 % (1) The Company recognized $3.3 million of tax deficiencies from stock-based compensation as income tax expense 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 |
Basis of Presentation and Sig17
Basis of Presentation and Significant Accounting Policies (Policies) | 3 Months Ended |
Mar. 31, 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 56% of the Company’s crude oil and natural gas production and approximately 65% of its crude oil and natural gas revenues for the three months ended March 31, 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 44% of the Company's crude oil and natural gas production and approximately 35% of its crude oil and natural gas revenues for the three months ended March 31, 2017 . For the three months ended March 31, 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 March 31, 2017 and for the three month periods ended March 31, 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 net income (loss) per share is computed by dividing net income (loss) by the weighted-average number of shares outstanding for the period. In periods where the Company has net income, diluted earnings per share reflects the potential dilution of non-vested restricted stock awards, which are calculated using the treasury stock method. |
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 $3.3 million ( $0.01 per share) of tax deficiencies from stock-based compensation as income tax expense in the first quarter of 2017 under the new standard, which is reflected in “(Provision) benefit for income taxes" in the unaudited condensed consolidated statements of comprehensive income (loss). ASU 2016-09 also removed the requirement that entities present excess tax benefits and deficiencies as offsetting cash flows from financing and operating activities in the statement of cash flows. Instead, ASU 2016-09 requires cash flows related to excess tax benefits and deficiencies be classified as operating activities in the same manner as other cash flows related to income taxes. The Company has elected to apply this guidance on a prospective basis. Accordingly, the cash flow presentation of excess tax benefits and deficiencies in periods prior to January 1, 2017, 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, rather than accounting for forfeitures as they occur. 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 months ended March 31, 2017 . New accounting pronouncements not yet adopted 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. 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. Revenue recognition and presentation – In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) , which generally requires an entity to identify performance obligations in its contracts, estimate the amount of consideration to be received in the transaction price, allocate the transaction price to each separate performance obligation, and recognize revenue as obligations are satisfied. Additionally, the standard requires expanded disclosures related to revenue recognition. Subsequent to the issuance of ASU 2014-09, the FASB has issued various clarifications and interpretive guidance to assist entities with implementation efforts, including guidance pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis. Under this guidance, an entity generally shall record revenue on a gross basis if it controls a promised good or service before transferring it to a customer, whereas an entity shall record revenue on a net basis if its role is to arrange for another entity to provide the goods or services to a customer. Significant judgment may be required in some circumstances to determine whether gross or net presentation is appropriate. ASU 2014-09 and related interpretive guidance will be effective for interim and annual periods beginning after December 15, 2017 and allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. The Company plans to adopt the standard on January 1, 2018 using a modified retrospective approach. The standard is not expected to have a material effect on the timing of the Company's revenue recognition or its financial position, results of operations, net income, or cash flows, but is expected to impact the presentation of future revenues and expenses under the gross-versus-net presentation guidance. Historically, the Company has generally presented its revenues net of transportation costs. The new guidance is expected to result in future revenues and associated transportation expenses for certain of the Company's 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 months ended March 31, 2017 , the Company estimates it had approximately $50 million of transportation-related charges on operated properties included in "Crude oil and natural gas sales" on the unaudited condensed consolidated statements of comprehensive income (loss). The Company is not currently able to estimate the impact on the presentation of its future revenues and expenses under the new guidance due to uncertainties with respect to future sales volumes, service costs, locations of producing properties, sales destinations, transportation methods utilized, and changes in the nature, timing, and extent of its arrangements from period to period. Credit losses – In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments . This standard changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. The standard is effective for interim and annual periods beginning after December 15, 2019 and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. The Company is currently evaluating the new standard and is unable to estimate its financial statement impact at this time. |
Basis of Presentation and Sig18
Basis of Presentation and Significant Accounting Policies (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Accounting Policies [Abstract] | |
Components of Inventories | The components of inventory as of March 31, 2017 and December 31, 2016 consisted of the following: In thousands March 31, 2017 December 31, 2016 Tubular goods and equipment $ 15,646 $ 15,243 Crude oil 83,044 96,744 Total $ 98,690 $ 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 income (loss) per share for the three months ended March 31, 2017 and 2016 . Three months ended March 31, In thousands, except per share data 2017 2016 Net income (loss) (numerator): Net income (loss) - basic and diluted $ 469 $ (198,326 ) Weighted average shares (denominator): Weighted average shares - basic 370,831 370,062 Non-vested restricted stock (1) 2,522 — Weighted average shares - diluted 373,353 370,062 Net income (loss) per share: Basic $ — $ (0.54 ) Diluted $ — $ (0.54 ) (1) For the three months ended March 31, 2016 the Company had a net loss and therefore the potential dilutive effect of approximately 42,000 weighted average non-vested restricted shares were not included in the calculation of diluted net loss per share because to do so would have been anti-dilutive to the computations. |
Supplemental Cash Flow Inform19
Supplemental Cash Flow Information (Tables) | 3 Months Ended |
Mar. 31, 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. Three months ended March 31, In thousands 2017 2016 Supplemental cash flow information: Cash paid for interest $ 57,952 $ 56,825 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 1,565 481 As of March 31, 2017 and December 31, 2016 , the Company had $268.0 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) | 3 Months Ended |
Mar. 31, 2017 | |
Summary of Outstanding Contracts with Respect to Natural Gas | At March 31, 2017 , the Company had outstanding natural gas derivative contracts as set forth in the table below. The volumes reflected below represent an aggregation of multiple derivative contracts having similar remaining durations that are expected to be realized ratably over the respective 2017 and 2018 periods. At March 31, 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 April 2017 - December 2017 Swaps - Henry Hub 99,000,000 $ 3.39 Collars - Henry Hub 49,500,000 $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 March 31, In thousands 2017 2016 Cash received (paid) on derivatives: Natural gas fixed price swaps $ 5,478 $ 39,189 Natural gas collars (6,406 ) — Cash received (paid) on derivatives, net (928 ) 39,189 Non-cash gain on derivatives: Crude oil written call options — 32 Natural gas fixed price swaps 22,896 2,393 Natural gas collars 24,890 498 Non-cash gain on derivatives, net 47,786 2,923 Gain on crude oil and natural gas derivatives, net $ 46,858 $ 42,112 |
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 March 31, 2017 December 31, 2016 Commodity derivative assets: Gross amounts of recognized assets $ 10,060 $ 4,061 Gross amounts offset on balance sheet (2,536 ) — Net amounts of assets on balance sheet 7,524 4,061 Commodity derivative liabilities: Gross amounts of recognized liabilities (20,333 ) (59,489 ) Gross amounts offset on balance sheet 2,536 — Net amounts of liabilities on balance sheet $ (17,797 ) $ (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 March 31, 2017 December 31, 2016 Derivative assets $ 7,524 $ 4,061 Noncurrent derivative assets — — Net amounts of assets on balance sheet 7,524 4,061 Derivative liabilities (17,797 ) (59,489 ) Noncurrent derivative liabilities — — Net amounts of liabilities on balance sheet (17,797 ) (59,489 ) Total derivative liabilities, net $ (10,273 ) $ (55,428 ) |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Valuation of Financial Instruments by Pricing Levels | The following tables summarize the valuation of financial instruments by pricing levels that were accounted for at fair value on a recurring basis as of March 31, 2017 and December 31, 2016 . Fair value measurements at March 31, 2017 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets (liabilities): Swaps $ — $ 7,968 $ — $ 7,968 Collars — (18,241 ) — (18,241 ) Total $ — $ (10,273 ) $ — $ (10,273 ) 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 income (loss). Three months ended March 31, In thousands 2017 2016 Proved property impairments $ 871 $ — Unproved property impairments 50,501 78,927 Total $ 51,372 $ 78,927 |
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. March 31, 2017 December 31, 2016 In thousands Carrying Estimated Fair Value Carrying Estimated Fair Value Debt: Revolving credit facility $ 835,000 $ 835,000 $ 905,000 $ 905,000 Term loan 499,020 500,000 498,865 500,000 Note payable 11,631 9,700 12,176 10,200 5% Senior Notes due 2022 1,997,280 2,019,500 1,997,188 2,020,400 4.5% Senior Notes due 2023 1,485,049 1,465,600 1,484,524 1,474,800 3.8% Senior Notes due 2024 991,228 930,900 990,964 929,400 4.9% Senior Notes due 2044 691,237 601,200 691,199 607,600 Total debt $ 6,510,445 $ 6,361,900 $ 6,579,916 $ 6,447,400 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 3 Months Ended |
Mar. 31, 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 March 31, 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 $36.2 million and $37.3 million at March 31, 2017 and December 31, 2016 , respectively, consists of the following. In thousands March 31, 2017 December 31, 2016 Revolving credit facility $ 835,000 $ 905,000 Term loan 499,020 498,865 Note payable 11,631 12,176 5% Senior Notes due 2022 1,997,280 1,997,188 4.5% Senior Notes due 2023 1,485,049 1,484,524 3.8% Senior Notes due 2024 991,228 990,964 4.9% Senior Notes due 2044 691,237 691,199 Total debt $ 6,510,445 $ 6,579,916 Less: Current portion of long-term debt 2,236 2,219 Long-term debt, net of current portion $ 6,508,209 $ 6,577,697 |
Stock-Based Compensation (Table
Stock-Based Compensation (Tables) | 3 Months Ended |
Mar. 31, 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 three months ended March 31, 2017 is presented below. Number of Weighted average Non-vested restricted shares outstanding at December 31, 2016 3,913,634 $ 37.12 Granted 1,151,041 46.21 Vested (715,222 ) 58.48 Forfeited (109,987 ) 33.71 Non-vested restricted shares outstanding at March 31, 2017 4,239,466 $ 36.08 |
Accumulated Other Comprehensi24
Accumulated Other Comprehensive Income (Tables) | 3 Months Ended |
Mar. 31, 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 loss for the three months ended March 31, 2017 and 2016 : Three months ended March 31, In thousands 2017 2016 Beginning accumulated other comprehensive loss, net of tax $ (260 ) $ (3,354 ) Foreign currency translation adjustments 138 426 Income taxes (1) — — Other comprehensive income, net of tax 138 426 Ending accumulated other comprehensive loss, net of tax $ (122 ) $ (2,928 ) (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) | 3 Months Ended |
Mar. 31, 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 March 31, $ in thousands 2017 Tax rate % 2016 Tax rate % Expected income tax (provision) benefit based on US statutory tax rate of 35% $ (2,272 ) 35 % $ 111,885 35 % State income taxes, net of federal benefit (195 ) 3 % 9,590 3 % Tax deficiency from stock-based compensation (1) (3,300 ) 51 % — — % Canadian valuation allowance (2) (145 ) 2 % (77 ) — % Effect of differing statutory tax rate in Canada (67 ) 1 % (34 ) — % Other, net (43 ) 1 % (18 ) — % (Provision) benefit for income taxes $ (6,022 ) 93 % $ 121,346 38 % (1) The Company recognized $3.3 million of tax deficiencies from stock-based compensation as income tax expense in accordance with ASU 2016-09 as discussed in Note 2. Basis of Presentation and Significant Accounting Policies–Adoption of new accounting pronouncements . (2) Represents valuation allowances recognized against all deferred tax assets associated with operating loss carryforwards generated by the Company's Canadian operations during the respective periods for which the Company does not expect to realize a benefit. |
Organization and Nature of Bu26
Organization and Nature of Business - Additional Information (Detail) | 3 Months Ended |
Mar. 31, 2017 | |
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | |
Percentage of crude oil and natural gas production concentrated in crude oil | 56.00% |
Percentage of crude oil and natural gas revenue concentrated in crude oil | 76.00% |
North Region [Member] | |
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | |
Percentage of operations concentrated in geographic areas | 56.00% |
Percentage of revenues concentrated in geographic areas | 65.00% |
South Region [Member] | |
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | |
Percentage of operations concentrated in geographic areas | 44.00% |
Percentage of revenues concentrated in geographic areas | 35.00% |
Basis of Presentation and Sig27
Basis of Presentation and Significant Accounting Policies - Components of Inventories (Detail) - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 |
Accounting Policies [Abstract] | ||
Tubular goods and equipment | $ 15,646 | $ 15,243 |
Crude oil | 83,044 | 96,744 |
Total | $ 98,690 | $ 111,987 |
Basis of Presentation and Sig28
Basis of Presentation and Significant Accounting Policies - Earnings Per Share (Detail) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | ||
Mar. 31, 2017 | Mar. 31, 2016 | ||
Accounting Policies [Abstract] | |||
Weighted Average Number Diluted Shares Outstanding Adjustment | 42,000 | ||
Net income (loss) (numerator): | |||
Net income (loss) - basic and diluted | $ 469 | $ (198,326) | |
Weighted average shares - basic | 370,831,000 | 370,062,000 | |
Non-vested restricted stock (1) | 2,522,000 | 0 | [1] |
Weighted average shares - diluted | 373,353,000 | 370,062,000 | |
Net income (loss) per share: | |||
Basic (in dollars per share) | $ 0 | $ (0.54) | |
Diluted (in dollars per share) | $ 0 | $ (0.54) | |
[1] | For the three months ended March 31, 2016 the Company had a net loss and therefore the potential dilutive effect of approximately 42,000 weighted average non-vested restricted shares were not included in the calculation of diluted net loss per share because to do so would have been anti-dilutive to the computations. |
Basis of Presentation and Sig29
Basis of Presentation and Significant Accounting Policies Basis of Presentation and Significant Accounting Policies - New Accounting Pronouncements (Details) $ / shares in Units, $ in Thousands | 3 Months Ended |
Mar. 31, 2017USD ($)$ / shares | |
Accounting Policies [Abstract] | |
Adoption of ASU 2016-09 cumulative effect on retained earnings | $ 5,150 |
Share-based Compensation, Tax Deficiency from Compensation Expense | $ 3,300 |
Tax Deficiency from Compensation Expense, Per Share | $ / shares | $ 0.01 |
Results of Operations, Transportation Costs | $ 50,000 |
Supplemental Cash Flow Inform30
Supplemental Cash Flow Information - Summary of Supplemental Cash Flow Information (Detail) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | Dec. 31, 2016 | |
Supplemental Cash Flow Elements [Abstract] | |||
Cash paid for interest | $ 57,952 | $ 56,825 | |
Cash paid for income taxes | 2 | 0 | |
Cash received for income tax refunds | 148 | 20 | |
Noncash Investing and Financing Items [Abstract] | |||
Accrued capital expenditures | 268,000 | $ 223,600 | |
Increase (Decrease) in Asset Retirement Obligations | $ 1,565 | $ 481 |
Derivative Instruments - Summar
Derivative Instruments - Summary of Outstanding Contracts with Respect to Natural Gas (Detail) - Natural Gas [Member] | 3 Months Ended |
Mar. 31, 2017MMBTU$ / MMBTU | |
April 2017 to December 2017 Swaps | |
Derivative [Line Items] | |
Natural Gas Production Derivative Volume, MMBtus | MMBTU | 99,000,000 |
Swaps Weighted Average Price | 3.39 |
April 2017 to December 2017 Collars | |
Derivative [Line Items] | |
Natural Gas Production Derivative Volume, MMBtus | MMBTU | 49,500,000 |
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] | April 2017 to December 2017 Collars | |
Derivative [Line Items] | |
Derivative, Floor Price | 2.40 |
Derivative, Cap Price | 2.92 |
Maximum [Member] | April 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 | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Non-cash gain (loss) on derivatives: | ||
Non-cash gain (loss) on derivatives, net | $ 45,155 | $ 1,863 |
Gain on crude oil and natural gas derivatives, net | 46,858 | 42,112 |
Diesel Fuel [Member] | ||
Cash received (paid) on derivatives: | ||
Cash received (paid) on derivatives, net | 700 | |
Non-cash gain (loss) on derivatives: | ||
Non-cash gain (loss) on derivatives, net | (2,600) | (1,100) |
Swap [Member] | Natural Gas [Member] | ||
Cash received (paid) on derivatives: | ||
Cash received (paid) on derivatives, net | 5,478 | 39,189 |
Non-cash gain (loss) on derivatives: | ||
Non-cash gain (loss) on derivatives, net | 22,896 | 2,393 |
Collars | Natural Gas [Member] | ||
Cash received (paid) on derivatives: | ||
Cash received (paid) on derivatives, net | (6,406) | 0 |
Non-cash gain (loss) on derivatives: | ||
Non-cash gain (loss) on derivatives, net | 24,890 | 498 |
Call Option [Member] | Crude Oil [Member] | ||
Non-cash gain (loss) on derivatives: | ||
Non-cash gain (loss) on derivatives, net | 0 | 32 |
Crude Oil and Natural Gas [Member] | ||
Cash received (paid) on derivatives: | ||
Cash received (paid) on derivatives, net | (928) | 39,189 |
Non-cash gain (loss) on derivatives: | ||
Non-cash gain (loss) on derivatives, net | 47,786 | 2,923 |
Gain on crude oil and natural gas derivatives, net | $ 46,858 | $ 42,112 |
Derivative Instruments - Gross
Derivative Instruments - Gross Amounts of Recognized Derivative Assets and Liabilities (Detail) - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Gross amounts of recognized assets | $ 10,060 | $ 4,061 |
Gross amounts offset on balance sheet | (2,536) | 0 |
Net amounts of assets on balance sheet | 7,524 | 4,061 |
Gross amounts of recognized liabilities | (20,333) | (59,489) |
Gross amounts offset on balance sheet | 2,536 | 0 |
Net amounts of liabilities on balance sheet | $ (17,797) | $ (59,489) |
Derivative Instruments - Reconc
Derivative Instruments - Reconciles Net Amounts Derivative Assets and Liabilities (Detail) - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Derivative assets | $ 7,524 | $ 4,061 |
Noncurrent derivative assets | 0 | 0 |
Net amounts of assets on balance sheet | 7,524 | 4,061 |
Derivative liabilities | (17,797) | (59,489) |
Noncurrent derivative liabilities | 0 | 0 |
Net amounts of liabilities on balance sheet | (17,797) | (59,489) |
Total derivative assets, net | $ (10,273) | $ (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 | |
Mar. 31, 2017USD ($)$ / galgal | Mar. 31, 2016USD ($) | |
Derivative [Line Items] | ||
Non-cash gain (loss) on derivatives, net | $ 45,155 | $ 1,863 |
Diesel Fuel [Member] | ||
Derivative [Line Items] | ||
Cash received (paid) on derivatives, net | 700 | |
Non-cash gain (loss) on derivatives, net | $ (2,600) | $ (1,100) |
Diesel Fuel [Member] | July 2016 to December 2017 Swaps [Member] | ||
Derivative [Line Items] | ||
Diesel Fuel Derivative Volume, gallons | gal | 9 | |
Swaps Weighted Average Price | $ / gal | 1.45 |
Fair Value Measurements - Valua
Fair Value Measurements - Valuation of Financial Instruments by Pricing Levels (Detail) - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 |
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | $ (10,273) | $ (55,428) |
Swap [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | 7,968 | (12,297) |
Collars | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | (18,241) | (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) | (10,273) | (55,428) |
Fair Value, Inputs, Level 2 [Member] | Swap [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | 7,968 | (12,297) |
Fair Value, Inputs, Level 2 [Member] | Collars | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | (18,241) | (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) | 3 Months Ended |
Mar. 31, 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 | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Proved property impairments | $ 871 | $ 0 |
Unproved property impairments | 50,501 | 78,927 |
Oil and gas property fair value after impairment | 3,400 | |
Property impairments | $ 51,372 | $ 78,927 |
Fair Value Measurements - Fair
Fair Value Measurements - Fair Values of Financial Instruments not Recorded at Fair Value (Detail) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Dec. 31, 2016 | |
Fair Value Measurements [Line Items] | ||
Loans Payable to Bank | $ 499,020 | $ 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 | $ 835,000 | 905,000 |
Loans Payable to Bank | 499,020 | 498,865 |
Note payable | 11,631 | 12,176 |
Total debt | 6,510,445 | 6,579,916 |
Carrying Amount | 5% Senior Notes due 2022 | ||
Fair Value Measurements [Line Items] | ||
Senior notes | 1,997,280 | 1,997,188 |
Carrying Amount | 4 1/2% Senior Notes Due 2023 | ||
Fair Value Measurements [Line Items] | ||
Senior notes | 1,485,049 | 1,484,524 |
Carrying Amount | 3.8% Senior Notes due 2024 | ||
Fair Value Measurements [Line Items] | ||
Senior notes | 991,228 | 990,964 |
Carrying Amount | 4.9% Senior Notes due 2044 | ||
Fair Value Measurements [Line Items] | ||
Senior notes | 691,237 | 691,199 |
Estimated Fair Value | ||
Fair Value Measurements [Line Items] | ||
Revolving credit facility | 835,000 | 905,000 |
Loans Payable to Bank | 500,000 | 500,000 |
Note payable | 9,700 | 10,200 |
Total debt | 6,361,900 | 6,447,400 |
Estimated Fair Value | 5% Senior Notes due 2022 | ||
Fair Value Measurements [Line Items] | ||
Senior notes | 2,019,500 | 2,020,400 |
Estimated Fair Value | 4 1/2% Senior Notes Due 2023 | ||
Fair Value Measurements [Line Items] | ||
Senior notes | 1,465,600 | 1,474,800 |
Estimated Fair Value | 3.8% Senior Notes due 2024 | ||
Fair Value Measurements [Line Items] | ||
Senior notes | 930,900 | 929,400 |
Estimated Fair Value | 4.9% Senior Notes due 2044 | ||
Fair Value Measurements [Line Items] | ||
Senior notes | $ 601,200 | $ 607,600 |
Long-Term Debt - Long-Term Debt
Long-Term Debt - Long-Term Debt (Detail) - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 |
Debt Instrument [Line Items] | ||
Loans Payable to Bank | $ 499,020 | $ 498,865 |
Less: Current portion of long-term debt | (2,236) | (2,219) |
Long-term debt, net of current portion | $ 6,508,209 | 6,577,697 |
5% Senior Notes due 2022 | ||
Debt Instrument [Line Items] | ||
Debt Instrument, stated interest rate | 5.00% | |
Note Payable [Member] | ||
Debt Instrument [Line Items] | ||
Debt Instrument, stated interest rate | 3.14% | |
Note payable | $ 22,000 | |
3.8% Senior Notes due 2024 | ||
Debt Instrument [Line Items] | ||
Debt Instrument, stated interest rate | 3.80% | |
4.9% Senior Notes due 2044 | ||
Debt Instrument [Line Items] | ||
Debt Instrument, stated interest rate | 4.90% | |
Carrying Amount | ||
Debt Instrument [Line Items] | ||
Revolving credit facility | $ 835,000 | 905,000 |
Loans Payable to Bank | 499,020 | 498,865 |
Note payable | 11,631 | 12,176 |
Total debt | 6,510,445 | 6,579,916 |
Carrying Amount | 5% Senior Notes due 2022 | ||
Debt Instrument [Line Items] | ||
Senior notes | 1,997,280 | 1,997,188 |
Carrying Amount | 4 1/2% Senior Notes Due 2023 | ||
Debt Instrument [Line Items] | ||
Senior notes | 1,485,049 | 1,484,524 |
Carrying Amount | 3.8% Senior Notes due 2024 | ||
Debt Instrument [Line Items] | ||
Senior notes | 991,228 | 990,964 |
Carrying Amount | 4.9% Senior Notes due 2044 | ||
Debt Instrument [Line Items] | ||
Senior notes | 691,237 | 691,199 |
Estimated Fair Value | ||
Debt Instrument [Line Items] | ||
Revolving credit facility | 835,000 | 905,000 |
Loans Payable to Bank | 500,000 | 500,000 |
Note payable | 9,700 | 10,200 |
Total debt | 6,361,900 | 6,447,400 |
Estimated Fair Value | 5% Senior Notes due 2022 | ||
Debt Instrument [Line Items] | ||
Senior notes | 2,019,500 | 2,020,400 |
Estimated Fair Value | 4 1/2% Senior Notes Due 2023 | ||
Debt Instrument [Line Items] | ||
Senior notes | 1,465,600 | 1,474,800 |
Estimated Fair Value | 3.8% Senior Notes due 2024 | ||
Debt Instrument [Line Items] | ||
Senior notes | 930,900 | 929,400 |
Estimated Fair Value | 4.9% Senior Notes due 2044 | ||
Debt Instrument [Line Items] | ||
Senior notes | $ 601,200 | $ 607,600 |
Long-Term Debt - Additional Inf
Long-Term Debt - Additional Information (Detail) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Dec. 31, 2016 | |
Debt Instrument [Line Items] | ||
Loans Payable to Bank | $ 499,020 | $ 498,865 |
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net | $ 36,200 | 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 | $ 2,236 | 2,219 |
Line of Credit Facility, Covenant Terms | 0.65 | |
Revolving Credit Facility [Member] | ||
Debt Instrument [Line Items] | ||
Debt, Weighted Average Interest Rate | 2.60% | |
Line of Credit Facility, Remaining Borrowing Capacity | $ 1,910,000 | |
Loans Payable [Member] | ||
Debt Instrument [Line Items] | ||
Debt Instrument, stated interest rate | 2.35% | |
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 [Member] | ||
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 | 835,000 | 905,000 |
Notes Payable | 9,700 | 10,200 |
Estimated Fair Value | 5% Senior Notes due 2022 | ||
Debt Instrument [Line Items] | ||
Senior notes | 2,019,500 | 2,020,400 |
Estimated Fair Value | 3.8% Senior Notes due 2024 | ||
Debt Instrument [Line Items] | ||
Senior notes | 930,900 | 929,400 |
Estimated Fair Value | 4.9% Senior Notes due 2044 | ||
Debt Instrument [Line Items] | ||
Senior notes | 601,200 | 607,600 |
Carrying Amount | ||
Debt Instrument [Line Items] | ||
Loans Payable to Bank | 499,020 | 498,865 |
Credit facility | 835,000 | 905,000 |
Notes Payable | 11,631 | 12,176 |
Carrying Amount | 5% Senior Notes due 2022 | ||
Debt Instrument [Line Items] | ||
Senior notes | 1,997,280 | 1,997,188 |
Carrying Amount | 3.8% Senior Notes due 2024 | ||
Debt Instrument [Line Items] | ||
Senior notes | 991,228 | 990,964 |
Carrying Amount | 4.9% Senior Notes due 2044 | ||
Debt Instrument [Line Items] | ||
Senior notes | $ 691,237 | $ 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 | 3 Months Ended |
Mar. 31, 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 | 3 Months Ended | |
Nov. 30, 2010 | Mar. 31, 2017 | Dec. 31, 2016 | |
Long-term Purchase Commitment [Line Items] | |||
Total future drilling commitments at balance sheet date | $ 183 | ||
Drilling commitments due remainder of current year | 94 | ||
Drilling commitments Year Two | 59 | ||
Drilling Commitments Year Three | 29 | ||
Drilling Commitments Year Four | $ 1 | ||
Future Drilling Commitments End Date | 2020-02 | ||
Damages sought in litigation matter | $ 200 | ||
Legal proceedings recorded as a liability under other noncurrent liabilities | $ (6.7) | $ (6.5) | |
Future Gas Transportation Costs | $ 380 | ||
Pipeline Transportation of Crude Oil and Natural Gas [Member] | |||
Long-term Purchase Commitment [Line Items] | |||
Pipeline commitments, end date | 2,027 | ||
Purchase Obligation, total | $ 839 | ||
Purchase Obligation, due in remainder of current year | 169 | ||
Purchase Obligation, due second year | 217 | ||
Purchase Obligation, due third year | 191 | ||
Purchase Obligation, due fourth year | 59 | ||
Purchase Obligation, due fifth year | 47 | ||
Purchase Obligation, due after fifth year | $ 156 |
Stock Based Compensation - Stoc
Stock Based Compensation - Stock Based Compensation Expenses (Detail) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | ||
Non-cash equity compensation | $ 11.4 | $ 9.2 |
Stock-Based Compensation - Addi
Stock-Based Compensation - Additional Information (Detail) $ in Millions | 3 Months Ended |
Mar. 31, 2017USD ($)shares | |
Restricted stock [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Stock available to grant | shares | 14,437,178 |
Fair value at vesting date | $ | $ 33.1 |
Unrecognized compensation expense related to non-vested | $ | $ 93 |
Unrecognized compensation expense related to non-vested, period for recognition, in years | 1 year 10 months 5 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) | 3 Months Ended |
Mar. 31, 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 | 1,151,041 |
Vested shares | shares | (715,222) |
Forfeited (unaudited), shares | shares | (109,987) |
Non-vested shares, ending balance | shares | 4,239,466 |
Non-vested, weighted average grant-date fair value, beginning of period | $ / shares | $ 37.12 |
Granted, weighted average grant-date fair value | $ / shares | 46.21 |
Vested, weighted average grant-date fair value | $ / shares | 58.48 |
Forfeited, weighted average grant-date fair value | $ / shares | 33.71 |
Non-vested, weighted average grant-date fair value, end of period | $ / shares | $ 36.08 |
Accumulated Other Comprehensi47
Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands | 3 Months Ended | |||
Mar. 31, 2017 | Mar. 31, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | |
Accumulated Other Comprehensive Income [Abstract] | ||||
Accumulated other comprehensive loss, net of tax | $ (122) | $ (2,928) | $ (260) | $ (3,354) |
Foreign currency translation adjustments | 138 | 426 | ||
Translation Adjustment Functional to Reporting Currency, Tax Benefit (Expense) | 0 | 0 | ||
Other Comprehensive Income (Loss), Net of Tax (unaudited) | $ 138 | $ 426 |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Income Taxes [Abstract] | ||
Share-based Compensation, Tax Deficiency from Compensation Expense | $ 3,300 | |
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount | $ (2,272) | $ 111,885 |
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 35.00% | 35.00% |
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount | $ (195) | $ 9,590 |
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent | 3.00% | 3.00% |
Effective Income Tax Rate Reconciliation, Tax Benefit (Deficiency), Amount | $ (3,300) | $ 0 |
Effective Income Tax Rate Reconciliation, Tax Benefit (Deficiency), Percent | 51.00% | 0.00% |
Effective Income Tax Rate Reconciliation, Valuation Allowance, Amount | $ (145) | $ (77) |
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Percent | 2.00% | 0.00% |
Effective Income Tax Rate Reconciliation, Tax Settlement, Foreign, Amount | $ (67) | $ (34) |
Effective Income Tax Rate Reconciliation, Tax Settlement, Foreign, Percent | 1.00% | 0.00% |
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount | $ (43) | $ (18) |
Effective Income Tax Rate Reconciliation, Other Adjustments, Percent | 0.70% | 0.00% |
(Provision) benefit for income taxes | $ (6,022) | $ 121,346 |
Effective Income Tax Rate Reconciliation, Percent | 93.00% | 38.00% |