Document and Entity Information
Document and Entity Information - shares | 6 Months Ended | |
Jun. 30, 2018 | Jul. 31, 2018 | |
Document Document And Entity Information [Abstract] | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Jun. 30, 2018 | |
Document Fiscal Year Focus | 2,018 | |
Document Fiscal Period Focus | Q2 | |
Trading Symbol | CLR | |
Entity Registrant Name | CONTINENTAL RESOURCES, INC | |
Entity Central Index Key | 732,834 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Entity Common Stock, Shares Outstanding | 376,037,498 |
Condensed Consolidated Balance
Condensed Consolidated Balance Sheets - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Current assets: | ||
Cash and cash equivalents | $ 129,989 | $ 43,902 |
Receivables: | ||
Crude oil and natural gas sales | 671,004 | 671,665 |
Affiliated parties | 58 | 63 |
Joint interest and other, net | 506,301 | 426,585 |
Derivative assets | 203 | 2,603 |
Inventories | 115,310 | 97,406 |
Prepaid expenses and other | 18,424 | 9,501 |
Total current assets | 1,441,289 | 1,251,725 |
Net property and equipment, based on successful efforts method of accounting | 13,339,571 | 12,933,789 |
Other noncurrent assets | 17,620 | 14,137 |
Total assets | 14,798,480 | 14,199,651 |
Current liabilities: | ||
Accounts payable trade | 811,965 | 692,908 |
Revenues and royalties payable | 380,651 | 374,831 |
Payables to affiliated parties | 237 | 143 |
Accrued liabilities and other | 280,199 | 260,074 |
Derivative liabilities | 9,065 | 0 |
Current portion of long-term debt | 2,322 | 2,286 |
Total current liabilities | 1,484,439 | 1,330,242 |
Long-term debt, net of current portion | 6,164,221 | 6,351,405 |
Other noncurrent liabilities: | ||
Deferred income tax liabilities, net | 1,406,326 | 1,259,558 |
Asset retirement obligations, net of current portion | 117,924 | 111,794 |
Other noncurrent liabilities | 12,082 | 15,449 |
Total other noncurrent liabilities | 1,536,332 | 1,386,801 |
Commitments and contingencies (Note 8) | ||
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; 376,030,797 shares issued and outstanding at June 30, 2018; 375,219,769 shares issued and outstanding at December 31, 2017 | 3,760 | 3,752 |
Additional paid-in capital | 1,415,175 | 1,409,326 |
Accumulated other comprehensive income | 325 | 307 |
Retained earnings | 4,194,228 | 3,717,818 |
Total shareholders’ equity | 5,613,488 | 5,131,203 |
Total liabilities and shareholders’ equity | $ 14,798,480 | $ 14,199,651 |
Condensed Consolidated Balance3
Condensed Consolidated Balance Sheets (Parenthetical) - $ / shares | Jun. 30, 2018 | Dec. 31, 2017 |
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 | 376,030,797 | 375,219,769 |
Common Stock, Shares, Outstanding | 376,030,797 | 375,219,769 |
Unaudited Condensed Consolidate
Unaudited Condensed Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Revenues: | ||||
Crude oil and natural gas sales | $ 1,137,528 | $ 626,548 | $ 2,251,380 | $ 1,260,398 |
Gain (loss) on natural gas derivatives, net | (12,685) | 28,022 | (2,511) | 74,880 |
Crude oil and natural gas service operations | 12,270 | 6,916 | 29,272 | 11,636 |
Total revenues | 1,137,113 | 661,486 | 2,278,141 | 1,346,914 |
Operating costs and expenses: | ||||
Production expenses | 90,171 | 82,474 | 183,133 | 155,328 |
Production taxes | 83,595 | 41,965 | 164,175 | 83,198 |
Transportation expenses | 47,254 | 0 | 96,551 | 0 |
Exploration expenses | 303 | 3,204 | 2,023 | 8,202 |
Crude oil and natural gas service operations | 7,688 | 4,478 | 12,271 | 7,315 |
Depreciation, depletion, amortization and accretion | 447,200 | 395,770 | 901,578 | 777,926 |
Property impairments | 29,162 | 123,316 | 62,946 | 174,689 |
General and administrative expenses | 47,174 | 39,186 | 90,217 | 86,407 |
Net (gain) loss on sale of assets and other | (6,710) | 134 | (6,751) | 5,669 |
Total operating costs and expenses | 745,837 | 690,527 | 1,506,143 | 1,298,734 |
Income (loss) from operations | 391,276 | (29,041) | 771,998 | 48,180 |
Other income (expense): | ||||
Interest expense | (74,288) | (72,744) | (150,182) | (143,916) |
Other | 708 | 373 | 1,362 | 815 |
Total other income (expense) | (73,580) | (72,371) | (148,820) | (143,101) |
Income (loss) before income taxes | 317,696 | (101,412) | 623,178 | (94,921) |
(Provision) benefit for income taxes | (75,232) | 37,855 | (146,768) | 31,833 |
Net income (loss) | 242,464 | (63,557) | 476,410 | (63,088) |
Foreign currency translation adjustments | 16 | 189 | 18 | 327 |
Total other comprehensive income, net of tax | 16 | 189 | 18 | 327 |
Comprehensive income (loss) | $ 242,480 | $ (63,368) | $ 476,428 | $ (62,761) |
Basic net income per share (in dollars per share) | $ 0.65 | $ (0.17) | $ 1.28 | $ (0.17) |
Diluted net income per share (in dollars per share) | $ 0.65 | $ (0.17) | $ 1.27 | $ (0.17) |
Condensed Consolidated Statemen
Condensed Consolidated Statements of Shareholders Equity - 6 months ended Jun. 30, 2018 - USD ($) $ in Thousands | Total | Common Stock [Member] | Additional Paid-In Capital [Member] | Accumulated Other Comprehensive Loss [Member] | Retained Earnings [Member] |
Balance at Dec. 31, 2017 | $ 5,131,203 | $ 3,752 | $ 1,409,326 | $ 307 | $ 3,717,818 |
Balance, shares at Dec. 31, 2017 | 375,219,769 | 375,219,769 | |||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Net income | $ 476,410 | 476,410 | |||
Other comprehensive income, net of tax (unaudited) | 18 | 18 | |||
Stock-based compensation (unaudited) | 21,465 | 21,465 | |||
Restricted stock: | |||||
Granted (unaudited) | $ 13 | $ 13 | |||
Granted (unaudited), shares | 1,277,491 | 1,277,491 | |||
Repurchased and canceled (unaudited) | $ (15,619) | $ (3) | (15,616) | ||
Repurchased and canceled (unaudited), shares | (287,506) | (287,506) | |||
Forfeited (unaudited), shares | (178,957) | (178,957) | |||
Forfeitures (unaudited) | $ (2) | $ (2) | |||
Balance at Jun. 30, 2018 | $ 5,613,488 | $ 3,760 | $ 1,415,175 | $ 325 | $ 4,194,228 |
Balance, shares at Jun. 30, 2018 | 376,030,797 | 376,030,797 |
Unaudited Condensed Consolidat6
Unaudited Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2018 | Jun. 30, 2017 | |
Cash flows from operating activities | ||
Net income (loss) | $ 476,410 | $ (63,088) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||
Depreciation, Depletion, Amortization and Accretion | 902,217 | 774,810 |
Property impairments | 62,946 | 174,689 |
Non-cash (gain) loss on derivatives, net | 11,465 | (68,420) |
Stock-based compensation | 21,478 | 20,571 |
Provision (benefit) for deferred income taxes | 146,768 | (31,834) |
Dry hole costs | 1 | 157 |
(Gain) loss on sale of assets, net | (6,751) | 2,859 |
Other, net | 7,159 | 5,089 |
Changes in assets and liabilities: | ||
Accounts receivable | (79,043) | (19,347) |
Inventories | (17,904) | 14,984 |
Other current assets | (8,138) | (2,225) |
Accounts payable trade | 103,710 | 105,441 |
Revenues and royalties payable | 5,857 | 21,105 |
Accrued liabilities and other | 17,550 | (17,968) |
Other noncurrent assets and liabilities | (3,732) | (251) |
Net cash provided by operating activities | 1,639,993 | 916,572 |
Cash flows from investing activities | ||
Exploration and development | (1,334,681) | (877,115) |
Purchase of producing crude oil and natural gas properties | (24,097) | (812) |
Purchase of other property and equipment | (12,205) | (9,372) |
Proceeds from sale of assets | 27,380 | 7,979 |
Net cash used in investing activities | (1,343,603) | (879,320) |
Cash flows from financing activities | ||
Credit facility borrowings | 803,000 | 540,000 |
Repayment of credit facility | (991,000) | (565,000) |
Repayment of other debt | (1,134) | (1,099) |
Debt issuance costs | (5,524) | 0 |
Repurchase of restricted stock for tax withholdings | (15,619) | (10,620) |
Net cash used in financing activities | (210,277) | (36,719) |
Effect of Exchange Rate on Cash and Cash Equivalents | (26) | 14 |
Net change in cash and cash equivalents | 86,087 | 547 |
Cash and cash equivalents at beginning of period | 43,902 | 16,643 |
Cash and cash equivalents at end of period | $ 129,989 | $ 17,190 |
Organization and Nature of Busi
Organization and Nature of Business | 6 Months Ended |
Jun. 30, 2018 | |
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 and STACK 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 59% of the Company’s crude oil and natural gas production and 74% of its crude oil and natural gas revenues for the six months ended June 30, 2018 . 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 41% of the Company's crude oil and natural gas production and 26% of its crude oil and natural gas revenues for the six months ended June 30, 2018 . For the six months ended June 30, 2018 , crude oil accounted for 56% of the Company’s total production and 82% of its crude oil and natural gas revenues. |
Basis of Presentation and Signi
Basis of Presentation and Significant Accounting Policies | 6 Months Ended |
Jun. 30, 2018 | |
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, 2017 (“ 2017 Form 10-K”), which includes a summary of the Company’s significant accounting policies and other disclosures. The condensed consolidated financial statements as of June 30, 2018 and for the three and six month periods ended June 30, 2018 and 2017 are unaudited. The condensed consolidated balance sheet as of December 31, 2017 was derived from the audited balance sheet included in the 2017 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 estimates and assumptions impacting reported results are estimates of the Company’s crude oil and natural gas reserves, which are used to compute depreciation, depletion, amortization and impairment of proved crude oil and natural gas properties. 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 and six months ended June 30, 2018 and 2017 . Three months ended June 30, Six months ended June 30, In thousands, except per share data 2018 2017 2018 2017 Net income (loss) (numerator) $ 242,464 $ (63,557 ) $ 476,410 $ (63,088 ) Weighted average shares (denominator): Weighted average shares - basic 371,921 371,111 371,733 370,972 Non-vested restricted stock (1) 2,584 — 2,850 — Weighted average shares - diluted 374,505 371,111 374,583 370,972 Net income (loss) per share: Basic $ 0.65 $ (0.17 ) $ 1.28 $ (0.17 ) Diluted $ 0.65 $ (0.17 ) $ 1.27 $ (0.17 ) (1) For the three and six months ended June 30, 2017 , the Company had a net loss and therefore the potential dilutive effect of approximately 1,933,200 and 2,546,200 weighted average non-vested restricted shares, respectively, were not included in the calculation of diluted net loss per share because to do so would have been anti-dilutive to the computations for those periods. Inventories Inventory is comprised of crude oil held in storage or as line fill in pipelines, pipeline imbalances, and tubular goods and equipment to be used in the Company's exploration and development activities. Crude oil inventories are valued at the lower of cost or market primarily using the first-in, first-out inventory method. Tubular goods and equipment are valued primarily using a weighted average cost method applied to specific classes of inventory items. The components of inventory as of June 30, 2018 and December 31, 2017 consisted of the following: In thousands June 30, 2018 December 31, 2017 Tubular goods and equipment $ 18,722 $ 14,946 Crude oil 96,588 82,460 Total $ 115,310 $ 97,406 Adoption of new accounting pronouncements Revenue recognition and presentation – In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers (Topic 606) , which supersedes nearly all previously existing revenue recognition guidance under U.S. GAAP. Subsequently, the FASB issued additional guidance to assist entities with implementation efforts, including the issuance of ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). This new guidance became effective for reporting periods beginning after December 15, 2017. The Company adopted the new revenue recognition and presentation guidance on January 1, 2018 as required. See Note 4. Revenues for discussion of the adoption impact and the applicable disclosures required by the new guidance. 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. The Company plans to adopt the new standard using the simplified transition method prescribed by ASU 2018-11, Leases (Topic 842): Targeted Improvements , whereby the Company will initially apply the new standard as of the January 1, 2019 adoption date and will recognize a cumulative-effect adjustment to the opening balance of retained earnings, if any, upon adoption in lieu of retrospectively applying the new standard to pre-adoption periods. The Company continues to evaluate the impact of ASU 2016-02 on its financial statements, accounting policies and internal controls and is in the process of implementing systems and processes to capture, classify, and account for leases within the scope of the new guidance and to comply with the related disclosure requirements. Interpretations and application of the new guidance continue to evolve and are being monitored for applicability and impact on the Company. Based on an initial review of the new guidance and the Company’s current commitments, the Company anticipates it will be required to recognize lease assets and liabilities related to drilling rig commitments, certain equipment rentals and leases, certain surface use agreements, and potentially other arrangements. The Company does not believe any of its firm transportation agreements will qualify as leases, but continues to evaluate such arrangements. Based on commitments in place as of June 30, 2018 , the Company currently estimates its lease assets and liabilities to be recognized under ASU 2016-02 will total approximately $100 million , the majority of which will be comprised of future cash flows associated with drilling rig commitments, which are further discussed in Note 8. Commitments and Contingencies–Drilling commitments . This estimate may be subsequently revised based on unforeseen changes in the nature, timing, and extent of the Company's contractual arrangements from period to period, finalization of the Company's evaluation of its firm transportation agreements, or due to changes in the Company's interpretation or application of the new guidance. Credit losses – In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments . This standard changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. The standard is effective for interim and annual periods beginning after December 15, 2019 and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. The Company continues to evaluate the new standard and is unable to estimate its financial statement impact at this time; however, the impact is not expected to be material. Historically, the Company's credit losses on crude oil and natural gas sales receivables and joint interest receivables have been immaterial. |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | 6 Months Ended |
Jun. 30, 2018 | |
Supplemental Cash Flow Elements [Abstract] | |
Supplemental Cash Flow Information | Supplemental Cash Flow Information The following table discloses supplemental cash flow information about cash paid for interest and income tax payments and refunds. Also disclosed is information about investing activities that affects recognized assets and liabilities but does not result in cash receipts or payments. Six months ended June 30, In thousands 2018 2017 Supplemental cash flow information: Cash paid for interest $ 122,940 $ 138,346 Cash paid for income taxes — 2 Cash received for income tax refunds 5 148 Non-cash investing activities: Asset retirement obligation additions and revisions, net 3,562 3,771 As of June 30, 2018 and December 31, 2017 , the Company had $317.5 million and $302.8 million , respectively, of accrued capital expenditures included in “Net property and equipment” and “Accounts payable trade” in the condensed consolidated balance sheets. |
Revenues (Notes)
Revenues (Notes) | 6 Months Ended |
Jun. 30, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Revenue from Contract with Customer [Text Block] | Revenues Adoption of new revenue recognition and disclosure guidance 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, allocate the consideration to each separate performance obligation, and recognize revenue as obligations are satisfied. Additionally, the standard requires expanded disclosures related to revenue recognition. Subsequent to the issuance of ASU 2014-09, the FASB issued additional guidance to assist entities with implementation efforts, including the issuance of ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis. This guidance requires an entity to record revenue on a gross basis if it controls a promised good or service before transferring it to a customer, whereas an entity records revenue on a net basis if its role is to arrange for another entity to provide the goods or services to a customer. Applying the guidance in ASU 2016-08 requires significant judgment in determining the point in time when control of products transfers to customers. The Company adopted the new revenue recognition and presentation guidance on January 1, 2018 using a modified retrospective transition approach to all applicable contracts at the date of initial application, whereby the standard has been applied for periods commencing after December 31, 2017 and prior period results have not been adjusted to conform to current presentation. Adoption of the new guidance had no cumulative effect impact on the Company's retained earnings at January 1, 2018. The new guidance does not have a material impact on the timing of the Company’s revenue recognition or its financial position, results of operations, net income, or cash flows, but does impact the Company's presentation of revenues and expenses under the gross-versus-net presentation guidance in ASU 2016-08. In years prior to 2018, the Company generally presented its revenues net of costs incurred to transport its production to market. Under the new guidance, revenues and transportation expenses associated with production originating from the Company’s operated properties are now reported on a gross basis as further discussed below. The changes from net to gross presentation resulted in an increase in revenues and a corresponding increase in separately reported transportation expenses, with no net effect on the Company’s results of operations, net income, or cash flows for the three and six months ended June 30, 2018 . The following table reflects the change in presentation of revenues and applicable expenses on the Company's 2018 results under the new and previous guidance. Three months ended June 30, 2018 Six months ended June 30, 2018 In thousands New Standard Prior Presentation Change New Standard Prior Presentation Change Revenues: Crude oil and natural gas sales $ 1,137,528 $ 1,090,274 $ 47,254 $ 2,251,380 $ 2,154,829 $ 96,551 Loss on natural gas derivatives, net (12,685 ) (12,685 ) — (2,511 ) (2,511 ) — Crude oil and natural gas service operations 12,270 12,270 — 29,272 29,272 — Total revenues $ 1,137,113 $ 1,089,859 $ 47,254 $ 2,278,141 $ 2,181,590 $ 96,551 Operating costs and expenses: Transportation expenses $ 47,254 $ — $ 47,254 $ 96,551 $ — $ 96,551 Net income $ 242,464 $ 242,464 $ — $ 476,410 $ 476,410 $ — Revenue from contracts with customers Below is a discussion of the nature, timing, and presentation of revenues arising from the Company's major revenue-generating arrangements. Operated crude oil revenues – The Company pays third parties to transport the majority of its operated crude oil production from lease locations to downstream market centers, at which time the Company's customers take title and custody of the product in exchange for prices based on the particular market where the product was delivered. Operated crude oil revenues are recognized during the month in which control transfers to the customer and it is probable the Company will collect the consideration it is entitled to receive. Crude oil sales proceeds from operated properties are generally received by the Company within one month after the month in which a sale has occurred. Operated crude oil revenues and transportation expenses are reported on a gross basis, as the Company controls the operated production prior to its transfer to customers. Transportation expenses associated with the Company's operated crude oil production totaled $40.2 million and $80.6 million for the three and six months ended June 30, 2018 , respectively. Operated natural gas revenues – The Company sells the majority of its operated natural gas production to midstream customers at its lease locations under multi-year term contracts based on market prices in the field where the sales occur. Under these arrangements, the midstream customers obtain control of the unprocessed gas stream at the lease location and the Company's revenues from each sale are determined using contractually agreed pricing formulas which contain multiple components, including the volume and Btu content of the natural gas sold, the midstream customer's proceeds from the sale of residue gas and natural gas liquids ("NGLs") at secondary downstream markets, and contractual pricing adjustments reflecting the midstream customer's estimated recoupment of its investment over time. Such revenues are recognized net of pricing adjustments applied by the midstream customer during the month in which control transfers to the customer at the delivery point and it is probable the Company will collect the consideration it is entitled to receive. Natural gas sales proceeds from operated properties are generally received by the Company within one month after the month in which a sale has occurred. Under certain arrangements, the Company may elect to take a volume of processed residue gas and/or NGLs in-kind at the tailgate of the midstream customer's processing plant in lieu of a monetary settlement based on the customer's proceeds for sale of those processed products. When the Company elects to do so, it pays third parties to transport the processed products which it took in-kind to downstream delivery points, where it then sells the products to customers at prices applicable to those downstream markets. In such situations, operated revenues are recognized during the month in which control transfers to the customer at the delivery point and it is probable the Company will collect the consideration it is entitled to receive. Operated sales proceeds are generally received by the Company within one month after the month in which a sale has occurred. In these scenarios, the Company's revenues include the pricing adjustments applied by the midstream processing entity according to the applicable contractual pricing formula, but exclude the transportation expenses the Company incurs to transport the processed products to downstream customers. Transportation expenses associated with these arrangements totaled $7.0 million and $15.9 million for the three and six months ended June 30, 2018 , respectively, comprised entirely of costs to transport processed residue gas. Non-operated crude oil and natural gas revenues – The Company's proportionate share of production from non-operated properties is marketed at the discretion of the operators. For non-operated properties, the Company receives a net payment from the operator representing its proportionate share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds to be received by the Company during the month in which production occurs and it is probable the Company will collect the consideration it is entitled to receive. Proceeds are generally received by the Company within two to three months after the month in which production occurs. Natural gas derivative revenues – See Note 5. Derivative Instruments for discussion of the Company's accounting for its derivative instruments. Revenues from service operations – Revenues from the Company's crude oil and natural gas service operations consist primarily of revenues associated with water gathering, recycling, and disposal activities and the treatment and sale of crude oil reclaimed from waste products. Revenues associated with such activities, which are derived using market-based rates or rates commensurate with industry guidelines, are recognized during the month in which services are performed, the Company has an unconditional right to receive payment, and collectability is probable. Payment is generally received by the Company within one month after the month in which services are provided. Disaggregation of crude oil and natural gas revenues The following table presents the disaggregation of the Company's crude oil and natural gas revenues for the three and six months ended June 30, 2018 . Three months ended June 30, 2018 Six months ended June 30, 2018 In thousands North Region South Region Total North Region South Region Total Crude oil revenues: Operated properties $ 587,582 $ 145,603 $ 733,185 $ 1,156,794 $ 284,056 $ 1,440,850 Non-operated properties 196,301 17,398 213,699 379,188 33,127 412,315 Total crude oil revenues 783,883 163,001 946,884 1,535,982 317,183 1,853,165 Natural gas revenues: Operated properties 41,425 121,188 162,613 93,245 248,442 341,687 Non-operated properties 13,982 14,049 28,031 27,661 28,867 56,528 Total natural gas revenues 55,407 135,237 190,644 120,906 277,309 398,215 Crude oil and natural gas sales $ 839,290 $ 298,238 $ 1,137,528 $ 1,656,888 $ 594,492 $ 2,251,380 Timing of revenue recognition Goods transferred at a point in time $ 839,290 $ 298,238 $ 1,137,528 $ 1,656,888 $ 594,492 $ 2,251,380 Goods transferred over time — — — — — — $ 839,290 $ 298,238 $ 1,137,528 $ 1,656,888 $ 594,492 $ 2,251,380 Performance obligations The Company satisfies the performance obligations under its crude oil and natural gas sales contracts upon delivery of its production and related transfer of control to customers. Upon delivery of production, the Company has a right to receive consideration from its customers in amounts that correspond with the value of the production transferred. All of the Company's outstanding crude oil sales contracts at June 30, 2018 are short-term in nature with contract terms of less than one year. For such contracts, the Company has utilized the practical expedient in Accounting Standards Codification ("ASC") 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations, if any, if the performance obligation is part of a contract that has an original expected duration of one year or less. The majority of the Company's operated natural gas production is sold at lease locations to midstream customers under multi-year term contracts. For such contracts having a term greater than one year, the Company has utilized the practical expedient in ASC 606-10-50-14A which indicates an entity is not required to disclose the transaction price allocated to remaining performance obligations, if any, if variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under our sales contracts, whether for crude oil or natural gas, each unit of production delivered to a customer represents a separate performance obligation; therefore, future volumes to be delivered are wholly unsatisfied at period-end and disclosure of the transaction price allocated to remaining performance obligations is not applicable. Contract balances Under the Company’s crude oil and natural gas sales contracts or activities that give rise to service revenues, the Company recognizes revenue after its performance obligations have been satisfied, at which point the Company has an unconditional right to receive payment. Accordingly, the Company’s commodity sales contracts and service activities generally do not give rise to contract assets or contract liabilities under ASC Topic 606. Instead, the Company's unconditional rights to receive consideration are presented as a receivable within "Receivables – Crude oil and natural gas sales" or "Receivables – Joint interest and other, net", as applicable, in its condensed consolidated balance sheets. Revenues from previously satisfied performance obligations To record revenues for commodity sales, at the end of each month the Company estimates the amount of production delivered and sold to customers and the prices to be received for such sales. Differences between estimated revenues and actual amounts received for all prior months are recorded in the month payment is received from the customer and are reflected in the financial statements within the caption "Crude oil and natural gas sales". Revenues recognized during the three and six months ended June 30, 2018 related to performance obligations satisfied in prior reporting periods were not material. |
Derivative Instruments
Derivative Instruments | 6 Months Ended |
Jun. 30, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Instruments | Derivative Instruments Natural gas derivatives From time to time the Company has entered into natural gas swap and collar derivative contracts to economically hedge against the variability in cash flows associated with future sales of 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 its natural gas derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The Company has not designated its natural gas derivatives 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 (loss) on natural gas derivatives, net ”. The Company's natural gas derivative contracts are settled based upon reported NYMEX Henry Hub settlement prices. The estimated fair value of derivatives is based upon various factors, including commodity exchange prices, over-the-counter quotations and, in the case of collars, volatility, the risk-free interest rate, and the time to expiration. The calculation of the fair value of collars requires the use of an option-pricing model. See Note 6. Fair Value Measurements . With respect to a 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 natural gas collar contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price. Neither party is required to make a payment to the other party if the settlement price for any settlement period is between the floor price and the ceiling price. At June 30, 2018 the Company had outstanding natural gas derivative contracts as set forth in the table below. The volumes reflected below represent an aggregation of multiple derivative contracts having similar remaining durations expected to be realized ratably over the remainder of 2018. At June 30, 2018 the Company had no outstanding crude oil derivative contracts. Swaps Weighted Average Price Period and Type of Contract MMBtus July 2018 - December 2018 Swaps - Henry Hub 115,920,000 $ 2.88 Natural gas derivative gains and losses Cash receipts and payments in the following table reflect the gain or loss on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price of matured contracts. Non-cash gains and losses below represent the change in fair value of derivative instruments which continue to be held at period end and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period. Three months ended June 30, Six months ended June 30, In thousands 2018 2017 2018 2017 Cash received (paid) on derivatives: Natural gas fixed price swaps $ 4,758 $ 6,709 $ 8,954 $ 12,187 Natural gas collars — (3,050 ) — (9,456 ) Cash received (paid) on derivatives, net 4,758 3,659 8,954 2,731 Non-cash gain (loss) on derivatives: Natural gas fixed price swaps (17,443 ) 12,520 (11,465 ) 35,416 Natural gas collars — 11,843 — 36,733 Non-cash gain (loss) on derivatives, net (17,443 ) 24,363 (11,465 ) 72,149 Gain (loss) on natural gas derivatives, net $ (12,685 ) $ 28,022 $ (2,511 ) $ 74,880 Diesel fuel derivatives The Company previously entered into diesel fuel swap derivative contracts, all of which matured on or before December 31, 2017, to economically hedge against the variability in cash flows associated with purchases of diesel fuel for use in drilling activities. With respect to the diesel fuel swap contracts, the counterparty was required to make a payment to the Company if the settlement price for any settlement period was greater than the swap price, and the Company was required to make a payment to the counterparty if the settlement price for any settlement period was less than the swap price. The diesel fuel swap contracts were settled based upon reported NYMEX settlement prices for New York Harbor ultra-low sulfur diesel fuel. The Company recognized its diesel fuel derivatives on the balance sheet as either assets or liabilities measured at fair value. The estimated fair value was based upon various factors, including commodity exchange prices, over-the-counter quotations, the risk-free interest rate, and time to expiration. The Company did not designate its diesel fuel derivatives as hedges for accounting purposes and, as a result, marked the derivative instruments to fair value and recognized the changes in fair value in the unaudited condensed consolidated statements of comprehensive income (loss) under the caption “Operating costs and expenses — Net (gain) loss on sale of assets and other.” Cash receipts in the following table reflect gains on diesel fuel derivatives which matured during the 2017 period, calculated as the difference between the contract price and the market settlement price of matured contracts. Non-cash losses below represent the change in fair value of diesel fuel derivatives held at June 30, 2017 and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the three and six months ended June 30, 2017 . Three months ended June 30, Six months ended June 30, In thousands 2018 2017 2018 2017 Cash received on diesel fuel derivatives $ — $ 185 $ — $ 919 Non-cash loss on diesel fuel derivatives — (1,098 ) — (3,729 ) Loss on diesel fuel derivatives, net $ — $ (913 ) $ — $ (2,810 ) 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 natural gas and diesel fuel derivative assets and liabilities, as applicable, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the condensed consolidated balance sheets for the periods presented, all at fair value. In thousands June 30, 2018 December 31, 2017 Commodity derivative assets: Gross amounts of recognized assets $ 885 $ 2,603 Gross amounts offset on balance sheet (682 ) — Net amounts of assets on balance sheet 203 2,603 Commodity derivative liabilities: Gross amounts of recognized liabilities (9,747 ) — Gross amounts offset on balance sheet 682 — Net amounts of liabilities on balance sheet $ (9,065 ) $ — The following table reconciles the net amounts disclosed above to the individual financial statement line items in the condensed consolidated balance sheets. In thousands June 30, 2018 December 31, 2017 Derivative assets $ 203 $ 2,603 Noncurrent derivative assets — — Net amounts of assets on balance sheet 203 2,603 Derivative liabilities (9,065 ) — Noncurrent derivative liabilities — — Net amounts of liabilities on balance sheet (9,065 ) — Total derivative assets (liabilities), net $ (8,862 ) $ 2,603 |
Fair Value Measurements
Fair Value Measurements | 6 Months Ended |
Jun. 30, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Fair Value Measurements The Company follows a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows: • Level 1: Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. • Level 2: Observable market-based inputs or unobservable inputs corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. • Level 3: Unobservable inputs not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value. A financial instrument’s categorization within the hierarchy is based upon the lowest level of input that is significant to the fair value measurement. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the hierarchy. As Level 1 inputs generally provide the most reliable evidence of fair value, the Company uses Level 1 inputs when available. The Company’s policy is to recognize transfers between the hierarchy levels as of the beginning of the reporting period in which the event or change in circumstances caused the transfer. Assets and Liabilities Measured at Fair Value on a Recurring Basis The Company's derivative instruments are reported at fair value on a recurring basis. In determining the fair values of swap contracts, a discounted cash flow method is used due to the unavailability of relevant comparable market data for the Company’s exact contracts. The discounted cash flow method estimates future cash flows based on quoted market prices for forward commodity prices and a risk-adjusted discount rate. The fair values of swap contracts are calculated mainly using significant observable inputs (Level 2). Calculation of the fair values of collars requires the use of an industry-standard option pricing model that considers various inputs including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. These assumptions are observable in the marketplace or can be corroborated by active markets or broker quotes and are therefore designated as Level 2 within the valuation hierarchy. The Company’s calculation of fair value for each of its derivative positions is compared to the counterparty valuation for reasonableness. The following tables summarize the valuation of financial instruments by pricing levels that were accounted for at fair value on a recurring basis as of June 30, 2018 and December 31, 2017 . Fair value measurements at June 30, 2018 using: In thousands Level 1 Level 2 Level 3 Total Derivative liabilities: Swaps $ — $ (8,862 ) $ — $ (8,862 ) Total $ — $ (8,862 ) $ — $ (8,862 ) Fair value measurements at December 31, 2017 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets: Swaps $ — $ 2,603 $ — $ 2,603 Total $ — $ 2,603 $ — $ 2,603 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. Risk-adjusted probable and possible reserves may be taken into consideration when determining estimated future net cash flows and fair value when such reserves exist and are economically recoverable. Due to the unavailability of relevant comparable market data, a discounted cash flow method is used to determine the fair value of proved properties. The discounted cash flow method estimates future cash flows based on the Company's estimates of future crude oil and natural gas production, commodity prices based on commodity futures price strips adjusted for differentials, operating costs, and a risk-adjusted discount rate. The fair value of proved crude oil and natural gas properties is calculated using significant unobservable inputs (Level 3). The following table sets forth quantitative information about the significant unobservable inputs used by the Company to calculate the fair value of proved crude oil and natural gas properties using a discounted cash flow method. Unobservable Input Assumption Future production Future production estimates for each property Forward commodity prices Forward NYMEX strip prices through 2022 (adjusted for differentials), escalating 3% per year thereafter Operating costs Estimated costs for the current year, escalating 3% per year thereafter Productive life of field Ranging from 1 to 38 years Discount rate 10% Unobservable inputs to the fair value assessment are reviewed quarterly and are revised as warranted based on a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Fair value measurements of proved properties are reviewed and approved by certain members of the Company’s management. For the three and six months ended June 30, 2018 , estimated future net cash flows were determined to be in excess of cost basis, therefore no impairment was recorded for the Company’s proved crude oil and natural gas properties for those periods. For the three and six months ended June 30, 2017 , the Company determined the carrying amounts of certain proved properties were not recoverable from future cash flows, and therefore, were impaired. Impairments of proved properties totaled $81.5 million and $82.3 million for the three and six months ended June 30, 2017 , respectively. The 2017 impairments reflected fair value adjustments primarily concentrated in the Arkoma Woodford field ( $81.2 million , all in the second quarter of 2017) and various non-core areas in the North and South regions ( $1.1 million , including $0.3 million in the second quarter of 2017). The impaired properties were written down to their estimated fair value at the time of impairment of approximately $72 million . Certain unproved crude oil and natural gas properties were impaired during the three and six months ended June 30, 2018 and 2017 , 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 June 30, Six months ended June 30, In thousands 2018 2017 2018 2017 Proved property impairments $ — $ 81,469 $ — $ 82,340 Unproved property impairments 29,162 41,847 62,946 92,349 Total $ 29,162 $ 123,316 $ 62,946 $ 174,689 Financial Instruments Not Recorded at Fair Value The following table sets forth the estimated fair values of financial instruments that are not recorded at fair value in the condensed consolidated financial statements. June 30, 2018 December 31, 2017 In thousands Carrying Estimated Fair Value Carrying Estimated Fair Value Debt: Revolving credit facility $ — $ — $ 188,000 $ 188,000 Note payable 8,845 8,800 9,974 9,900 5% Senior Notes due 2022 (1) 1,997,782 2,030,100 1,997,576 2,040,000 4.5% Senior Notes due 2023 1,487,803 1,522,900 1,486,690 1,526,800 3.8% Senior Notes due 2024 992,588 976,000 992,036 988,800 4.375% Senior Notes due 2028 988,090 994,100 988,061 987,200 4.9% Senior Notes due 2044 691,435 683,600 691,354 679,900 Total debt $ 6,166,543 $ 6,215,500 $ 6,353,691 $ 6,420,600 (1) As discussed in Note 12. Subsequent Events , on July 12, 2018 the Company announced it will redeem $400 million, or 20%, of its outstanding $2.0 billion of 5% Senior Notes due 2022 on August 16, 2018. The fair value of revolving credit facility borrowings at December 31, 2017 approximate carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and are classified as Level 2 in the fair value hierarchy. The fair value of the note payable is determined using a discounted cash flow approach based on the interest rate and payment terms of the note payable and an assumed discount rate. The fair value of the note payable is significantly influenced by the discount rate assumption, which is derived by the Company and is unobservable. Accordingly, the fair value of the note payable is classified as Level 3 in the fair value hierarchy. The fair values of the 5% Senior Notes due 2022 (“2022 Notes”), the 4.5% Senior Notes due 2023 (“2023 Notes”), the 3.8% Senior Notes due 2024 (“2024 Notes”), the 4.375% Senior Notes due 2028 (“2028 Notes”), and the 4.9% Senior Notes due 2044 (“2044 Notes”) are based on quoted market prices and, accordingly, are classified as Level 1 in the fair value hierarchy. The carrying values of all classes of cash and cash equivalents, trade receivables, and trade payables are considered to be representative of their respective fair values due to the short term maturities of those instruments. |
Long-Term Debt
Long-Term Debt | 6 Months Ended |
Jun. 30, 2018 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | Long-Term Debt Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $42.3 million and $44.3 million at June 30, 2018 and December 31, 2017 , respectively, consists of the following. In thousands June 30, 2018 December 31, 2017 Revolving credit facility $ — $ 188,000 Note payable 8,845 9,974 5% Senior Notes due 2022 (1) 1,997,782 1,997,576 4.5% Senior Notes due 2023 1,487,803 1,486,690 3.8% Senior Notes due 2024 992,588 992,036 4.375% Senior Notes due 2028 988,090 988,061 4.9% Senior Notes due 2044 691,435 691,354 Total debt $ 6,166,543 $ 6,353,691 Less: Current portion of long-term debt 2,322 2,286 Long-term debt, net of current portion $ 6,164,221 $ 6,351,405 (1) As discussed in Note 12. Subsequent Events , on July 12, 2018 the Company announced it will redeem $400 million, or 20%, of its outstanding $2.0 billion of 5% Senior Notes due 2022 on August 16, 2018. Revolving Credit Facility On April 9, 2018, the Company entered into a new unsecured revolving credit facility, maturing on April 9, 2023 , with aggregate lender commitments totaling $1.5 billion , which may be increased up to a total of $4.0 billion upon agreement between the Company and participating lenders. In connection with the execution of the new credit facility, the Company terminated its then-existing $2.75 billion credit facility that was due to mature in May 2019. The Company had no outstanding borrowings on its credit facility at June 30, 2018 . Borrowings under the credit facility, if any, 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 Company incurs commitment fees based on currently assigned credit ratings of 0.20% per annum on the daily average amount of unused borrowing availability under its credit facility. The Company's new credit facility retains substantially the same restrictive covenants as the previous credit facility, 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 credit facility covenants at June 30, 2018 . Senior Notes The following table summarizes the face values, maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding senior note obligations at June 30, 2018 . 2022 Notes (1) 2023 Notes 2024 Notes 2028 Notes 2044 Notes Face value (in thousands) $2,000,000 $1,500,000 $1,000,000 $1,000,000 $700,000 Maturity date Sep 15, 2022 April 15, 2023 June 1, 2024 January 15, 2028 June 1, 2044 Interest payment dates March 15, Sep 15 April 15, Oct 15 June 1, Dec 1 Jan 15, July 15 June 1, Dec 1 Make-whole redemption period (2) — Jan 15, 2023 Mar 1, 2024 Oct 15, 2027 Dec 1, 2043 (1) The Company has the option to redeem all or a portion of its 2022 Notes at the decreasing redemption prices specified in the indenture related to the 2022 Notes plus any accrued and unpaid interest to the date of redemption. See Note 12. Subsequent Events . (2) At any time prior to the indicated dates, the Company has the option to redeem all or a portion of its senior notes of the applicable series at the “make-whole” redemption prices or amounts specified in the respective senior note indentures plus any accrued and unpaid interest to the date of redemption. On or after the indicated dates, the Company may redeem all or a portion of its senior notes at a redemption price equal to 100% of the principal amount of the senior notes being redeemed plus any accrued and unpaid interest to the date of redemption. The Company’s senior notes are not subject to any mandatory redemption or sinking fund requirements. The indentures governing the Company’s senior notes contain covenants that, among other things, limit the Company’s ability to create liens securing certain indebtedness, enter into certain sale-leaseback transactions, or consolidate, merge or transfer certain assets. The senior note covenants are subject to a number of important exceptions and qualifications. The Company was in compliance with these covenants at June 30, 2018 . 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. Note Payable In February 2012, 20 Broadway Associates LLC, a 100% owned subsidiary of the Company, borrowed $22 million under a 10 -year amortizing term loan secured by the Company’s corporate office building in Oklahoma City, Oklahoma. The loan bears interest at a fixed rate of 3.14% per annum. Principal and interest are payable monthly through the loan’s maturity date of February 26, 2022 . Accordingly, approximately $2.3 million is reflected as a current liability under the caption “Current portion of long-term debt” in the condensed consolidated balance sheets as of June 30, 2018 . |
Commitments and Contingencies
Commitments and Contingencies | 6 Months Ended |
Jun. 30, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Included below is a discussion of various future commitments of the Company as of June 30, 2018 . The commitments under these arrangements are not recorded in the accompanying condensed consolidated balance sheets. Drilling commitments – As of June 30, 2018 , the Company has drilling rig contracts with various terms extending to June 2021 to ensure rig availability in its key operating areas. Future commitments as of June 30, 2018 total approximately $97 million , of which $42 million is expected to be incurred in the remainder of 2018 , $41 million in 2019 , $10 million in 2020 , and $4 million in 2021 . Transportation and processing commitments – The Company has entered into transportation and processing commitments to guarantee capacity on crude oil and natural gas pipelines and natural gas processing facilities. The commitments, which have varying terms extending as far as 2028, require the Company to pay per-unit transportation or processing charges regardless of the amount of capacity used. Future commitments remaining as of June 30, 2018 under the arrangements amount to approximately $1.36 billion , of which $112 million is expected to be incurred in the remainder of 2018 , $225 million in 2019 , $194 million in 2020 , $175 million in 2021 , $168 million in 2022, and $487 million thereafter. The Company is not committed under the above contracts to deliver fixed and determinable quantities of crude oil or natural gas in the future. Litigation – In November 2010, a putative class action was filed in the District Court of Blaine County, Oklahoma by Billy J. Strack and Daniela A. Renner as trustees of certain named trusts and on behalf of other similarly situated parties against the Company. The Petition, as amended, alleged the Company improperly deducted post-production costs from royalties paid to plaintiffs and other royalty interest owners from crude oil and natural gas wells located in Oklahoma. The plaintiffs alleged a number of claims, including breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and sought recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the proposed class. The Company denied all allegations and denied that the case was properly brought as a class action. On June 11, 2015, the trial court certified a “hybrid” class requested by plaintiffs over the objections of the Company. The Company appealed the trial court’s class certification order. On February 8, 2017, the Oklahoma Court of Civil Appeals reversed the trial court’s ruling on certification and remanded the case for further proceedings. The plaintiffs filed a Petition for Rehearing which was denied by the Oklahoma Court of Civil Appeals. Plaintiffs then filed a Petition for Writ of Certiorari on May 23, 2017 to the Oklahoma Supreme Court, which was denied on October 2, 2017. On October 10, 2017, Plaintiffs filed with the trial court a “Second Amended and Renewed Motion for Class Action Certification and Request that the Court to Set a Briefing Schedule Related to Class Certification.” During the litigation the Company was not able to estimate a reasonably possible loss or range of loss or what impact, if any, the ultimate resolution of the action would have on its financial condition, results of operations or cash flows due to the preliminary status of the matter, the complexity and number of legal and factual issues presented by the matter and uncertainties with respect to, among other things, the nature of the claims and defenses, the existence and the potential size of the class, the scope and types of the properties and agreements involved, the production years involved, and the ultimate potential outcome of the matter. The Company further disclosed that it was reasonably possible one or more events could occur in the near term that could impact the Company’s ability to estimate the potential effect of this matter if any, on its financial condition, results of operations or cash flows. During the litigation the Company also disclosed plaintiffs alleged underpayments in excess of $200 million as damages, which may increase with the passage of time, a majority of which would be comprised of interest. After certification of the case as a class action was reversed the parties continued settlement negotiations. Due to the uncertainty of and burdens of litigation, on February 16, 2018, the Company reached a settlement in connection with this matter. Under the settlement, the Company initially expected to make payments and incur costs associated with the settlement of approximately $59.6 million . The Company accrued a loss for such amount at December 31, 2017, which was subsequently increased to $61.7 million at June 30, 2018 to reflect additional settlement obligations resulting from the passage of time. Such accrual is included in “Accrued liabilities and other” on the condensed consolidated balance sheets. On April 3, 2018, the District Court of Garfield County, Oklahoma preliminarily approved the settlement and set certain dates applicable to the settlement including the timing and content of Notice, Opt-out, and Objections to Class Members. The Fairness Hearing was held on June 11, 2018. On June 12, 2018, the court entered an order formally approving the settlement. The order approving the settlement is not subject to appeal. On June 20, 2018, the court entered an order approving Plaintiff Counsels’ request for Attorney Fees and Expenses. The deadline for an appeal of the order approving Attorney Fees and Expenses is August 13, 2018. In accordance with the settlement terms, the Company expects to make payments totaling approximately $50 million in the third quarter of 2018 and expects to satisfy the remainder of its settlement obligations in 2019. 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. In addition to the accrued loss on the matter described above, as of June 30, 2018 and December 31, 2017 the Company recorded a liability in the condensed consolidated balance sheets under the caption “Other noncurrent liabilities” of $4.7 million and $7.6 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 | 6 Months Ended |
Jun. 30, 2018 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Stock-Based Compensation | Stock-Based Compensation The Company has granted restricted stock to employees and directors pursuant to the Continental Resources, Inc. 2013 Long-Term Incentive Plan ("2013 Plan") as discussed below. The Company’s associated compensation expense, which is included in the caption “General and administrative expenses” in the unaudited condensed consolidated statements of comprehensive income (loss), was $10.6 million and $9.1 million for the three months ended June 30, 2018 and 2017 , respectively, and $21.5 million and $20.6 million for the six months ended June 30, 2018 and 2017 , respectively. In May 2013, the Company adopted the 2013 Plan and reserved 19,680,072 shares of common stock that may be issued pursuant to the plan. As of June 30, 2018 , the Company had 13,727,512 shares of common stock available for long-term incentive awards to employees and directors under the 2013 Plan. Restricted stock is awarded in the name of the recipient and constitutes issued and outstanding shares of the Company’s common stock for all corporate purposes during the period of restriction and, except as otherwise provided under the 2013 Plan or agreement relevant to a given award, includes the right to vote the restricted stock and to receive dividends, subject to forfeiture. Restricted stock grants generally vest over periods ranging from one to three years. A summary of changes in non-vested restricted shares outstanding for the six months ended June 30, 2018 is presented below. Number of Weighted average Non-vested restricted shares outstanding at December 31, 2017 4,026,110 $ 35.63 Granted 1,277,491 52.47 Vested (1,041,748 ) 47.10 Forfeited (178,957 ) 37.27 Non-vested restricted shares outstanding at June 30, 2018 4,082,896 $ 37.90 The grant date fair value of restricted stock represents the closing market price of the Company’s common stock on the date of grant. Compensation expense for a restricted stock grant is determined at the grant date fair value and is recognized over the vesting period as services are rendered by employees and directors. The Company estimates the number of forfeitures expected to occur in determining the amount of stock-based compensation expense to recognize. There are no post-vesting restrictions related to the Company’s restricted stock. The fair value at the vesting date of restricted stock that vested during the six months ended June 30, 2018 was approximately $57.0 million . As of June 30, 2018 , there was approximately $94 million of unrecognized compensation expense related to non-vested restricted stock. This expense is expected to be recognized over a weighted average period of 1.5 years. |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Income (Notes) | 6 Months Ended |
Jun. 30, 2018 | |
Accumulated Other Comprehensive Income [Abstract] | |
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block] | Accumulated Other Comprehensive Income (Loss) Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in “Accumulated other comprehensive income (loss)” within shareholders’ equity in the condensed consolidated balance sheets and “Other comprehensive income, net of tax” in the unaudited condensed consolidated statements of comprehensive income (loss). The following table summarizes the change in accumulated other comprehensive income (loss) for the three and six months ended June 30, 2018 and 2017 : Three months ended June 30, Six months ended June 30, In thousands 2018 2017 2018 2017 Beginning accumulated other comprehensive income (loss), net of tax $ 309 $ (122 ) $ 307 $ (260 ) Foreign currency translation adjustments 16 189 18 327 Income taxes (1) — — — — Other comprehensive income, net of tax 16 189 18 327 Ending accumulated other comprehensive income, net of tax $ 325 $ 67 $ 325 $ 67 (1) A valuation allowance has been recognized against all deferred tax assets associated with losses generated by the Company's Canadian operations, thereby resulting in no income taxes on other comprehensive income. |
Income Taxes (Notes)
Income Taxes (Notes) | 6 Months Ended |
Jun. 30, 2018 | |
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 ($75.2) million and $37.9 million for the three months ended June 30, 2018 and 2017, respectively. The Company's (provision) benefit for income taxes totaled ($146.8) million and $31.8 million for the six months ended June 30, 2018 and 2017, respectively. These amounts differ from the amounts computed by applying the United States statutory federal income tax rate to net income before income taxes. The sources and tax effects of the differences are reflected in the table below: Three months ended June 30, Six months ended June 30, $ in thousands 2018 Tax rate % 2017 Tax rate % 2018 Tax rate % 2017 Tax rate % Expected income tax (provision) benefit based on US statutory tax rate (1) $ (66,716 ) 21 % $ 35,494 35 % $ (130,867 ) 21 % $ 33,222 35 % State income taxes, net of federal benefit (9,531 ) 3 % 3,043 3 % (18,695 ) 3 % 2,848 3 % Tax benefit (deficiency) from stock-based compensation 359 — % (473 ) (1 %) 1,868 — % (3,773 ) (4 %) Canadian valuation allowance (2) (78 ) — % (112 ) — % (148 ) — % (257 ) — % Other, net 734 — % (97 ) — % 1,074 — % (207 ) — % (Provision) benefit for income taxes $ (75,232 ) 24 % $ 37,855 37 % $ (146,768 ) 24 % $ 31,833 34 % (1) In December 2017 the Tax Cuts and Jobs Act was signed into law, which among other things reduced the U.S. federal corporate income tax rate from 35% to 21% effective January 1, 2018. (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. |
Subsequent Events (Notes)
Subsequent Events (Notes) | 6 Months Ended |
Jun. 30, 2018 | |
Subsequent Events [Abstract] | |
Subsequent Events [Text Block] | Subsequent Events Partial redemption of senior notes On July 12, 2018, the Company announced it will redeem $400 million , or 20%, of its outstanding $2.0 billion of 5% Senior Notes due 2022 on August 16, 2018. The redemption price will be equal to 101.667% of the principal amount called for redemption plus accrued and unpaid interest to the redemption date in accordance with the terms of the 2022 Notes and the related indenture under which the 2022 Notes were issued. The aggregate of the principal amount, redemption premium, and accrued interest payable upon partial redemption of the 2022 Notes is expected to total approximately $415 million . The Company expects to record a pre-tax loss on extinguishment of debt related to the partial redemption of approximately $7 million , which will be reflected in third quarter 2018 results. Formation of strategic relationship On August 6, 2018, the Company executed definitive documents to form a strategic relationship with Franco-Nevada, subject to customary closing conditions, to acquire minerals in the SCOOP and STACK plays, primarily in areas operated by the Company. In accordance with the deal terms, Franco-Nevada has agreed to pay approximately $220 million for a stake in a newly-formed minerals subsidiary. The Company expects to receive the proceeds at closing in the fourth quarter of 2018. The amount to be received by the Company is subject to adjustment under the terms of the transaction documents. In addition, the parties have also committed, subject to satisfaction of agreed upon development thresholds, to spend up to a combined $125 million per year over the next three years to acquire additional minerals through the newly-formed subsidiary. With a carry component on capital acquisition costs, the Company is to fund 20% of future mineral acquisitions. The Company will be entitled to receive between 25% and 50% of total revenues generated by the minerals subsidiary based upon performance relative to certain predetermined targets. |
Basis of Presentation and Sig19
Basis of Presentation and Significant Accounting Policies (Policies) | 6 Months Ended |
Jun. 30, 2018 | |
Accounting Policies [Abstract] | |
Description of the Company | Continental Resources, Inc. (the “Company”) was originally formed in 1967 and is incorporated under the laws of the State of Oklahoma. The Company's principal business is crude oil and natural gas exploration, development and production with properties primarily located in the North, South, and East regions of the United States. The North region consists of properties north of Kansas and west of the Mississippi River and includes North Dakota Bakken, Montana Bakken and the Red River units. The South region includes all properties south of Nebraska and west of the Mississippi River including various plays in the SCOOP and STACK 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 59% of the Company’s crude oil and natural gas production and 74% of its crude oil and natural gas revenues for the six months ended June 30, 2018 . 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 41% of the Company's crude oil and natural gas production and 26% of its crude oil and natural gas revenues for the six months ended June 30, 2018 . For the six months ended June 30, 2018 , crude oil accounted for 56% of the Company’s total production and 82% 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, 2017 (“ 2017 Form 10-K”), which includes a summary of the Company’s significant accounting policies and other disclosures. The condensed consolidated financial statements as of June 30, 2018 and for the three and six month periods ended June 30, 2018 and 2017 are unaudited. The condensed consolidated balance sheet as of December 31, 2017 was derived from the audited balance sheet included in the 2017 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 estimates and assumptions impacting reported results are estimates of the Company’s crude oil and natural gas reserves, which are used to compute depreciation, depletion, amortization and impairment of proved crude oil and natural gas properties. 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, pipeline imbalances, and tubular goods and equipment to be used in the Company's exploration and development activities. Crude oil inventories are valued at the lower of cost or market primarily using the first-in, first-out inventory method. Tubular goods and equipment are valued primarily using a weighted average cost method applied to specific classes of inventory items. |
New Accounting Pronouncements | Adoption of new accounting pronouncements Revenue recognition and presentation – In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers (Topic 606) , which supersedes nearly all previously existing revenue recognition guidance under U.S. GAAP. Subsequently, the FASB issued additional guidance to assist entities with implementation efforts, including the issuance of ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). This new guidance became effective for reporting periods beginning after December 15, 2017. The Company adopted the new revenue recognition and presentation guidance on January 1, 2018 as required. See Note 4. Revenues for discussion of the adoption impact and the applicable disclosures required by the new guidance. 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. The Company plans to adopt the new standard using the simplified transition method prescribed by ASU 2018-11, Leases (Topic 842): Targeted Improvements , whereby the Company will initially apply the new standard as of the January 1, 2019 adoption date and will recognize a cumulative-effect adjustment to the opening balance of retained earnings, if any, upon adoption in lieu of retrospectively applying the new standard to pre-adoption periods. The Company continues to evaluate the impact of ASU 2016-02 on its financial statements, accounting policies and internal controls and is in the process of implementing systems and processes to capture, classify, and account for leases within the scope of the new guidance and to comply with the related disclosure requirements. Interpretations and application of the new guidance continue to evolve and are being monitored for applicability and impact on the Company. Based on an initial review of the new guidance and the Company’s current commitments, the Company anticipates it will be required to recognize lease assets and liabilities related to drilling rig commitments, certain equipment rentals and leases, certain surface use agreements, and potentially other arrangements. The Company does not believe any of its firm transportation agreements will qualify as leases, but continues to evaluate such arrangements. Based on commitments in place as of June 30, 2018 , the Company currently estimates its lease assets and liabilities to be recognized under ASU 2016-02 will total approximately $100 million , the majority of which will be comprised of future cash flows associated with drilling rig commitments, which are further discussed in Note 8. Commitments and Contingencies–Drilling commitments . This estimate may be subsequently revised based on unforeseen changes in the nature, timing, and extent of the Company's contractual arrangements from period to period, finalization of the Company's evaluation of its firm transportation agreements, or due to changes in the Company's interpretation or application of the new guidance. Credit losses – In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments . This standard changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. The standard is effective for interim and annual periods beginning after December 15, 2019 and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. The Company continues to evaluate the new standard and is unable to estimate its financial statement impact at this time; however, the impact is not expected to be material. Historically, the Company's credit losses on crude oil and natural gas sales receivables and joint interest receivables have been immaterial. |
Basis of Presentation and Sig20
Basis of Presentation and Significant Accounting Policies (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Accounting Policies [Abstract] | |
Components of Inventories | The components of inventory as of June 30, 2018 and December 31, 2017 consisted of the following: In thousands June 30, 2018 December 31, 2017 Tubular goods and equipment $ 18,722 $ 14,946 Crude oil 96,588 82,460 Total $ 115,310 $ 97,406 |
Calculation of Basic and Diluted Weighted Average Shares and Net Income Per Share | The following table presents the calculation of basic and diluted weighted average shares outstanding and net income (loss) per share for the three and six months ended June 30, 2018 and 2017 . Three months ended June 30, Six months ended June 30, In thousands, except per share data 2018 2017 2018 2017 Net income (loss) (numerator) $ 242,464 $ (63,557 ) $ 476,410 $ (63,088 ) Weighted average shares (denominator): Weighted average shares - basic 371,921 371,111 371,733 370,972 Non-vested restricted stock (1) 2,584 — 2,850 — Weighted average shares - diluted 374,505 371,111 374,583 370,972 Net income (loss) per share: Basic $ 0.65 $ (0.17 ) $ 1.28 $ (0.17 ) Diluted $ 0.65 $ (0.17 ) $ 1.27 $ (0.17 ) |
Supplemental Cash Flow Inform21
Supplemental Cash Flow Information (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Supplemental Cash Flow Elements [Abstract] | |
Summary of Supplemental Cash Flow Information | The following table discloses supplemental cash flow information about cash paid for interest and income tax payments and refunds. Also disclosed is information about investing activities that affects recognized assets and liabilities but does not result in cash receipts or payments. Six months ended June 30, In thousands 2018 2017 Supplemental cash flow information: Cash paid for interest $ 122,940 $ 138,346 Cash paid for income taxes — 2 Cash received for income tax refunds 5 148 Non-cash investing activities: Asset retirement obligation additions and revisions, net 3,562 3,771 As of June 30, 2018 and December 31, 2017 , the Company had $317.5 million and $302.8 million , respectively, of accrued capital expenditures included in “Net property and equipment” and “Accounts payable trade” in the condensed consolidated balance sheets. |
Revenues (Tables)
Revenues (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Schedule of Prospective Adoption of New Accounting Pronouncements [Table Text Block] | The following table reflects the change in presentation of revenues and applicable expenses on the Company's 2018 results under the new and previous guidance. Three months ended June 30, 2018 Six months ended June 30, 2018 In thousands New Standard Prior Presentation Change New Standard Prior Presentation Change Revenues: Crude oil and natural gas sales $ 1,137,528 $ 1,090,274 $ 47,254 $ 2,251,380 $ 2,154,829 $ 96,551 Loss on natural gas derivatives, net (12,685 ) (12,685 ) — (2,511 ) (2,511 ) — Crude oil and natural gas service operations 12,270 12,270 — 29,272 29,272 — Total revenues $ 1,137,113 $ 1,089,859 $ 47,254 $ 2,278,141 $ 2,181,590 $ 96,551 Operating costs and expenses: Transportation expenses $ 47,254 $ — $ 47,254 $ 96,551 $ — $ 96,551 Net income $ 242,464 $ 242,464 $ — $ 476,410 $ 476,410 $ — |
Disaggregation of Revenue [Table Text Block] | The following table presents the disaggregation of the Company's crude oil and natural gas revenues for the three and six months ended June 30, 2018 . Three months ended June 30, 2018 Six months ended June 30, 2018 In thousands North Region South Region Total North Region South Region Total Crude oil revenues: Operated properties $ 587,582 $ 145,603 $ 733,185 $ 1,156,794 $ 284,056 $ 1,440,850 Non-operated properties 196,301 17,398 213,699 379,188 33,127 412,315 Total crude oil revenues 783,883 163,001 946,884 1,535,982 317,183 1,853,165 Natural gas revenues: Operated properties 41,425 121,188 162,613 93,245 248,442 341,687 Non-operated properties 13,982 14,049 28,031 27,661 28,867 56,528 Total natural gas revenues 55,407 135,237 190,644 120,906 277,309 398,215 Crude oil and natural gas sales $ 839,290 $ 298,238 $ 1,137,528 $ 1,656,888 $ 594,492 $ 2,251,380 Timing of revenue recognition Goods transferred at a point in time $ 839,290 $ 298,238 $ 1,137,528 $ 1,656,888 $ 594,492 $ 2,251,380 Goods transferred over time — — — — — — $ 839,290 $ 298,238 $ 1,137,528 $ 1,656,888 $ 594,492 $ 2,251,380 |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Summary of Outstanding Contracts with Respect to Natural Gas | At June 30, 2018 the Company had outstanding natural gas derivative contracts as set forth in the table below. The volumes reflected below represent an aggregation of multiple derivative contracts having similar remaining durations expected to be realized ratably over the remainder of 2018. At June 30, 2018 the Company had no outstanding crude oil derivative contracts. Swaps Weighted Average Price Period and Type of Contract MMBtus July 2018 - December 2018 Swaps - Henry Hub 115,920,000 $ 2.88 |
Realized and Unrealized Gains and Losses on Derivative Instruments | Cash receipts and payments in the following table reflect the gain or loss on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price of matured contracts. Non-cash gains and losses below represent the change in fair value of derivative instruments which continue to be held at period end and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period. Three months ended June 30, Six months ended June 30, In thousands 2018 2017 2018 2017 Cash received (paid) on derivatives: Natural gas fixed price swaps $ 4,758 $ 6,709 $ 8,954 $ 12,187 Natural gas collars — (3,050 ) — (9,456 ) Cash received (paid) on derivatives, net 4,758 3,659 8,954 2,731 Non-cash gain (loss) on derivatives: Natural gas fixed price swaps (17,443 ) 12,520 (11,465 ) 35,416 Natural gas collars — 11,843 — 36,733 Non-cash gain (loss) on derivatives, net (17,443 ) 24,363 (11,465 ) 72,149 Gain (loss) on natural gas derivatives, net $ (12,685 ) $ 28,022 $ (2,511 ) $ 74,880 |
Gross Amounts of Recognized Derivative Assets and Liabilities | The following table presents the gross amounts of recognized natural gas and diesel fuel derivative assets and liabilities, as applicable, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the condensed consolidated balance sheets for the periods presented, all at fair value. In thousands June 30, 2018 December 31, 2017 Commodity derivative assets: Gross amounts of recognized assets $ 885 $ 2,603 Gross amounts offset on balance sheet (682 ) — Net amounts of assets on balance sheet 203 2,603 Commodity derivative liabilities: Gross amounts of recognized liabilities (9,747 ) — Gross amounts offset on balance sheet 682 — Net amounts of liabilities on balance sheet $ (9,065 ) $ — |
Reconciles Net Amounts Derivative Assets and Liabilities | The following table reconciles the net amounts disclosed above to the individual financial statement line items in the condensed consolidated balance sheets. In thousands June 30, 2018 December 31, 2017 Derivative assets $ 203 $ 2,603 Noncurrent derivative assets — — Net amounts of assets on balance sheet 203 2,603 Derivative liabilities (9,065 ) — Noncurrent derivative liabilities — — Net amounts of liabilities on balance sheet (9,065 ) — Total derivative assets (liabilities), net $ (8,862 ) $ 2,603 |
Diesel Fuel [Member] | |
Realized and Unrealized Gains and Losses on Derivative Instruments | Cash receipts in the following table reflect gains on diesel fuel derivatives which matured during the 2017 period, calculated as the difference between the contract price and the market settlement price of matured contracts. Non-cash losses below represent the change in fair value of diesel fuel derivatives held at June 30, 2017 and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the three and six months ended June 30, 2017 . Three months ended June 30, Six months ended June 30, In thousands 2018 2017 2018 2017 Cash received on diesel fuel derivatives $ — $ 185 $ — $ 919 Non-cash loss on diesel fuel derivatives — (1,098 ) — (3,729 ) Loss on diesel fuel derivatives, net $ — $ (913 ) $ — $ (2,810 ) |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Fair Value Disclosures [Abstract] | |
Valuation of Financial Instruments by Pricing Levels | The following tables summarize the valuation of financial instruments by pricing levels that were accounted for at fair value on a recurring basis as of June 30, 2018 and December 31, 2017 . Fair value measurements at June 30, 2018 using: In thousands Level 1 Level 2 Level 3 Total Derivative liabilities: Swaps $ — $ (8,862 ) $ — $ (8,862 ) Total $ — $ (8,862 ) $ — $ (8,862 ) Fair value measurements at December 31, 2017 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets: Swaps $ — $ 2,603 $ — $ 2,603 Total $ — $ 2,603 $ — $ 2,603 |
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 2022 (adjusted for differentials), escalating 3% per year thereafter Operating costs Estimated costs for the current year, escalating 3% per year thereafter Productive life of field Ranging from 1 to 38 years Discount rate 10% |
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 June 30, Six months ended June 30, In thousands 2018 2017 2018 2017 Proved property impairments $ — $ 81,469 $ — $ 82,340 Unproved property impairments 29,162 41,847 62,946 92,349 Total $ 29,162 $ 123,316 $ 62,946 $ 174,689 |
Fair Values of Financial Instruments not Recorded at Fair Value | The following table sets forth the estimated fair values of financial instruments that are not recorded at fair value in the condensed consolidated financial statements. June 30, 2018 December 31, 2017 In thousands Carrying Estimated Fair Value Carrying Estimated Fair Value Debt: Revolving credit facility $ — $ — $ 188,000 $ 188,000 Note payable 8,845 8,800 9,974 9,900 5% Senior Notes due 2022 (1) 1,997,782 2,030,100 1,997,576 2,040,000 4.5% Senior Notes due 2023 1,487,803 1,522,900 1,486,690 1,526,800 3.8% Senior Notes due 2024 992,588 976,000 992,036 988,800 4.375% Senior Notes due 2028 988,090 994,100 988,061 987,200 4.9% Senior Notes due 2044 691,435 683,600 691,354 679,900 Total debt $ 6,166,543 $ 6,215,500 $ 6,353,691 $ 6,420,600 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Debt Disclosure [Abstract] | |
Summary of Maturity Dates, Semi-Annual Interest Payment Dates, and Optional Redemption Periods of Outstanding Senior Note Obligations | The following table summarizes the face values, maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding senior note obligations at June 30, 2018 . 2022 Notes (1) 2023 Notes 2024 Notes 2028 Notes 2044 Notes Face value (in thousands) $2,000,000 $1,500,000 $1,000,000 $1,000,000 $700,000 Maturity date Sep 15, 2022 April 15, 2023 June 1, 2024 January 15, 2028 June 1, 2044 Interest payment dates March 15, Sep 15 April 15, Oct 15 June 1, Dec 1 Jan 15, July 15 June 1, Dec 1 Make-whole redemption period (2) — Jan 15, 2023 Mar 1, 2024 Oct 15, 2027 Dec 1, 2043 (1) The Company has the option to redeem all or a portion of its 2022 Notes at the decreasing redemption prices specified in the indenture related to the 2022 Notes plus any accrued and unpaid interest to the date of redemption. See Note 12. Subsequent Events . (2) At any time prior to the indicated dates, the Company has the option to redeem all or a portion of its senior notes of the applicable series at the “make-whole” redemption prices or amounts specified in the respective senior note indentures plus any accrued and unpaid interest to the date of redemption. On or after the indicated 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 $42.3 million and $44.3 million at June 30, 2018 and December 31, 2017 , respectively, consists of the following. In thousands June 30, 2018 December 31, 2017 Revolving credit facility $ — $ 188,000 Note payable 8,845 9,974 5% Senior Notes due 2022 (1) 1,997,782 1,997,576 4.5% Senior Notes due 2023 1,487,803 1,486,690 3.8% Senior Notes due 2024 992,588 992,036 4.375% Senior Notes due 2028 988,090 988,061 4.9% Senior Notes due 2044 691,435 691,354 Total debt $ 6,166,543 $ 6,353,691 Less: Current portion of long-term debt 2,322 2,286 Long-term debt, net of current portion $ 6,164,221 $ 6,351,405 |
Stock-Based Compensation (Table
Stock-Based Compensation (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Restricted stock [Member] | |
Summary of Changes in Non-vested Shares of Restricted Stock Outstanding | A summary of changes in non-vested restricted shares outstanding for the six months ended June 30, 2018 is presented below. Number of Weighted average Non-vested restricted shares outstanding at December 31, 2017 4,026,110 $ 35.63 Granted 1,277,491 52.47 Vested (1,041,748 ) 47.10 Forfeited (178,957 ) 37.27 Non-vested restricted shares outstanding at June 30, 2018 4,082,896 $ 37.90 |
Accumulated Other Comprehensi27
Accumulated Other Comprehensive Income (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Accumulated Other Comprehensive Income [Abstract] | |
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block] | The following table summarizes the change in accumulated other comprehensive income (loss) for the three and six months ended June 30, 2018 and 2017 : Three months ended June 30, Six months ended June 30, In thousands 2018 2017 2018 2017 Beginning accumulated other comprehensive income (loss), net of tax $ 309 $ (122 ) $ 307 $ (260 ) Foreign currency translation adjustments 16 189 18 327 Income taxes (1) — — — — Other comprehensive income, net of tax 16 189 18 327 Ending accumulated other comprehensive income, net of tax $ 325 $ 67 $ 325 $ 67 (1) A valuation allowance has been recognized against all deferred tax assets associated with losses generated by the Company's Canadian operations, thereby resulting in no income taxes on other comprehensive income. |
Income Taxes (Tables)
Income Taxes (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Effective Tax Rate Reconciliation Table [Abstract] | |
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block] | The sources and tax effects of the differences are reflected in the table below: Three months ended June 30, Six months ended June 30, $ in thousands 2018 Tax rate % 2017 Tax rate % 2018 Tax rate % 2017 Tax rate % Expected income tax (provision) benefit based on US statutory tax rate (1) $ (66,716 ) 21 % $ 35,494 35 % $ (130,867 ) 21 % $ 33,222 35 % State income taxes, net of federal benefit (9,531 ) 3 % 3,043 3 % (18,695 ) 3 % 2,848 3 % Tax benefit (deficiency) from stock-based compensation 359 — % (473 ) (1 %) 1,868 — % (3,773 ) (4 %) Canadian valuation allowance (2) (78 ) — % (112 ) — % (148 ) — % (257 ) — % Other, net 734 — % (97 ) — % 1,074 — % (207 ) — % (Provision) benefit for income taxes $ (75,232 ) 24 % $ 37,855 37 % $ (146,768 ) 24 % $ 31,833 34 % (1) In December 2017 the Tax Cuts and Jobs Act was signed into law, which among other things reduced the U.S. federal corporate income tax rate from 35% to 21% effective January 1, 2018. (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 Bu29
Organization and Nature of Business - Additional Information (Detail) | 6 Months Ended |
Jun. 30, 2018 | |
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 | 82.00% |
North Region [Member] | |
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | |
Percentage of operations concentrated in geographic areas | 59.00% |
Percentage of revenues concentrated in geographic areas | 74.00% |
South Region [Member] | |
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | |
Percentage of operations concentrated in geographic areas | 41.00% |
Percentage of revenues concentrated in geographic areas | 26.00% |
Basis of Presentation and Sig30
Basis of Presentation and Significant Accounting Policies - Components of Inventories (Detail) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Accounting Policies [Abstract] | ||
Tubular goods and equipment | $ 18,722 | $ 14,946 |
Crude oil | 96,588 | 82,460 |
Total | $ 115,310 | $ 97,406 |
Basis of Presentation and Sig31
Basis of Presentation and Significant Accounting Policies - Earnings Per Share (Detail) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 6 Months Ended | ||||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |||
Accounting Policies [Abstract] | ||||||
Weighted Average Number Diluted Shares Outstanding Adjustment | 1,933,200 | 2,546,200 | ||||
Net income (loss) (numerator) | ||||||
Net income (loss) (numerator) | $ 242,464 | $ (63,557) | $ 476,410 | $ (63,088) | ||
Weighted average shares - basic | 371,921,000 | 371,111,000 | 371,733,000 | 370,972,000 | ||
Non-vested restricted stock (1) | 2,584,000 | 0 | [1] | 2,850,000 | 0 | [1] |
Weighted average shares - diluted | 374,505,000 | 371,111,000 | 374,583,000 | 370,972,000 | ||
Net income (loss) per share: | ||||||
Basic (in dollars per share) | $ 0.65 | $ (0.17) | $ 1.28 | $ (0.17) | ||
Diluted (in dollars per share) | $ 0.65 | $ (0.17) | $ 1.27 | $ (0.17) | ||
[1] | For the three and six months ended June 30, 2017, the Company had a net loss and therefore the potential dilutive effect of approximately 1,933,200 and 2,546,200 weighted average non-vested restricted shares, respectively, were not included in the calculation of diluted net loss per share because to do so would have been anti-dilutive to the computations for those periods. |
Basis of Presentation and Sig32
Basis of Presentation and Significant Accounting Policies Basis of Presentation and Significant Accounting Policies - New Accounting Pronouncements (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Accounting Policies [Abstract] | ||||
Estimated lease assets and liabilities | $ 100,000 | $ 100,000 | ||
Transportation expenses | $ 47,254 | $ 0 | $ 96,551 | $ 0 |
Supplemental Cash Flow Inform33
Supplemental Cash Flow Information - Summary of Supplemental Cash Flow Information (Detail) - USD ($) $ in Thousands | 6 Months Ended | 12 Months Ended | |
Jun. 30, 2018 | Jun. 30, 2017 | Dec. 31, 2017 | |
Supplemental Cash Flow Elements [Abstract] | |||
Cash paid for interest | $ 122,940 | $ 138,346 | |
Cash paid for income taxes | 0 | 2 | |
Cash received for income tax refunds | 5 | 148 | |
Noncash Investing and Financing Items [Abstract] | |||
Accrued capital expenditures | 317,500 | $ 302,800 | |
Increase (Decrease) in Asset Retirement Obligations | $ 3,562 | $ 3,771 |
Revenues (Details)
Revenues (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | ||||
Crude oil and natural gas sales | $ 1,137,528 | $ 626,548 | $ 2,251,380 | $ 1,260,398 |
Gain (loss) on natural gas derivatives, net | (12,685) | 28,022 | (2,511) | 74,880 |
Crude oil and natural gas service operations | 12,270 | 6,916 | 29,272 | 11,636 |
Total revenues | 1,137,113 | 661,486 | 2,278,141 | 1,346,914 |
Transportation expenses | 47,254 | 0 | 96,551 | 0 |
Net income | 242,464 | $ (63,557) | 476,410 | $ (63,088) |
Previous Revenue Recognition | ||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | ||||
Crude oil and natural gas sales | 1,090,274 | 2,154,829 | ||
Gain (loss) on natural gas derivatives, net | (12,685) | (2,511) | ||
Crude oil and natural gas service operations | 12,270 | 29,272 | ||
Total revenues | 1,089,859 | 2,181,590 | ||
Transportation expenses | 0 | 0 | ||
Net income | 242,464 | 476,410 | ||
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | ||||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | ||||
Crude oil and natural gas sales | 47,254 | 96,551 | ||
Gain (loss) on natural gas derivatives, net | 0 | 0 | ||
Crude oil and natural gas service operations | 0 | 0 | ||
Total revenues | 47,254 | 96,551 | ||
Transportation expenses | 47,254 | 96,551 | ||
Net income | $ 0 | $ 0 |
Revenues Disaggregation of Reve
Revenues Disaggregation of Revenue (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Disaggregation of Revenue [Line Items] | ||||
Crude oil and natural gas sales | $ 1,137,528 | $ 626,548 | $ 2,251,380 | $ 1,260,398 |
Transportation expenses | 47,254 | $ 0 | 96,551 | $ 0 |
Transferred at Point in Time | ||||
Disaggregation of Revenue [Line Items] | ||||
Crude oil and natural gas sales | 1,137,528 | 2,251,380 | ||
Transferred over Time | ||||
Disaggregation of Revenue [Line Items] | ||||
Crude oil and natural gas sales | 0 | 0 | ||
North Region [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Crude oil and natural gas sales | 839,290 | 1,656,888 | ||
North Region [Member] | Transferred at Point in Time | ||||
Disaggregation of Revenue [Line Items] | ||||
Crude oil and natural gas sales | 839,290 | 1,656,888 | ||
North Region [Member] | Transferred over Time | ||||
Disaggregation of Revenue [Line Items] | ||||
Crude oil and natural gas sales | 0 | 0 | ||
South Region [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Crude oil and natural gas sales | 298,238 | 594,492 | ||
South Region [Member] | Transferred at Point in Time | ||||
Disaggregation of Revenue [Line Items] | ||||
Crude oil and natural gas sales | 298,238 | 594,492 | ||
South Region [Member] | Transferred over Time | ||||
Disaggregation of Revenue [Line Items] | ||||
Crude oil and natural gas sales | 0 | 0 | ||
Crude oil sales | ||||
Disaggregation of Revenue [Line Items] | ||||
Crude oil and natural gas sales | 946,884 | 1,853,165 | ||
Transportation expenses | 40,200 | 80,600 | ||
Crude oil sales | North Region [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Crude oil and natural gas sales | 783,883 | 1,535,982 | ||
Crude oil sales | South Region [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Crude oil and natural gas sales | 163,001 | 317,183 | ||
Natural gas sales | ||||
Disaggregation of Revenue [Line Items] | ||||
Crude oil and natural gas sales | 190,644 | 398,215 | ||
Transportation expenses | 7,000 | 15,900 | ||
Natural gas sales | North Region [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Crude oil and natural gas sales | 55,407 | 120,906 | ||
Natural gas sales | South Region [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Crude oil and natural gas sales | 135,237 | 277,309 | ||
Operated properties | Crude oil sales | ||||
Disaggregation of Revenue [Line Items] | ||||
Crude oil and natural gas sales | 733,185 | 1,440,850 | ||
Operated properties | Crude oil sales | North Region [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Crude oil and natural gas sales | 587,582 | 1,156,794 | ||
Operated properties | Crude oil sales | South Region [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Crude oil and natural gas sales | 145,603 | 284,056 | ||
Operated properties | Natural gas sales | ||||
Disaggregation of Revenue [Line Items] | ||||
Crude oil and natural gas sales | 162,613 | 341,687 | ||
Operated properties | Natural gas sales | North Region [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Crude oil and natural gas sales | 41,425 | 93,245 | ||
Operated properties | Natural gas sales | South Region [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Crude oil and natural gas sales | 121,188 | 248,442 | ||
Non-operated properties | Crude oil sales | ||||
Disaggregation of Revenue [Line Items] | ||||
Crude oil and natural gas sales | 213,699 | 412,315 | ||
Non-operated properties | Crude oil sales | North Region [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Crude oil and natural gas sales | 196,301 | 379,188 | ||
Non-operated properties | Crude oil sales | South Region [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Crude oil and natural gas sales | 17,398 | 33,127 | ||
Non-operated properties | Natural gas sales | ||||
Disaggregation of Revenue [Line Items] | ||||
Crude oil and natural gas sales | 28,031 | 56,528 | ||
Non-operated properties | Natural gas sales | North Region [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Crude oil and natural gas sales | 13,982 | 27,661 | ||
Non-operated properties | Natural gas sales | South Region [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Crude oil and natural gas sales | $ 14,049 | $ 28,867 |
Derivative Instruments - Summar
Derivative Instruments - Summary of Outstanding Contracts with Respect to Natural Gas (Detail) - July 2018 to December 2018 Swaps - Natural Gas [Member] | 6 Months Ended |
Jun. 30, 2018MMBTU$ / MMBTU | |
Derivative [Line Items] | |
Natural Gas Production Derivative Volume, MMBtus | MMBTU | 115,920,000 |
Swaps Weighted Average Price | $ / MMBTU | 2.88 |
Derivative Instruments - Realiz
Derivative Instruments - Realized and Unrealized Gains and Losses on Derivative Instruments (Detail) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Non-cash gain (loss) on derivatives: | ||||
Non-cash gain (loss) on derivatives, net | $ (11,465) | $ 68,420 | ||
Gain (loss) on natural gas derivatives, net | $ (12,685) | $ 28,022 | (2,511) | 74,880 |
Diesel Fuel [Member] | ||||
Cash received (paid) on derivatives: | ||||
Cash received (paid) on derivatives, net | 0 | 185 | 0 | 919 |
Non-cash gain (loss) on derivatives: | ||||
Non-cash gain (loss) on derivatives, net | 0 | (1,098) | 0 | (3,729) |
Gain (loss) on natural gas derivatives, net | 0 | (913) | 0 | (2,810) |
Swap [Member] | Natural Gas [Member] | ||||
Cash received (paid) on derivatives: | ||||
Cash received (paid) on derivatives, net | 4,758 | 6,709 | 8,954 | 12,187 |
Non-cash gain (loss) on derivatives: | ||||
Non-cash gain (loss) on derivatives, net | (17,443) | 12,520 | (11,465) | 35,416 |
Collars | Natural Gas [Member] | ||||
Cash received (paid) on derivatives: | ||||
Cash received (paid) on derivatives, net | 0 | (3,050) | 0 | (9,456) |
Non-cash gain (loss) on derivatives: | ||||
Non-cash gain (loss) on derivatives, net | 0 | 11,843 | 0 | 36,733 |
Crude Oil and Natural Gas [Member] | ||||
Cash received (paid) on derivatives: | ||||
Cash received (paid) on derivatives, net | 4,758 | 3,659 | 8,954 | 2,731 |
Non-cash gain (loss) on derivatives: | ||||
Non-cash gain (loss) on derivatives, net | (17,443) | 24,363 | (11,465) | 72,149 |
Gain (loss) on natural gas derivatives, net | $ (12,685) | $ 28,022 | $ (2,511) | $ 74,880 |
Derivative Instruments - Gross
Derivative Instruments - Gross Amounts of Recognized Derivative Assets and Liabilities (Detail) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Gross amounts of recognized assets | $ 885 | $ 2,603 |
Gross amounts offset on balance sheet | (682) | 0 |
Net amounts of assets on balance sheet | 203 | 2,603 |
Gross amounts of recognized liabilities | (9,747) | 0 |
Gross amounts offset on balance sheet | 682 | 0 |
Net amounts of liabilities on balance sheet | $ (9,065) | $ 0 |
Derivative Instruments - Reconc
Derivative Instruments - Reconciles Net Amounts Derivative Assets and Liabilities (Detail) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Derivative assets | $ 203 | $ 2,603 |
Noncurrent derivative assets | 0 | 0 |
Net amounts of assets on balance sheet | 203 | 2,603 |
Derivative liabilities | (9,065) | 0 |
Noncurrent derivative liabilities | 0 | 0 |
Net amounts of liabilities on balance sheet | (9,065) | 0 |
Total derivative assets (liabilities), net | $ (8,862) | $ 2,603 |
Derivative Instruments Summary
Derivative Instruments Summary of Outstanding Contracts with Respect to Diesel Fuel (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Derivative [Line Items] | ||||
Non-cash gain (loss) on derivatives, net | $ (11,465) | $ 68,420 | ||
Gain on natural gas derivatives, net | $ (12,685) | $ 28,022 | (2,511) | 74,880 |
Diesel Fuel [Member] | ||||
Derivative [Line Items] | ||||
Cash received (paid) on derivatives, net | 0 | 185 | 0 | 919 |
Non-cash gain (loss) on derivatives, net | 0 | (1,098) | 0 | (3,729) |
Gain on natural gas derivatives, net | $ 0 | $ (913) | $ 0 | $ (2,810) |
Fair Value Measurements - Valua
Fair Value Measurements - Valuation of Financial Instruments by Pricing Levels (Detail) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | $ (8,862) | $ 2,603 |
Swap [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | (8,862) | 2,603 |
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 2 [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | (8,862) | 2,603 |
Fair Value, Inputs, Level 2 [Member] | Swap [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | (8,862) | 2,603 |
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 Measurements - Addit
Fair Value Measurements - Additional Information (Detail) | 6 Months Ended |
Jun. 30, 2018 | |
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) | 38 years |
Forward Commodity Prices [Member] | |
Fair Value Measurements [Line Items] | |
Forward commodity price escalation assumption used in impairment assessment | 3.00% |
Fair Value Measurements - Prope
Fair Value Measurements - Property Impairments (Detail) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Proved property impairments | $ 0 | $ 81,469 | $ 0 | $ 82,340 |
Unproved property impairments | 29,162 | 41,847 | 62,946 | 92,349 |
Oil and gas property fair value after impairment | 72,000 | 72,000 | ||
Property impairments | $ 29,162 | 123,316 | $ 62,946 | 174,689 |
Arkoma Woodford [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Proved property impairments | 81,200 | |||
Non-core [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Proved property impairments | $ 300 | $ 1,100 |
Fair Value Measurements - Fair
Fair Value Measurements - Fair Values of Financial Instruments not Recorded at Fair Value (Detail) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2018 | Dec. 31, 2017 | |
5% Senior Notes due 2022 (1) | ||
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 | |
4.375% Senior Notes Due 2028 | ||
Fair Value Measurements [Line Items] | ||
Debt Instrument, stated interest rate | 4.375% | |
Debt Instrument, Maturity Date, Description | 2,028 | |
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 | $ 0 | $ 188,000 |
Note payable | 8,845 | 9,974 |
Total debt | 6,166,543 | 6,353,691 |
Carrying Amount | 5% Senior Notes due 2022 (1) | ||
Fair Value Measurements [Line Items] | ||
Senior notes | 1,997,782 | 1,997,576 |
Carrying Amount | 4 1/2% Senior Notes Due 2023 | ||
Fair Value Measurements [Line Items] | ||
Senior notes | 1,487,803 | 1,486,690 |
Carrying Amount | 3.8% Senior Notes due 2024 | ||
Fair Value Measurements [Line Items] | ||
Senior notes | 992,588 | 992,036 |
Carrying Amount | 4.375% Senior Notes Due 2028 | ||
Fair Value Measurements [Line Items] | ||
Senior notes | 988,090 | 988,061 |
Carrying Amount | 4.9% Senior Notes due 2044 | ||
Fair Value Measurements [Line Items] | ||
Senior notes | 691,435 | 691,354 |
Estimated Fair Value | ||
Fair Value Measurements [Line Items] | ||
Revolving credit facility | 0 | 188,000 |
Note payable | 8,800 | 9,900 |
Total debt | 6,215,500 | 6,420,600 |
Estimated Fair Value | 5% Senior Notes due 2022 (1) | ||
Fair Value Measurements [Line Items] | ||
Senior notes | 2,030,100 | 2,040,000 |
Estimated Fair Value | 4 1/2% Senior Notes Due 2023 | ||
Fair Value Measurements [Line Items] | ||
Senior notes | 1,522,900 | 1,526,800 |
Estimated Fair Value | 3.8% Senior Notes due 2024 | ||
Fair Value Measurements [Line Items] | ||
Senior notes | 976,000 | 988,800 |
Estimated Fair Value | 4.375% Senior Notes Due 2028 | ||
Fair Value Measurements [Line Items] | ||
Senior notes | 994,100 | 987,200 |
Estimated Fair Value | 4.9% Senior Notes due 2044 | ||
Fair Value Measurements [Line Items] | ||
Senior notes | $ 683,600 | $ 679,900 |
Long-Term Debt - Long-Term Debt
Long-Term Debt - Long-Term Debt (Detail) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Debt Instrument [Line Items] | ||
Less: Current portion of long-term debt | $ (2,322) | $ (2,286) |
Long-term debt, net of current portion | $ 6,164,221 | 6,351,405 |
5% Senior Notes due 2022 (1) | ||
Debt Instrument [Line Items] | ||
Debt Instrument, stated interest rate | 5.00% | |
Note payable | ||
Debt Instrument [Line Items] | ||
Debt Instrument, stated interest rate | 3.14% | |
Note payable | $ 22,000 | |
3.8% Senior Notes due 2024 | ||
Debt Instrument [Line Items] | ||
Debt Instrument, stated interest rate | 3.80% | |
4.375% Senior Notes Due 2028 | ||
Debt Instrument [Line Items] | ||
Debt Instrument, stated interest rate | 4.375% | |
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 | $ 0 | 188,000 |
Note payable | 8,845 | 9,974 |
Total debt | 6,166,543 | 6,353,691 |
Carrying Amount | 5% Senior Notes due 2022 (1) | ||
Debt Instrument [Line Items] | ||
Senior notes | 1,997,782 | 1,997,576 |
Carrying Amount | 4 1/2% Senior Notes Due 2023 | ||
Debt Instrument [Line Items] | ||
Senior notes | 1,487,803 | 1,486,690 |
Carrying Amount | 3.8% Senior Notes due 2024 | ||
Debt Instrument [Line Items] | ||
Senior notes | 992,588 | 992,036 |
Carrying Amount | 4.375% Senior Notes Due 2028 | ||
Debt Instrument [Line Items] | ||
Senior notes | 988,090 | 988,061 |
Carrying Amount | 4.9% Senior Notes due 2044 | ||
Debt Instrument [Line Items] | ||
Senior notes | 691,435 | 691,354 |
Estimated Fair Value | ||
Debt Instrument [Line Items] | ||
Revolving credit facility | 0 | 188,000 |
Note payable | 8,800 | 9,900 |
Total debt | 6,215,500 | 6,420,600 |
Estimated Fair Value | 5% Senior Notes due 2022 (1) | ||
Debt Instrument [Line Items] | ||
Senior notes | 2,030,100 | 2,040,000 |
Estimated Fair Value | 4 1/2% Senior Notes Due 2023 | ||
Debt Instrument [Line Items] | ||
Senior notes | 1,522,900 | 1,526,800 |
Estimated Fair Value | 3.8% Senior Notes due 2024 | ||
Debt Instrument [Line Items] | ||
Senior notes | 976,000 | 988,800 |
Estimated Fair Value | 4.375% Senior Notes Due 2028 | ||
Debt Instrument [Line Items] | ||
Senior notes | 994,100 | 987,200 |
Estimated Fair Value | 4.9% Senior Notes due 2044 | ||
Debt Instrument [Line Items] | ||
Senior notes | $ 683,600 | $ 679,900 |
Long-Term Debt - Additional Inf
Long-Term Debt - Additional Information (Detail) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | |
Jun. 30, 2018 | Jun. 30, 2018 | Dec. 31, 2017 | |
Debt Instrument [Line Items] | |||
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net | $ 42,300 | $ 42,300 | $ 44,300 |
Line of credit facility, maturity date | Apr. 9, 2023 | ||
Aggregate amount of lender commitments on credit facility | 1,500,000 | $ 1,500,000 | |
Line of Credit Facility, Maximum Borrowing Capacity | $ 4,000,000 | 4,000,000 | |
Line of credit facility, commitment fee percentage, per annum | 0.20% | ||
Current portion of long-term debt | $ 2,322 | $ 2,322 | 2,286 |
Line of Credit Facility, Covenant Terms | 0.65 | ||
4.5% Senior Notes due 2023 | |||
Debt Instrument [Line Items] | |||
Debt Instrument, stated interest rate | 4.50% | 4.50% | |
Debt Instrument, Maturity Date, Description | 2,023 | ||
Note payable | |||
Debt Instrument [Line Items] | |||
Notes Payable | $ 22,000 | $ 22,000 | |
Loan term | 10 years | ||
Debt Instrument, stated interest rate | 3.14% | 3.14% | |
Debt Instrument, Maturity Date | Feb. 26, 2022 | ||
5% Senior Notes due 2022 (1) | |||
Debt Instrument [Line Items] | |||
Debt Instrument, stated interest rate | 5.00% | 5.00% | |
Debt Instrument, Maturity Date, Description | 2,022 | ||
3.8% Senior Notes due 2024 | |||
Debt Instrument [Line Items] | |||
Debt Instrument, stated interest rate | 3.80% | 3.80% | |
Debt Instrument, Maturity Date, Description | 2,024 | ||
4.375% Senior Notes Due 2028 | |||
Debt Instrument [Line Items] | |||
Debt Instrument, stated interest rate | 4.375% | 4.375% | |
Debt Instrument, Maturity Date, Description | 2,028 | ||
4.9% Senior Notes due 2044 | |||
Debt Instrument [Line Items] | |||
Debt Instrument, stated interest rate | 4.90% | 4.90% | |
Debt Instrument, Maturity Date, Description | 2,044 | ||
Estimated Fair Value | |||
Debt Instrument [Line Items] | |||
Credit facility | $ 0 | $ 0 | 188,000 |
Notes Payable | 8,800 | 8,800 | 9,900 |
Estimated Fair Value | 5% Senior Notes due 2022 (1) | |||
Debt Instrument [Line Items] | |||
Senior notes | 2,030,100 | 2,030,100 | 2,040,000 |
Estimated Fair Value | 3.8% Senior Notes due 2024 | |||
Debt Instrument [Line Items] | |||
Senior notes | 976,000 | 976,000 | 988,800 |
Estimated Fair Value | 4.375% Senior Notes Due 2028 | |||
Debt Instrument [Line Items] | |||
Senior notes | 994,100 | 994,100 | 987,200 |
Estimated Fair Value | 4.9% Senior Notes due 2044 | |||
Debt Instrument [Line Items] | |||
Senior notes | 683,600 | 683,600 | 679,900 |
Carrying Amount | |||
Debt Instrument [Line Items] | |||
Credit facility | 0 | 0 | 188,000 |
Notes Payable | 8,845 | 8,845 | 9,974 |
Carrying Amount | 5% Senior Notes due 2022 (1) | |||
Debt Instrument [Line Items] | |||
Senior notes | 1,997,782 | 1,997,782 | 1,997,576 |
Carrying Amount | 3.8% Senior Notes due 2024 | |||
Debt Instrument [Line Items] | |||
Senior notes | 992,588 | 992,588 | 992,036 |
Carrying Amount | 4.375% Senior Notes Due 2028 | |||
Debt Instrument [Line Items] | |||
Senior notes | 988,090 | 988,090 | 988,061 |
Carrying Amount | 4.9% Senior Notes due 2044 | |||
Debt Instrument [Line Items] | |||
Senior notes | $ 691,435 | $ 691,435 | $ 691,354 |
Long-Term Debt Long-Term Debt -
Long-Term Debt Long-Term Debt - Summary of Maturity Dates, Semi-Annual Interest Payment Dates, and Optional Redemption Periods of Outstanding Senior Note Obligations (Details) $ in Thousands | 6 Months Ended |
Jun. 30, 2018USD ($) | |
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 |
2028 Notes | |
Debt Instrument [Line Items] | |
Debt Instrument, Face Amount | $ 1,000,000 |
Maturity date | Jan. 15, 2028 |
Interest payment dates | Jan 15, July 15 |
Debt Instrument, Redemption Period, Start Date | Oct. 15, 2027 |
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 C
Commitments and Contingencies Commitments and Contingencies - Additional Information (Details) $ in Millions | 6 Months Ended |
Jun. 30, 2018USD ($) | |
Long-term Purchase Commitment [Line Items] | |
Purchase Obligation Agreement Expiration Date | 2,028 |
Future Drilling Commitments At Balance Sheet Date | $ 97 |
Drilling Commitments Year One | 42 |
Drilling Commitments Year Two | 41 |
Drilling Commitments Year Three | 10 |
Drilling Commitments Year Four | 4 |
Purchase Obligation | 1,400 |
Purchase Obligation, Future Minimum Payments, Remainder of Fiscal Year | 112 |
Purchase Obligation, Due in Second Year | 225 |
Purchase Obligation, Due in Third Year | 194 |
Purchase Obligation, Due in Fourth Year | 175 |
Purchase Obligation, Due in Fifth Year | 168 |
Purchase Obligation, Due after Fifth Year | $ 487 |
Future Drilling Commitments End Date | 2021-06 |
Commitments and Contingencies L
Commitments and Contingencies Loss Contingencies (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Jun. 30, 2018 | |
Loss Contingencies [Line Items] | ||
Legal proceedings recorded as a liability under other noncurrent liabilities | $ (7.6) | $ (4.7) |
Strack royalty payment litigation [Member] | ||
Loss Contingencies [Line Items] | ||
Damages sought in litigation matter | 200 | |
Estimated Litigation Liability, Current | $ 59.6 | 61.7 |
Future settlement payment, current year | $ 50 |
Stock Based Compensation - Stoc
Stock Based Compensation - Stock Based Compensation Expenses (Detail) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | ||||
Non-cash equity compensation | $ 10.6 | $ 9.1 | $ 21.5 | $ 20.6 |
Stock-Based Compensation - Addi
Stock-Based Compensation - Additional Information (Detail) $ in Millions | 6 Months Ended |
Jun. 30, 2018USD ($)shares | |
Restricted stock [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Stock available to grant | shares | 13,727,512 |
Fair value at vesting date | $ | $ 57 |
Unrecognized compensation expense related to non-vested | $ | $ 94 |
Unrecognized compensation expense related to non-vested, period for recognition, in years | 1 year 5 months 17 days |
Restricted stock [Member] | Minimum [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Grants vest over periods, in years | 1 year |
Restricted stock [Member] | Maximum [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Grants vest over periods, in years | 3 years |
2013 Plan [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Common stock available for issue | shares | 19,680,072 |
Stock Based Compensation - Summ
Stock Based Compensation - Summary of Changes in Non Vested Shares of Restricted Stock Outstanding (Detail) | 6 Months Ended |
Jun. 30, 2018$ / 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 | 4,026,110 |
Granted (unaudited), shares | shares | 1,277,491 |
Vested shares | shares | (1,041,748) |
Forfeited (unaudited), shares | shares | (178,957) |
Non-vested shares, ending balance | shares | 4,082,896 |
Non-vested, weighted average grant-date fair value, beginning of period | $ / shares | $ 35.63 |
Granted, weighted average grant-date fair value | $ / shares | 52.47 |
Vested, weighted average grant-date fair value | $ / shares | 47.10 |
Forfeited, weighted average grant-date fair value | $ / shares | 37.27 |
Non-vested, weighted average grant-date fair value, end of period | $ / shares | $ 37.90 |
Accumulated Other Comprehensi53
Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||||||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | Mar. 31, 2018 | Dec. 31, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | |
Accumulated Other Comprehensive Income [Abstract] | ||||||||
Accumulated other comprehensive income | $ 325 | $ 67 | $ 325 | $ 67 | $ 309 | $ 307 | $ (122) | $ (260) |
Foreign currency translation adjustments | 16 | 189 | 18 | 327 | ||||
Translation Adjustment Functional to Reporting Currency, Tax Benefit (Expense) | 0 | 0 | 0 | 0 | ||||
Total other comprehensive income, net of tax | $ 16 | $ 189 | $ 18 | $ 327 |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | ||
Income Taxes [Abstract] | |||||
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount | [1] | $ (66,716) | $ 35,494 | $ (130,867) | $ 33,222 |
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 21.00% | 35.00% | 21.00% | 35.00% | |
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount | $ (9,531) | $ 3,043 | $ (18,695) | $ 2,848 | |
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent | 3.00% | 3.00% | 3.00% | 3.00% | |
Effective Income Tax Rate Reconciliation, Tax Benefit (Deficiency), Amount | $ 359 | $ (473) | $ 1,868 | $ (3,773) | |
Effective Income Tax Rate Reconciliation, Tax Benefit (Deficiency), Percent | 0.00% | (1.00%) | 0.00% | (4.00%) | |
Effective Income Tax Rate Reconciliation, Valuation Allowance, Amount | [2] | $ (78) | $ (112) | $ (148) | $ (257) |
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Percent | 0.00% | 0.00% | 0.00% | 0.00% | |
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount | $ 734 | $ (97) | $ 1,074 | $ (207) | |
Effective Income Tax Rate Reconciliation, Other Adjustments, Percent | 0.00% | 0.00% | 0.00% | 0.00% | |
(Provision) benefit for income taxes | $ (75,232) | $ 37,855 | $ (146,768) | $ 31,833 | |
Effective Income Tax Rate Reconciliation, Percent | 24.00% | 37.00% | 24.00% | 34.00% | |
[1] | In December 2017 the Tax Cuts and Jobs Act was signed into law, which among other things reduced the U.S. federal corporate income tax rate from 35% to 21% effective January 1, 2018. | ||||
[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. |
Subsequent Events (Details)
Subsequent Events (Details) - Subsequent Event [Member] - USD ($) $ in Millions | 3 Months Ended | ||
Dec. 31, 2018 | Sep. 30, 2018 | Aug. 16, 2018 | |
Subsequent Event [Line Items] | |||
Senior notes | $ 400 | ||
Early Repayment of Senior Debt | $ 415 | ||
Gain (Loss) on Extinguishment of Debt | $ 7 | ||
Proceeds from formation of new mineral relationship | $ 220 | ||
Combined per year acquisitions of additional mineral interests | $ 125 |
Uncategorized Items - clr-20180
Label | Element | Value |
Retained Earnings [Member] | ||
Net Income (Loss) Attributable to Parent | us-gaap_NetIncomeLoss | $ 242,464,000 |