Document and Entity Information
Document and Entity Information - USD ($) $ in Billions | 12 Months Ended | ||
Dec. 31, 2015 | Feb. 16, 2016 | Jun. 30, 2015 | |
Entity Information [Line Items] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2015 | ||
Document Fiscal Year Focus | 2,015 | ||
Document Fiscal Period Focus | FY | ||
Trading Symbol | CLR | ||
Entity Registrant Name | CONTINENTAL RESOURCES, INC | ||
Entity Central Index Key | 732,834 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 372,684,421 | ||
Entity Public Float | $ 4.9 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Current assets: | ||
Cash and cash equivalents | $ 11,463 | $ 24,381 |
Receivables: | ||
Crude oil and natural gas sales | 378,622 | 552,476 |
Affiliated parties | 122 | 13,360 |
Joint interest and other, net | 232,293 | 567,476 |
Derivative assets | 93,922 | 52,423 |
Inventories | 94,151 | 102,179 |
Prepaid Taxes | 94 | 63,266 |
Prepaid expenses and other | 11,672 | 14,040 |
Total current assets | 822,339 | 1,389,601 |
Net property and equipment, based on successful efforts method of accounting | 14,063,328 | 13,635,852 |
Noncurrent derivative assets | 14,560 | 31,992 |
Other noncurrent assets | 19,581 | 18,588 |
Total assets | 14,919,808 | 15,076,033 |
Current liabilities: | ||
Accounts payable trade | 553,285 | 1,263,724 |
Revenues and royalties payable | 187,000 | 272,755 |
Payables to affiliated parties | 69 | 7,305 |
Accrued liabilities and other | 176,947 | 259,157 |
Derivative liabilities | 3,583 | 1,645 |
Current portion of long-term debt | 2,144 | 2,078 |
Total current liabilities | 923,028 | 1,806,664 |
Long-term debt, net of current portion | 7,115,644 | 5,926,800 |
Other noncurrent liabilities: | ||
Deferred income tax liabilities, net | 2,090,228 | 2,286,796 |
Asset retirement obligations, net of current portion | 101,251 | 75,462 |
Noncurrent derivative liabilities | 3,706 | 3,109 |
Other noncurrent liabilities | 17,051 | 9,358 |
Total other noncurrent liabilities | $ 2,212,236 | $ 2,374,725 |
Commitments and contingencies (Note 10) | ||
Shareholders’ equity: | ||
Preferred stock, $0.01 par value; 25,000,000 shares authorized; no shares issued and outstanding | $ 0 | $ 0 |
Common stock, $0.01 par value; 1,000,000,000 shares authorized; 372,959,080 shares issued and outstanding at December 31, 2015; 372,005,502 shares issued and outstanding at December 31, 2014 | 3,730 | 3,720 |
Additional paid-in capital | 1,345,624 | 1,287,941 |
Accumulated other comprehensive loss | (3,354) | (385) |
Retained earnings | 3,322,900 | 3,676,568 |
Total shareholders’ equity | 4,668,900 | 4,967,844 |
Total liabilities and shareholders’ equity | $ 14,919,808 | $ 15,076,033 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Dec. 31, 2015 | Dec. 31, 2014 |
Preferred stock, par value | $ 0.01 | $ 0.01 |
Preferred stock, shares authorized | 25,000,000 | 25,000,000 |
Preferred stock, shares issued | 0 | 0 |
Preferred stock, shares outstanding | 0 | 0 |
Common Stock, Par or Stated Value Per Share | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 1,000,000,000 | 500,000,000 |
Common stock, shares issued | 372,959,080 | 372,005,502 |
Common stock, outstanding | 372,959,080 | 372,005,502 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Revenues: | |||
Crude oil and natural gas sales | $ 2,551,131 | $ 4,107,894 | $ 3,473,026 |
Crude oil and natural gas sales to affiliates | 1,400 | 95,128 | 100,405 |
Gain (loss) on derivative instruments, net | 91,085 | 559,759 | (191,751) |
Crude oil and natural gas service operations | 36,551 | 38,837 | 40,127 |
Total revenues | 2,680,167 | 4,801,618 | 3,421,807 |
Operating costs and expenses: | |||
Production expenses | 347,243 | 347,349 | 280,789 |
Production expenses to affiliates | 1,654 | 5,123 | 1,408 |
Production taxes and other expenses | 200,637 | 349,760 | 298,787 |
Exploration expenses | 19,413 | 50,067 | 34,947 |
Crude oil and natural gas service operations | 17,337 | 21,871 | 29,665 |
Depreciation, depletion, amortization and accretion | 1,749,056 | 1,358,669 | 965,645 |
Property impairments | 402,131 | 616,888 | 220,508 |
General and administrative expenses | 189,846 | 184,655 | 144,379 |
Gain on sale of assets, net | (23,149) | (600) | (88) |
Total operating costs and expenses | 2,904,168 | 2,933,782 | 1,976,040 |
Income (loss) from operations | (224,001) | 1,867,836 | 1,445,767 |
Other income (expense): | |||
Interest expense | (313,079) | (283,928) | (235,275) |
Loss on extinguishment of debt | 0 | (24,517) | 0 |
Other | 1,995 | 2,647 | 2,557 |
Total other income (expense) | (311,084) | (305,798) | (232,718) |
Income (loss) before income taxes | (535,085) | 1,562,038 | 1,213,049 |
Provision (benefit) for income taxes | (181,417) | 584,697 | 448,830 |
Net income (loss) | $ (353,668) | $ 977,341 | $ 764,219 |
Basic net income per share (in dollars per share) | $ (0.96) | $ 2.65 | $ 2.08 |
Diluted net income per share (in dollars per share) | $ (0.96) | $ 2.64 | $ 2.07 |
Foreign currency translation adjustments | $ (2,969) | $ (385) | $ 0 |
Other Comprehensive Income (Loss), Net of Tax | (2,969) | (385) | 0 |
Comprehensive Income (Loss), Net of Tax | $ (356,637) | $ 976,956 | $ 764,219 |
Consolidated Statements of Shar
Consolidated Statements of Shareholders' Equity - USD ($) $ in Thousands | Total | Common stock | Additional paid-in capital | Accumulated Other Comprehensive Income (Loss) | Retained earnings |
Balance at Dec. 31, 2012 | $ 3,163,699 | $ 3,712 | $ 1,224,979 | $ 1,935,008 | |
Balance, shares at Dec. 31, 2012 | 371,209,362 | ||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Net income (loss) | 764,219 | 764,219 | |||
Other Comprehensive Income (Loss), Net of Tax | 0 | ||||
Stock-based compensation | 39,886 | 39,886 | |||
Restricted stock: | |||||
Issued | 5 | $ 5 | 0 | ||
Issued, shares | 522,518 | ||||
Repurchased and canceled | (14,690) | $ (3) | (14,687) | ||
Repurchased and canceled, shares | (277,050) | ||||
Forfeited | (1) | $ (1) | |||
Forfeited, shares | (137,512) | ||||
Balance at Dec. 31, 2013 | 3,953,118 | $ 3,713 | 1,250,178 | 2,699,227 | |
Balance, shares at Dec. 31, 2013 | 371,317,318 | ||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Net income (loss) | 977,341 | 977,341 | |||
Other Comprehensive Income (Loss), Net of Tax | (385) | $ (385) | |||
Stock-based compensation | 54,343 | 54,343 | |||
Restricted stock: | |||||
Issued | 14 | $ 14 | 0 | ||
Issued, shares | 1,424,764 | ||||
Repurchased and canceled | (16,583) | $ (3) | (16,580) | ||
Repurchased and canceled, shares | (283,434) | ||||
Forfeited | (4) | $ (4) | |||
Forfeited, shares | (453,146) | ||||
Balance at Dec. 31, 2014 | $ 4,967,844 | $ 3,720 | 1,287,941 | (385) | 3,676,568 |
Balance, shares at Dec. 31, 2014 | 372,005,502 | 372,005,502 | |||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Net income (loss) | $ (353,668) | (353,668) | |||
Other Comprehensive Income (Loss), Net of Tax | (2,969) | (2,969) | |||
Stock-based compensation | 51,817 | 51,817 | |||
Excess Tax Benefit from Share-based Compensation | 13,177 | 13,177 | |||
Restricted stock: | |||||
Issued | 15 | $ 15 | 0 | ||
Issued, shares | 1,462,534 | ||||
Repurchased and canceled | (7,313) | $ (2) | (7,311) | ||
Repurchased and canceled, shares | (172,786) | ||||
Forfeited | (3) | $ (3) | |||
Forfeited, shares | (336,170) | ||||
Balance at Dec. 31, 2015 | $ 4,668,900 | $ 3,730 | $ 1,345,624 | $ (3,354) | $ 3,322,900 |
Balance, shares at Dec. 31, 2015 | 372,959,080 | 372,959,080 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Cash flows from operating activities: | |||
Net income (loss) | $ (353,668) | $ 977,341 | $ 764,219 |
Adjustments to reconcile net income (loss) to cash provided by operating activities: | |||
Depreciation, depletion, amortization and accretion | 1,746,454 | 1,368,311 | 965,437 |
Property impairments | 402,131 | 616,888 | 220,508 |
Non-cash (gain) loss on derivatives, net | (21,532) | (174,409) | 130,196 |
Stock-based compensation | 51,834 | 54,353 | 39,890 |
Provision (benefit) for deferred income taxes | (181,441) | 584,677 | 442,621 |
Excess tax benefit from stock-based compensation | (13,177) | 0 | 0 |
Dry hole costs | 8,381 | 23,679 | 9,350 |
Gain on sale of assets, net | (23,149) | (600) | (88) |
Loss on extinguishment of debt | 0 | 24,517 | 0 |
Other, net | 12,646 | 7,637 | 2,037 |
Changes in assets and liabilities: | |||
Accounts receivable | 524,973 | (129,634) | (166,138) |
Inventories | 7,997 | (65,919) | (7,697) |
Other current assets | 65,493 | (57,489) | (11,537) |
Accounts payable trade | (201,434) | 85,540 | 107,250 |
Revenues and royalties payable | (85,754) | (18,022) | 28,401 |
Accrued liabilities and other | (84,056) | 58,880 | 44,260 |
Other noncurrent assets and liabilities | 1,403 | (35) | (5,414) |
Net cash provided by operating activities | 1,857,101 | 3,355,715 | 2,563,295 |
Cash flows from investing activities: | |||
Exploration and development | (3,042,747) | (4,604,468) | (3,660,773) |
Purchase of producing crude oil and natural gas properties | (557) | (48,917) | (16,604) |
Purchase of other property and equipment | (36,951) | (63,402) | (62,054) |
Proceeds from sale of assets and other | 34,008 | 129,388 | 28,420 |
Net cash used in investing activities | (3,046,247) | (4,587,399) | (3,711,011) |
Cash flows from financing activities: | |||
Credit facility borrowings | 2,001,000 | 1,695,000 | 970,000 |
Repayment of credit facility | (1,313,000) | (1,805,000) | (1,290,000) |
Proceeds from issuance of Senior Notes | 0 | 1,681,834 | 1,479,375 |
Redemption of Senior Notes | 0 | (300,000) | 0 |
Premium on redemption of Senior Notes | 0 | (17,497) | 0 |
Proceeds from other debt | 500,000 | 0 | 0 |
Repayment of other debt | (2,078) | (2,013) | (1,951) |
Debt issuance costs | (4,597) | (8,026) | (2,265) |
Repurchase of restricted stock for tax withholdings | (7,313) | (16,583) | (14,690) |
Excess tax benefit from stock-based compensation | 13,177 | 0 | 0 |
Net cash provided by financing activities | 1,187,189 | 1,227,715 | 1,140,469 |
Effect of exchange rate on cash and cash equivalents | (10,961) | (132) | 0 |
Net change in cash and cash equivalents | (12,918) | (4,101) | (7,247) |
Cash and cash equivalents at beginning of period | 24,381 | 28,482 | 35,729 |
Cash and cash equivalents at end of period | $ 11,463 | $ 24,381 | $ 28,482 |
Organization and Summary of Sig
Organization and Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization and Summary of Significant Accounting Policies | Organization and Summary of Significant Accounting Policies Description of the Company Continental Resources, Inc. (the “Company”) was originally formed in 1967 and is incorporated under the laws of the State of Oklahoma. The Company's principal business is crude oil and natural gas exploration, development and production with properties primarily located in the North, South, and East regions of the United States. The North region consists of properties north of Kansas and west of the Mississippi River and includes North Dakota Bakken, Montana Bakken, and the Red River units. The South region includes all properties south of Kansas and west of the Mississippi River including various plays in the SCOOP (South Central Oklahoma Oil Province), STACK (Sooner Trend Anadarko Canadian Kingfisher), Northwest Cana and Arkoma Woodford areas of Oklahoma. The East region is comprised of undeveloped leasehold acreage east of the Mississippi River with no current drilling or production operations. A substantial portion of the Company’s operations are concentrated in the North region, with that region comprising approximately 68% of the Company’s crude oil and natural gas production and approximately 77% of its crude oil and natural gas revenues for the year ended December 31, 2015 . The Company's principal producing properties in the North region are located in the Bakken field of North Dakota and Montana. As of December 31, 2015 , approximately 58% of the Company’s estimated proved reserves were located in the North region. In recent years, the Company has significantly expanded its activity in the South region with its discovery of the SCOOP play and its increased activity in the Northwest Cana and STACK plays. The South region comprised approximately 32% of the Company's crude oil and natural gas production, 23% of its crude oil and natural gas revenues, and 42% of its estimated proved reserves at December 31, 2015 . The Company has focused its operations on the exploration and development of crude oil since the 1980s. For the year ended December 31, 2015 , crude oil accounted for approximately 66% of the Company’s total production and approximately 85% of its crude oil and natural gas revenues. Crude oil represents approximately 57% of the Company's estimated proved reserves as of December 31, 2015 . Basis of presentation of consolidated financial statements The consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are 100% owned, after all significant intercompany accounts and transactions have been eliminated upon consolidation. Use of estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure and estimation of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from those estimates. The most significant of the estimates and assumptions that affect reported results are the estimates of the Company’s crude oil and natural gas reserves, which are used to compute depreciation, depletion, amortization and impairment of proved crude oil and natural gas properties. Revenue recognition Crude oil and natural gas sales result from interests owned by the Company in crude oil and natural gas properties. Sales of crude oil and natural gas produced from crude oil and natural gas operations are recognized when the product is delivered to the purchaser and title transfers to the purchaser. Payment is generally received one to three months after the sale has occurred. The Company uses the sales method of accounting for natural gas imbalances in those circumstances where it has under-produced or over-produced its ownership percentage in a property. Under this method, a receivable or payable is recognized only to the extent an imbalance cannot be recouped from the reserves in the underlying properties. The Company’s aggregate imbalance positions at December 31, 2015 and 2014 were not material. Cash and cash equivalents The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The Company maintains its cash and cash equivalents in accounts that may not be federally insured. As of December 31, 2015 , the Company had cash deposits in excess of federally insured amounts of approximately $10.7 million . The Company has not experienced any losses in such accounts and believes it is not exposed to significant credit risk in this area. Accounts receivable The Company operates exclusively in crude oil and natural gas exploration and production related activities. Receivables arising from crude oil and natural gas sales and joint interest receivables are generally unsecured. Accounts receivable are due within 30 days and are considered delinquent after 60 days. The Company determines its allowance for doubtful accounts by considering a number of factors, including the length of time accounts are past due, the Company’s history of losses, and the customer or working interest owner’s ability to pay. The Company writes off specific receivables when they become noncollectable and any payments subsequently received on those receivables are credited to the allowance for doubtful accounts. Write-offs of noncollectable receivables have historically not been material. Concentration of credit risk The Company is subject to credit risk resulting from the concentration of its crude oil and natural gas receivables with several significant purchasers. For the year ended December 31, 2015 , sales to the Company’s largest purchaser accounted for approximately 11% of its total crude oil and natural gas sales. No other purchasers accounted for more than 10% of the Company’s total crude oil and natural gas sales for 2015 . The Company does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers in various regions. Inventories Inventory is comprised of crude oil held in storage or as line fill in pipelines and tubular goods and equipment to be used in the Company's exploration and development activities. Crude oil inventories are valued at the lower of cost or market primarily using the first-in, first-out inventory method. Tubular goods and equipment are valued at the lower of cost or market, with cost determined primarily using a weighted average cost method applied to specific classes of inventory items. The components of inventory as of December 31, 2015 and 2014 consisted of the following: December 31, In thousands 2015 2014 Tubular goods and equipment $ 15,633 $ 15,659 Crude oil 78,518 86,520 Total $ 94,151 $ 102,179 Crude oil and natural gas properties The Company uses the successful efforts method of accounting for crude oil and natural gas properties whereby costs incurred to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, to drill and equip development wells, and expenditures for enhanced recovery operations are capitalized. Geological and geophysical costs, seismic costs incurred for exploratory projects, lease rentals and costs associated with unsuccessful exploratory wells or projects are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. To the extent a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between capitalized development costs and exploration expense. Maintenance, repairs and costs of injection are expensed as incurred, except that the costs of replacements or renewals that expand capacity or improve production are capitalized. Under the successful efforts method of accounting, the Company capitalizes exploratory drilling costs on the balance sheet pending determination of whether the well has found proved reserves in economically producible quantities. The Company capitalizes costs associated with the acquisition or construction of support equipment and facilities with the drilling and development costs to which they relate. If proved reserves are found by an exploratory well, the associated capitalized costs become part of well equipment and facilities. However, if proved reserves are not found, the capitalized costs associated with the well are expensed, net of any salvage value. Production expenses are those costs incurred by the Company to operate and maintain its crude oil and natural gas properties and associated equipment and facilities. Production expenses include labor costs to operate the Company’s properties, repairs and maintenance, waste water disposal costs, and materials and supplies utilized in the Company’s operations. Service property and equipment Service property and equipment consist primarily of automobiles and aircraft; machinery and equipment; gathering systems; storage tanks; office and computer equipment, software, furniture and fixtures; and buildings and improvements. Major renewals and replacements are capitalized and stated at cost, while maintenance and repairs are expensed as incurred. Depreciation and amortization of service property and equipment are provided in amounts sufficient to expense the cost of depreciable assets to operations over their estimated useful lives using the straight-line method. The estimated useful lives of service property and equipment are as follows: Service property and equipment Useful Lives In Years Automobiles and aircraft 5-10 Machinery and equipment 6-10 Gathering systems 15-30 Storage tanks 10-30 Office and computer equipment, software, furniture and fixtures 3-10 Enterprise resource planning software 25 Buildings and improvements 10-40 Depreciation, depletion and amortization Depreciation, depletion and amortization of capitalized drilling and development costs of producing crude oil and natural gas properties, including related support equipment and facilities, are computed using the unit-of-production method on a field basis based on total estimated proved developed reserves. Amortization of producing leaseholds is based on the unit-of-production method using total estimated proved reserves. In arriving at rates under the unit-of-production method, the quantities of recoverable crude oil and natural gas reserves are established based on estimates made by the Company’s internal geologists and engineers and external independent reserve engineers. Upon sale or retirement of properties, the cost and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss, if any, is recognized. Unit of production rates are revised whenever there is an indication of a need, but at least in conjunction with semi-annual reserve reports. Revisions are accounted for prospectively as changes in accounting estimates. Asset retirement obligations The Company accounts for its asset retirement obligations by recording the fair value of a liability for an asset retirement obligation in the period in which a legal obligation is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the capitalized asset retirement costs are charged to expense through the depreciation, depletion and amortization of crude oil and natural gas properties and the liability is accreted to the expected future abandonment cost ratably over the related asset’s life. The Company’s primary asset retirement obligations relate to future plugging and abandonment costs on its crude oil and natural gas properties and related facilities disposal. The following table summarizes the changes in the Company’s future abandonment liabilities from January 1, 2013 through December 31, 2015 : In thousands 2015 2014 2013 Asset retirement obligations at January 1 $ 76,708 $ 55,787 $ 47,171 Accretion expense 4,740 3,366 2,767 Revisions (1) 15,068 9,916 2,826 Plus: Additions for new assets 7,404 9,022 6,009 Less: Plugging costs and sold assets (1,011 ) (1,383 ) (2,986 ) Total asset retirement obligations at December 31 $ 102,909 $ 76,708 $ 55,787 Less: Current portion of asset retirement obligations at December 31 (2) 1,658 1,246 1,434 Non-current portion of asset retirement obligations at December 31 $ 101,251 $ 75,462 $ 54,353 (1) Revisions for the years ended December 31, 2015 and 2014 primarily represent an increase in the present value of liabilities from an acceleration in the estimated timing of abandonment prompted by decreases in commodity prices in 2015 and 2014 which shortened the economic lives of certain producing properties. (2) Balance is included in the caption "Accrued liabilities and other" in the consolidated balance sheets. As of December 31, 2015 and 2014 , net property and equipment on the consolidated balance sheets included $87.5 million and $64.7 million , respectively, of net asset retirement costs. Asset impairment Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter. The estimated future cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value. Non-producing crude oil and natural gas properties primarily consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Impairment losses for non-producing properties are recognized by amortizing the portion of the properties’ costs which management estimates will not be transferred to proved properties over the lives of the leases based on drilling plans, experience of successful drilling, and the average holding period. The Company’s impairment assessments are affected by economic factors such as the results of exploration activities, commodity price outlooks, anticipated drilling programs, remaining lease terms, and potential shifts in business strategy employed by management. Debt issuance costs Costs incurred in connection with the execution of the Company’s three-year term loan, note payable, and revolving credit facility and any amendments thereto are capitalized and amortized over the terms of the arrangements on a straight-line basis, the use of which approximates the effective interest method. Costs incurred upon the issuances of the Company's various senior notes (collectively, the “Notes”) were capitalized and are being amortized over the terms of the Notes using the effective interest method. The Company had capitalized costs of $71.8 million and $76.1 million (net of accumulated amortization of $47.0 million and $38.1 million ) relating to its long-term debt at December 31, 2015 and 2014 , respectively. See the subsequent heading titled New accounting pronouncements for a discussion of the presentation of these costs on the consolidated balance sheets. For the years ended December 31, 2015 , 2014 and 2013 , the Company recognized amortization expense associated with capitalized debt issuance costs of $8.9 million , $9.3 million and $8.6 million , respectively, which are reflected in “Interest expense” in the consolidated statements of comprehensive income (loss). Derivative instruments The Company recognizes its derivative instruments on the balance sheet as either assets or liabilities measured at fair value with such amounts classified as current or long-term based on contractual settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the changes in fair value in the consolidated statements of comprehensive income (loss) under the caption “Gain (loss) on derivative instruments, net.” Fair value of financial instruments The Company’s financial instruments consist primarily of cash, trade receivables, trade payables, derivative instruments and long-term debt. See Note 6. Fair Value Measurements for a discussion of the methods used to determine fair value for the Company's financial instruments and the quantification of fair value for its derivatives and long-term debt obligations at December 31, 2015 and 2014 . Income taxes Income taxes are accounted for using the liability method under which deferred income taxes are recognized for the future tax effects of temporary differences between financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year-end. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. The Company’s policy is to recognize penalties and interest related to unrecognized tax benefits, if any, in income tax expense. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized. The Company recorded valuation allowances of $13.5 million and $4.4 million for the years ended December 31, 2015 and 2014, respectively, against deferred tax assets associated with operating loss carryforwards generated by its Canadian subsidiary for which the Company does not expect to realize a benefit. Earnings per share Basic net income (loss) per share is computed by dividing net income (loss) by the weighted-average number of shares outstanding for the period. Diluted net income (loss) per share reflects the potential dilution of non-vested restricted stock awards, which are calculated using the treasury stock method. The following table presents the calculation of basic and diluted weighted average shares outstanding and net income (loss) per share for the years ended December 31, 2015 , 2014 and 2013 . Year ended December 31, In thousands, except per share data 2015 2014 2013 Income (loss) (numerator): Net income (loss) - basic and diluted $ (353,668 ) $ 977,341 $ 764,219 Weighted average shares (denominator): Weighted average shares - basic 369,540 368,829 368,150 Non-vested restricted stock (1) — 1,929 1,548 Weighted average shares - diluted 369,540 370,758 369,698 Net income (loss) per share: Basic $ (0.96 ) $ 2.65 $ 2.08 Diluted $ (0.96 ) $ 2.64 $ 2.07 (1) During the year ended December 31, 2015 , the Company had a net loss and therefore the potential dilutive effect of approximately 1,567,000 weighted average restricted shares were not included in the calculation of diluted net loss per share for 2015 because to do so would have been anti-dilutive to the computations. Foreign currency translation In 2014, the Company initiated exploratory drilling activities in Canada through a 100%-owned Canadian subsidiary. The Company has designated the Canadian dollar as the functional currency for its Canadian operations. Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in "Accumulated other comprehensive loss" within shareholders’ equity on the consolidated balance sheets. New accounting pronouncements In April 2015, the Financial Accounting Standards Board issued Accounting Standards Update ("ASU") 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs ("ASU 2015-03"). The new standard requires debt issuance costs related to a recognized term debt liability, such as the Company's senior notes, three-year term loan and note payable, be presented in the balance sheet as a direct deduction from the carrying amount of that term debt liability, consistent with the presentation of a debt discount. Under previous guidance, debt issuance costs were required to be presented in the balance sheet as an asset. The new standard does not affect the existing recognition and measurement guidance for debt issuance costs. The new standard is effective for annual and interim periods beginning after December 15, 2015, with early adoption permitted. The Company early adopted ASU 2015-03 as of June 30, 2015 on a retrospective basis to all prior balance sheet periods presented. As a result of the adoption, the Company reclassified unamortized debt issuance costs associated with its senior notes and note payable, which totaled $65.7 million and $69.0 million as of June 30, 2015 and December 31, 2014, respectively, from "Other noncurrent assets" to a reduction of "Long-term debt, net of current portion" on the consolidated balance sheets. Unamortized debt issuance costs reflected as a reduction of long-term debt subsequently totaled $64.0 million as of December 31, 2015 , inclusive of costs incurred upon execution of the Company's new term loan in November 2015 as discussed in Note 7. Long-Term Debt . Adoption of ASU 2015-03 had no impact on the Company's current and previously reported shareholders' equity, results of operations, or cash flows. The December 31, 2014 carrying amounts for the Company's senior notes and note payable presented throughout this report on Form 10-K have been adjusted to reflect the retroactive adoption of ASU 2015-03. Unamortized debt issuance costs associated with the Company's revolving credit facility, which amounted to $7.8 million and $7.0 million as of December 31, 2015 and 2014, respectively, were not reclassified and remain reflected in "Other noncurrent assets" on the consolidated balance sheets. In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes , which requires entities with a classified balance sheet to present all deferred tax assets and deferred tax liabilities as noncurrent instead of separating deferred taxes into current and noncurrent amounts. The standard will be effective for public companies for annual and interim periods beginning after December 15, 2016, with early adoption permitted. The Company early adopted ASU 2015-17 as of December 31, 2015 on a retrospective basis to all prior balance sheet periods presented. As a result of the adoption, the Company reclassified $36.2 million and $145.3 million as of December 31, 2015 and 2014, respectively, from "Accrued liabilities and other" to “Deferred income tax liabilities, net” on the consolidated balance sheets. Adoption of ASU 2015-17 had no impact on the Company's current and previously reported shareholders' equity, results of operations, or cash flows. The affected prior period deferred income tax account balances presented throughout this report on Form 10-K have been adjusted to reflect the retroactive adoption of ASU 2015-17. |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | 12 Months Ended |
Dec. 31, 2015 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Cash Flow Information | Supplemental Cash Flow Information The following table discloses supplemental cash flow information about cash paid for interest and income tax payments and refunds. Also disclosed is information about investing activities that affects recognized assets and liabilities but does not result in cash receipts or payments. Year ended December 31, In thousands 2015 2014 2013 Supplemental cash flow information: Cash paid for interest $ 301,743 $ 267,384 $ 209,815 Cash paid for income taxes 30 53,457 29,017 Cash received for income tax refunds 61,403 7 174 Non-cash investing activities: Increase (decrease) in accrued capital expenditures (519,949 ) 290,782 89,482 Asset retirement obligation additions and revisions, net 22,472 18,938 8,835 |
Net Property and Equipment
Net Property and Equipment | 12 Months Ended |
Dec. 31, 2015 | |
Property, Plant and Equipment, Net [Abstract] | |
Net Property and Equipment | Net Property and Equipment Net property and equipment includes the following at December 31, 2015 and 2014 : December 31, In thousands 2015 2014 Proved crude oil and natural gas properties $ 19,520,724 $ 17,045,967 Unproved crude oil and natural gas properties 682,988 966,080 Service properties, equipment and other 307,059 274,584 Total property and equipment 20,510,771 18,286,631 Accumulated depreciation, depletion and amortization (6,447,443 ) (4,650,779 ) Net property and equipment $ 14,063,328 $ 13,635,852 |
Accrued Liabilities and Other
Accrued Liabilities and Other | 12 Months Ended |
Dec. 31, 2015 | |
Accrued Liabilities and Other Liabilities [Abstract] | |
Accrued Liabilities and Other | Accrued Liabilities and Other Accrued liabilities and other includes the following at December 31, 2015 and 2014 : December 31, In thousands 2015 2014 Prepaid advances from joint interest owners $ 49,917 $ 115,687 Accrued compensation 40,060 39,848 Accrued production taxes, ad valorem taxes and other non-income taxes 21,678 36,550 Accrued interest 62,058 60,861 Current portion of asset retirement obligations 1,658 1,246 Other 1,576 4,965 Accrued liabilities and other $ 176,947 $ 259,157 |
Derivative Instruments
Derivative Instruments | 12 Months Ended |
Dec. 31, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Instruments | Derivative Instruments The Company recognizes all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the changes in fair value in the consolidated statements of comprehensive income (loss) under the caption “Gain (loss) on derivative instruments, net.” The Company may utilize swap and collar derivative contracts to economically hedge against the variability in cash flows associated with the sale of future crude oil and natural gas production. While the use of these derivative instruments limits the downside risk of adverse price movements, their use also limits future revenues from upward price movements. With respect to a fixed price swap contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the swap price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. For a collar contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price. Neither party is required to make a payment to the other party if the settlement price for any settlement period is between the floor price and the ceiling price. The Company's derivative contracts are settled based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on Inter-Continental Exchange ("ICE") pricing for Brent crude oil and natural gas derivative settlements based on NYMEX Henry Hub pricing. The estimated fair value of derivative contracts is based upon various factors, including commodity exchange prices, over-the-counter quotations, and, in the case of collars and written call options, volatility, the risk-free interest rate, and the time to expiration. The calculation of the fair value of collars and written call options requires the use of an option-pricing model. See Note 6. Fair Value Measurements . At December 31, 2015 , the Company had outstanding derivative contracts with respect to future production as set forth in the tables below. The hedged volumes reflected below represent an aggregation of multiple derivative contracts that have varying durations and may not be realized on a ratable basis over a calendar year. Crude Oil - ICE Brent Period and Type of Contract Bbls Ceiling Price January 2016 - December 2016 Written call options - ICE Brent (1) 1,464,000 $ 107.70 (1) Written call options represent the ceiling positions remaining from the Company's previous crude oil collar contracts. The floor positions of the collars were liquidated in the fourth quarter of 2014. For these written call options, the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price. Natural Gas - Henry Hub Swaps Weighted Average Price Floors Ceilings Weighted Average Price Weighted Average Price Period and Type of Contract MMBtus Range Range January 2016 - December 2016 Swaps - Henry Hub 133,710,000 $ 3.17 January 2017 - December 2017 Swaps - Henry Hub 25,550,000 $ 3.35 Collars - Henry Hub 65,700,000 $2.40 - $3.00 $ 2.47 $2.92 - $3.88 $ 3.08 Derivative gains and losses The following table presents cash settlements on matured or liquidated derivative instruments and non-cash gains and losses on open derivative instruments for the periods presented. Cash receipts and payments below reflect proceeds received upon early liquidation of derivative positions and gains or losses 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 or were liquidated during the period. Year ended December 31, In thousands 2015 2014 2013 Cash received (paid) on derivatives: Crude oil fixed price swaps (1) $ — $ 331,591 $ (54,289 ) Crude oil collars (1) — 65,310 (16,867 ) Natural gas fixed price swaps 39,670 (11,551 ) 9,601 Natural gas collars 29,883 — — Cash received (paid) on derivatives, net 69,553 385,350 (61,555 ) Non-cash gain (loss) on derivatives: Crude oil fixed price swaps — 84,792 (117,580 ) Crude oil collars — 1,121 (8,587 ) Crude oil written call options 4,715 3,981 — Natural gas fixed price swaps 41,828 62,699 (4,029 ) Natural gas collars (25,011 ) 21,816 — Non-cash gain (loss) on derivatives, net 21,532 174,409 (130,196 ) Gain (loss) on derivative instruments, net $ 91,085 $ 559,759 $ (191,751 ) (1) Net cash receipts for crude oil swaps and collars for the year ended December 31, 2014 include $433 million of proceeds received from crude oil derivative contracts that were settled in the fourth quarter of 2014 prior to their contractual maturities. Of the proceeds, $373 million related to crude oil swap liquidations and $60 million related to crude oil collar liquidations. Balance sheet offsetting of derivative assets and liabilities The Company’s derivative contracts are recorded at fair value in the consolidated balance sheets under the captions “Derivative assets”, “Noncurrent derivative assets”, “Derivative liabilities”, and “Noncurrent derivative liabilities”. Derivative assets and liabilities with the same counterparty that are subject to contractual terms which provide for net settlement are reported on a net basis in the consolidated balance sheets. The following table present the gross amounts of recognized derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the consolidated balance sheets for the periods presented, all at fair value. December 31, In thousands 2015 2014 Commodity derivative assets: Gross amounts of recognized assets $ 120,385 $ 84,431 Gross amounts offset on balance sheet (11,903 ) (16 ) Net amounts of assets on balance sheet 108,482 84,415 Commodity derivative liabilities: Gross amounts of recognized liabilities (19,192 ) (4,770 ) Gross amounts offset on balance sheet 11,903 16 Net amounts of liabilities on balance sheet $ (7,289 ) $ (4,754 ) The following table reconciles the net amounts disclosed above to the individual financial statement line items in the consolidated balance sheets. December 31, In thousands 2015 2014 Derivative assets $ 93,922 $ 52,423 Noncurrent derivative assets 14,560 31,992 Net amounts of assets on balance sheet 108,482 84,415 Derivative liabilities (3,583 ) (1,645 ) Noncurrent derivative liabilities (3,706 ) (3,109 ) Net amounts of liabilities on balance sheet (7,289 ) (4,754 ) Total derivative assets, net $ 101,193 $ 79,661 |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Fair Value Measurements The Company follows a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows: • Level 1: Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. • Level 2: Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. • Level 3: Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value. A financial instrument’s categorization within the hierarchy is based upon the lowest level of input that is significant to the fair value measurement. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the hierarchy. As Level 1 inputs generally provide the most reliable evidence of fair value, the Company uses Level 1 inputs when available. The Company’s policy is to recognize transfers between the hierarchy levels as of the beginning of the reporting period in which the event or change in circumstances caused the transfer. Assets and liabilities measured at fair value on a recurring basis The Company's derivative instruments are reported at fair value on a recurring basis. In determining the fair values of fixed price swaps, a discounted cash flow method is used due to the unavailability of relevant comparable market data for the Company’s exact contracts. The discounted cash flow method estimates future cash flows based on quoted market prices for forward commodity prices and a risk-adjusted discount rate. The fair values of fixed price swaps are calculated mainly using significant observable inputs (Level 2). Calculation of the fair values of collars and written call options requires the use of an industry-standard option pricing model that considers various inputs including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. These assumptions are observable in the marketplace or can be corroborated by active markets or broker quotes and are therefore designated as Level 2 within the valuation hierarchy. The Company’s calculation of fair value for each of its derivative positions is compared to the counterparty valuation for reasonableness. The following tables summarize the valuation of financial instruments by pricing levels that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014 . Fair value measurements at December 31, 2015 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets (liabilities): Fixed price swaps $ — $ 104,426 $ — $ 104,426 Collars — (3,195 ) — (3,195 ) Written call options — (38 ) — (38 ) Total $ — $ 101,193 $ — $ 101,193 Fair value measurements at December 31, 2014 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets (liabilities): Fixed price swaps $ — $ 62,599 $ — $ 62,599 Collars — 21,816 — 21,816 Written call options — (4,754 ) $ — (4,754 ) Total $ — $ 79,661 $ — $ 79,661 Assets measured at fair value on a nonrecurring basis Certain assets are reported at fair value on a nonrecurring basis in the consolidated financial statements. The following methods and assumptions were used to estimate the fair values for those assets. Asset impairments – Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter. The estimated future cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value. Due to the unavailability of relevant comparable market data, a discounted cash flow method is used to determine the fair value of proved properties. The discounted cash flow method estimates future cash flows based on the Company's estimates of future crude oil and natural gas production, commodity prices based on commodity futures price strips, operating costs, and a risk-adjusted discount rate. The fair value of proved crude oil and natural gas properties is calculated using significant unobservable inputs (Level 3). The following table sets forth quantitative information about the significant unobservable inputs used by the Company to calculate the fair value of proved crude oil and natural gas properties using a discounted cash flow method. Unobservable Input Assumption Future production Future production estimates for each property Forward commodity prices Forward NYMEX swap prices through 2020 (adjusted for differentials), escalating 3% per year thereafter Operating costs Estimated costs for the current year, escalating 3% per year thereafter Productive life of field Ranging from 0 to 34 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. Impairments of proved properties amounted to $138.9 million for the year ended December 31, 2015 resulting from declines in commodity prices that indicated the carrying amounts for certain fields were not recoverable. The 2015 impairments reflect fair value adjustments primarily concentrated in an emerging area with minimal production and costly reserve additions ( $42.5 million ), the Medicine Pole Hills units ( $32.5 million ), the Buffalo Red River units ( $26.3 million ), non-Bakken areas of North Dakota and Montana ( $8.2 million ), Wyoming properties ( $17.9 million ), and various legacy areas in the South region ( $11.4 million ). The impaired properties were written down to their estimated fair value totaling approximately $59.9 million . Certain unproved crude oil and natural gas properties were impaired during the years ended December 31, 2015 , 2014 , and 2013 , reflecting recurring amortization of undeveloped leasehold costs on properties the Company expects will not be transferred to proved properties over the lives of the leases based on drilling plans, experience of successful drilling, and the average holding period. The following table sets forth the non-cash impairments of both proved and unproved properties for the indicated periods. Proved and unproved property impairments are recorded under the caption “Property impairments” in the consolidated statements of comprehensive income (loss). Year ended December 31, In thousands 2015 2014 2013 Proved property impairments $ 138,878 $ 324,302 $ 51,805 Unproved property impairments 263,253 292,586 168,703 Total $ 402,131 $ 616,888 $ 220,508 Financial instruments not recorded at fair value The following table sets forth the fair values of financial instruments that are not recorded at fair value in the consolidated financial statements. December 31, 2015 December 31, 2014 In thousands Carrying Amount Fair Value Carrying Amount Fair Value Debt: Credit facility $ 853,000 $ 853,000 $ 165,000 $ 165,000 Term loan 498,274 500,000 — — Note payable 14,309 12,500 16,375 14,900 7.375% Senior Notes due 2020 196,574 179,200 195,997 213,000 7.125% Senior Notes due 2021 395,365 388,300 394,668 421,000 5% Senior Notes due 2022 1,996,831 1,480,400 1,996,507 1,857,900 4.5% Senior Notes due 2023 1,482,451 1,061,000 1,480,479 1,372,800 3.8% Senior Notes due 2024 989,932 700,300 988,940 868,700 4.9% Senior Notes due 2044 691,052 430,500 690,912 572,400 Total debt $ 7,117,788 $ 5,605,200 $ 5,928,878 $ 5,485,700 The fair values of credit facility borrowings and the term loan approximate carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and are classified as Level 2 in the fair value hierarchy. The fair value of the note payable is determined using a discounted cash flow approach based on the interest rate and payment terms of the note payable and an assumed discount rate. The fair value of the note payable is significantly influenced by the discount rate assumption, which is derived by the Company and is unobservable. Accordingly, the fair value of the note payable is classified as Level 3 in the fair value hierarchy. The fair values of the 7.375% Senior Notes due 2020 (“2020 Notes”), the 7.125% Senior Notes due 2021 (“2021 Notes”), the 5% Senior Notes due 2022 (“2022 Notes”), the 4.5% Senior Notes due 2023 (“2023 Notes”), the 3.8% Senior Notes due 2024 (“2024 Notes”), and the 4.9% Senior Notes due 2044 (“2044 Notes”) are based on quoted market prices and, accordingly, are classified as Level 1 in the fair value hierarchy. The carrying values of all classes of cash and cash equivalents, trade receivables, and trade payables are considered to be representative of their respective fair values due to the short term maturities of those instruments. |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2015 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | Long-Term Debt Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $49.6 million and $52.6 million at December 31, 2015 and 2014 , respectively, consists of the following. See Note 1. Organization and Summary of Significant Accounting Policies—New accounting pronouncements for a discussion of the impact on long-term debt from the Company's adoption of ASU 2015-03. December 31, In thousands 2015 2014 Credit facility $ 853,000 $ 165,000 Term loan 498,274 — Note payable 14,309 16,375 7.375% Senior Notes due 2020 196,574 195,997 7.125% Senior Notes due 2021 395,365 394,668 5% Senior Notes due 2022 1,996,831 1,996,507 4.5% Senior Notes due 2023 1,482,451 1,480,479 3.8% Senior Notes due 2024 989,932 988,940 4.9% Senior Notes due 2044 691,052 690,912 Total debt 7,117,788 5,928,878 Less: Current portion of long-term debt 2,144 2,078 Long-term debt, net of current portion $ 7,115,644 $ 5,926,800 Revolving credit facility The Company has an unsecured revolving credit facility, maturing on May 16, 2019, with aggregate commitments totaling $2.75 billion at December 31, 2015 , which may be increased up to a total of $4.0 billion upon agreement between the Company and participating lenders. The Company had $853 million and $165 million of outstanding borrowings on its credit facility at December 31, 2015 and 2014 , respectively. Borrowings bear interest at market-based interest rates plus a margin that is based on the terms of the borrowing and the credit ratings assigned to the Company's senior, unsecured, long-term indebtedness. The weighted-average interest rate on outstanding borrowings at December 31, 2015 was 1.9% . The Company had approximately $1.9 billion of borrowing availability on its credit facility at December 31, 2015 and incurred commitment fees based on its assigned credit rating at that date of 0.225% per annum of the daily average amount of unused borrowing availability under its credit facility. The revolving credit facility contains certain restrictive covenants including a requirement that the Company maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. This ratio represents the ratio of net debt (total debt less cash and cash equivalents) divided by the sum of net debt plus total shareholders' equity plus, to the extent resulting in a reduction of total shareholders' equity, the amount of any non-cash impairment charges incurred, net of any tax effect, after June 30, 2014. The Company was in compliance with this covenant at December 31, 2015 . Senior notes The following table summarizes the face values, maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding senior note obligations at December 31, 2015 . 2020 Notes 2021 Notes 2022 Notes 2023 Notes 2024 Notes 2044 Notes Face value (in thousands) $200,000 $400,000 $2,000,000 $1,500,000 $1,000,000 $700,000 Maturity date Oct 1, 2020 April 1, 2021 Sep 15, 2022 April 15, 2023 June 1, 2024 June 1, 2044 Interest payment dates April 1, Oct 1 April 1, Oct 1 March 15, Sep 15 April 15, Oct 15 June 1, Dec 1 June 1, Dec 1 Call premium redemption period (1) Oct 1, 2015 April 1, 2016 March 15, 2017 — — — Make-whole redemption period (2) Oct 1, 2015 April 1, 2016 March 15, 2017 Jan 15, 2023 Mar 1, 2024 Dec 1, 2043 (1) On or after these dates, the Company has the option to redeem all or a portion of its senior notes of the applicable series at the decreasing redemption prices specified in the respective senior note indentures (together, the “Indentures”) plus any accrued and unpaid interest to the date of redemption. (2) At any time prior to these dates, the Company has the option to redeem all or a portion of its senior notes of the applicable series at the “make-whole” redemption prices or amounts specified in the Indentures plus any accrued and unpaid interest to the date of redemption. The Company’s senior notes are not subject to any mandatory redemption or sinking fund requirements. The indentures governing the Company's senior notes contain covenants that, among others, limit the Company's ability to create liens securing certain indebtedness, enter into certain sale-leaseback transactions, and consolidate, merge or transfer certain assets. The senior note covenants are subject to a number of important exceptions and qualifications. The Company was in compliance with these covenants at December 31, 2015 . Two of the Company’s subsidiaries, Banner Pipeline Company, L.L.C. and CLR Asset Holdings, LLC, which have no material assets or operations, fully and unconditionally guarantee the senior notes 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. 2014 Redemption of Senior Notes In July 2014, the Company redeemed its then outstanding 8.25% Senior Notes due 2019 ("2019 Notes") using a portion of the proceeds from the May 2014 issuances of 2024 Notes and 2044 Notes. The 2019 Notes were redeemed for $317.5 million , representing a make-whole amount calculated in accordance with the terms of the 2019 Notes and related indenture. The Company recognized a pre-tax loss of $24.5 million related to the redemption, which included the make-whole premium and the write-off of deferred financing costs and unaccreted debt discount and is reflected under the caption “Loss on extinguishment of debt" in the consolidated statements of comprehensive income (loss) for the year ended December 31, 2014 . Term loan In November 2015, the Company borrowed $500 million under a three-year term loan agreement, the proceeds of which were used to repay a portion of the borrowings then outstanding on the Company's revolving credit facility. The term loan matures in full on November 4, 2018 and bears interest at a variable market-based interest rate plus a margin that is based on the terms of the borrowing and the credit ratings assigned to the Company's senior, unsecured, long-term indebtedness. The interest rate on the term loan at December 31, 2015 was 1.8% . The term loan contains certain restrictive covenants including a requirement that the Company maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.0, consistent with the covenant requirement in the Company's revolving credit facility. The Company was in compliance with this covenant at December 31, 2015 . Note payable In February 2012, 20 Broadway Associates LLC, a 100% owned subsidiary of the Company, borrowed $22 million under a 10 -year amortizing note payable secured by the Company’s corporate office building in Oklahoma City, Oklahoma. The loan bears interest at a fixed rate of 3.14% per annum. Principal and interest are payable monthly through the loan’s maturity date of February 26, 2022 . Accordingly, approximately $2.1 million is reflected as a current liability under the caption “Current portion of long-term debt” in the consolidated balance sheets at December 31, 2015 . |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes The items comprising the provision (benefit) for income taxes are as follows for the periods presented: Year ended December 31, In thousands 2015 2014 2013 Current income tax provision: United States federal $ — $ — $ 6,193 Various states 24 20 16 Total current income tax provision 24 20 6,209 Deferred income tax provision (benefit): United States federal (140,578 ) 527,315 403,002 Various states (40,863 ) 57,362 39,619 Total deferred income tax provision (benefit) (181,441 ) 584,677 442,621 Total provision (benefit) for income taxes $ (181,417 ) $ 584,697 $ 448,830 The provision (benefit) for income taxes differs from the amount computed by applying the United States statutory federal income tax rate to income (loss) before income taxes. The sources and tax effects of the difference are as follows: Year ended December 31, In thousands 2015 2014 2013 Expected income tax expense (benefit) based on US statutory tax rate of 35% $ (187,280 ) $ 546,713 $ 424,567 State income taxes, net of federal benefit (16,219 ) 42,169 25,838 Canadian valuation allowance 13,503 4,389 — Effect of differing statutory tax rate in Canada 5,239 (1,900 ) — Other, net 3,340 (6,674 ) (1,575 ) Provision (benefit) for income taxes $ (181,417 ) $ 584,697 $ 448,830 The components of the Company’s deferred tax assets and deferred tax liabilities as of December 31, 2015 and 2014 are reflected in the table below. As discussed in Note 1. Organization and Summary of Significant Accounting Policies—New accounting pronouncements , in November 2015 the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes . This new standard requires that all deferred tax assets and deferred tax liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. The new standard was early-adopted by the Company as of December 31, 2015 on a retrospective basis to all prior balance sheet periods presented. Accordingly, all deferred tax assets and deferred tax liabilities have been reflected as noncurrent and the Company reclassified $36.2 million and $145.3 million as of December 31, 2015 and 2014, respectively, from "Accrued liabilities and other" to “Deferred income tax liabilities, net” on the consolidated balance sheets. December 31, In thousands 2015 2014 Deferred tax assets United States net operating loss carryforwards 398,024 60,904 Canadian net operating loss carryforwards 17,892 4,899 Alternative minimum tax carryforwards 40,796 38,715 Equity compensation 32,910 22,255 Other 11,048 8,920 Total deferred tax assets 500,670 135,693 Canadian valuation allowance (17,892 ) (4,389 ) Total deferred tax assets, net of valuation allowance 482,778 131,304 Deferred tax liabilities Property and equipment (2,528,125 ) (2,254,343 ) Non-cash gains on derivatives (38,452 ) (30,269 ) Gain on derivative liquidation (4,158 ) (132,356 ) Other (2,271 ) (1,132 ) Total deferred tax liabilities (2,573,006 ) (2,418,100 ) Deferred income tax liabilities, net $ (2,090,228 ) $ (2,286,796 ) As of December 31, 2015 , the Company had federal and state net operating loss carryforwards of $865 million and $2.63 billion , respectively. The federal net operating loss carryforward will begin expiring in 2033. The Oklahoma net operating loss carryforward of $2.12 billion will begin to expire in 2027. The remainder of the state net operating loss carryforwards will begin expiring in 2017. The Company has alternative minimum tax credit carryforwards of $41 million that have no expiration date. Any available statutory depletion carryforwards will be recognized when realized. The Company files income tax returns in the U.S. federal, U.S. state and Canadian jurisdictions. With few exceptions, the Company is no longer subject to U.S. federal, state and local income tax examinations by tax authorities for years prior to 2012. The Company recorded valuation allowances of $13.5 million and $4.4 million against Canadian deferred tax assets for the years ended December 31, 2015 and 2014, respectively, which resulted in a cumulative valuation allowance of $17.9 million as of December 31, 2015 . Our Canadian subsidiary has generated operating loss carryforwards for which we do not believe we will realize a benefit. The amount of deferred tax assets considered realizable, however, could change if our subsidiary generates taxable income. |
Lease Commitments
Lease Commitments | 12 Months Ended |
Dec. 31, 2015 | |
Leases [Abstract] | |
Lease Commitments | Lease Commitments The Company’s operating lease obligations primarily represent leases for surface rentals, office equipment, communication towers, software services, and tanks for storage of hydraulic fracturing fluids. Lease payments associated with operating leases for the years ended December 31, 2015 , 2014 and 2013 were $9.6 million , $8.0 million and $3.0 million , respectively, a portion of which was capitalized and/or billed to other interest owners. At December 31, 2015 , the minimum future rental commitments under operating leases having lease terms in excess of one year are as follows: In thousands Total amount 2016 $ 3,348 2017 1,327 2018 979 2019 291 2020 210 Thereafter 3,105 Total obligations $ 9,260 |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Included below is a discussion of various future commitments of the Company as of December 31, 2015 . The commitments under these arrangements are not recorded in the accompanying consolidated balance sheets. Drilling commitments – As of December 31, 2015 , the Company had drilling rig contracts with various terms extending to year-end 2019 to ensure rig availability in its key operating areas. Future commitments as of December 31, 2015 total approximately $422 million , of which $200 million is expected to be incurred in 2016, $136 million in 2017, $62 million in 2018, and $24 million in 2019. Pipeline transportation commitments – The Company has entered into firm transportation commitments to guarantee pipeline access capacity on operational crude oil and natural gas pipelines. The commitments, which have varying terms extending as far as 2027, require the Company to pay per-unit transportation charges regardless of the amount of pipeline capacity used. Future commitments remaining as of December 31, 2015 under the operational pipeline transportation arrangements amount to approximately $1.0 billion , of which $215 million is expected to be incurred in 2016, $212 million in 2017, $207 million in 2018, $154 million in 2019, $47 million in 2020, and $170 million thereafter. Further, the Company was a party to a five-year firm transportation commitment (the "Agreement") for a future crude oil pipeline project being considered for development that is not yet operational. The project requires the granting of regulatory approvals and requires additional construction efforts by the counterparty before being completed. The project has faced significant delays and has failed to gain the necessary permits and approvals. As a result of the persistent delays and lack of regulatory approval, the Agreement’s basic assumptions and purpose have become commercially impracticable. Accordingly, in 2015 the Company provided a shipper termination notice pursuant to the Agreement and formally provided the counterparty with the Company’s termination of the Agreement in its entirety. The Company's previously disclosed commitments under the Agreement totaled approximately $260 million , which are no longer expected to be incurred. The Company’s pipeline commitments are for production primarily in the North region. The Company is not committed under these contracts to deliver fixed and determinable quantities of crude oil or natural gas in the future. Fuel purchase commitment – The Company has entered into a forward purchase contract with a third party to purchase specified quantities of diesel fuel at specified prices each month through June 2016 for use in drilling operations. Over the remaining contract term, the Company has committed to purchase approximately 11 million gallons of diesel fuel at varying prices depending on the grade of diesel fuel purchased and the timing and location of delivery. The contract satisfies a significant portion of the Company's anticipated diesel fuel needs and provides for physical delivery to desired locations. Future commitments under the arrangement as of December 31, 2015 total approximately $31 million , all of which will be incurred in 2016. Litigation – In November 2010, a putative class action was filed in the District Court of Blaine County, Oklahoma by Billy J. Strack and Daniela A. Renner as trustees of certain named trusts and on behalf of other similarly situated parties against the Company. The Petition alleged the Company improperly deducted post-production costs from royalties paid to plaintiffs and other royalty interest owners from crude oil and natural gas wells located in Oklahoma. The plaintiffs alleged a number of claims, including breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the proposed class. On November 3, 2014, plaintiffs filed an Amended Petition that did not add any substantive claims, but sought a “hybrid class action” in which they sought certification of certain claims for injunctive relief, reserving the right to seek a further class certification on money damages in the future. Plaintiffs filed an Amended Motion for Class Certification on January 9, 2015, that modified the proposed class to royalty owners in Oklahoma production from July 1, 1993, to the present (instead of 1980 to the present) and sought certification of over 45 separate “issues” for injunctive or declaratory relief, again, reserving the right to seek a further class certification of money damages in the future. The Company responded to the petition, its amendment, and the motions for class certification denying the allegations and raising a number of affirmative defenses and legal arguments to each of the claims and filings. Certain discovery was undertaken and the “hybrid” motion was briefed by plaintiffs and the Company. A hearing on the “hybrid” class certification was held on June 1st and 2nd, 2015. On June 11, 2015, the trial court certified a “hybrid” class as requested by plaintiffs. The Company has appealed the trial court’s class certification order, which will be reviewed de novo by the appellate court. The appeal briefing is complete and ready for determination by the court. An unsuccessful mediation was conducted on December 7, 2015. The Company is not currently able to estimate a reasonably possible loss or range of loss or what impact, if any, the action will have on its financial condition, results of operations or cash flows due to the preliminary status of the matter, the complexity and number of legal and factual issues presented by the matter and uncertainties with respect to, among other things, the nature of the claims and defenses, the potential size of the class, the scope and types of the properties and agreements involved, the production years involved, and the ultimate potential outcome of the matter. Although not currently at issue in the “hybrid” certification, plaintiffs have alleged underpayments in excess of $200 million that they may claim as damages, which may increase with the passage of time, a majority of which would be comprised of interest. The Company disputes plaintiffs’ claims, disputes that the case meets the requirements for a class action and is vigorously defending the case. The Company will continue to assert its defenses to the case as certified as well as any future attempt to certify a money damages class. The Company is involved in various other legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, disputes with tax authorities and other matters. While the outcome of these legal matters cannot be predicted with certainty, the Company does not expect them to have a material effect on its financial condition, results of operations or cash flows. As of December 31, 2015 and 2014 , the Company had recorded a liability on the consolidated balance sheets under the caption “Other noncurrent liabilities” of $6.1 million and $2.9 million , respectively, for various matters, none of which are believed to be individually significant. Environmental risk – Due to the nature of the crude oil and natural gas business, the Company is exposed to possible environmental risks. The Company is not aware of any material environmental issues or claims. |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2015 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Related Party Transactions The affiliate transactions reflected in the consolidated statements of comprehensive income (loss) include transactions between the Company and Hiland Partners, LP and its subsidiaries ("Hiland"). Hiland was controlled by the Company's principal shareholder through February 13, 2015, at which time it was sold to an unaffiliated third party. As a result of the sale, the prior related party relationship between the Company and Hiland terminated as of February 13, 2015, which resulted in a reduction in certain affiliate transactions recognized in the Company's financial statements at December 31, 2015 and for the year then ended. The Company historically sold a portion of its natural gas production to Hiland. For the years ended December 31, 2015 , 2014 , and 2013 , these sales amounted to $1.4 million , $95.1 million , and $100.4 million , respectively, net of transportation and processing costs, and are included in the caption “Crude oil and natural gas sales to affiliates” in the consolidated statements of comprehensive income (loss). At December 31, 2015 nothing was due to the Company and at December 31, 2014 , $13.1 million was due to the Company from Hiland, which is included in the caption “Receivables—Affiliated parties” in the consolidated balance sheets. At December 31, 2015 nothing was due from the Company and at December 31, 2014 , $0.3 million was due from the Company to Hiland for transportation and processing costs associated with the transactions, which is included in the caption “Payables to affiliated parties” in the consolidated balance sheets. In prior years, the Company engaged in crude oil trades with an affiliate from time to time to obtain space on pipeline systems in the Company's operating areas. There were no crude oil purchases or sales with affiliates in 2015 or 2014. In 2013, the Company purchased 30,000 barrels from an affiliate for $3.0 million and had no crude oil sales to the affiliate. The Company capitalized costs of $2.6 million , $5.9 million and $5.7 million in 2015 , 2014 , and 2013 , respectively, associated with drilling rig services provided by an affiliate. Hiland historically provided field services such as compression, purchases of residue fuel gas and reclaimed crude oil, and reimbursements of generator rentals and fuel. Production and other expenses attributable to these transactions with Hiland were $1.7 million , $5.1 million and $1.4 million for the years ended December 31, 2015 , 2014 , and 2013 , respectively. The total amount paid to these affiliates, a portion of which was billed to other interest owners, was $7.7 million , $58.2 million and $48.5 million for the years ended December 31, 2015 , 2014 , and 2013 , respectively. At December 31, 2015 nothing was due to these affiliates and at December 31, 2014 , $5.6 million was due to these affiliates related to the transactions, which is included in the caption “Payables to affiliated parties” in the consolidated balance sheets. Certain officers of the Company own or control entities that own working and royalty interests in wells operated by the Company. The Company paid revenues to these affiliates, including royalties, of $0.7 million , $1.7 million , and $2.3 million and received payments from these affiliates of $0.5 million , $0.8 million , and $1.3 million during the years ended December 31, 2015 , 2014 , and 2013 , respectively, relating to the operations of the respective properties. At December 31, 2015 and 2014 , $106,000 and $207,000 was due from these affiliates and approximately $52,000 and $133,000 was due to these affiliates, respectively, relating to these transactions. The Company allows certain affiliates to use its corporate aircraft and crews and has used the aircraft and crews of those same affiliates from time to time in order to facilitate efficient transportation of Company personnel. The rates charged between the parties vary by type of aircraft used. For usage during 2015 , 2014 , and 2013 , the Company charged affiliates approximately $9,600 , $51,000 , and $55,000 , respectively, for use of its corporate aircraft, crews, fuel, utilities and reimbursement of expenses and received $33,000 , $39,000 , and $379,000 from affiliates in 2015 , 2014 , and 2013 , respectively. The Company was charged $236,000 , $97,000 , and $51,000 , respectively, by affiliates for use of their aircraft and reimbursement of expenses during 2015 , 2014 , and 2013 and paid $221,000 , $34,000 , and $238,000 to the affiliates in 2015 , 2014 , and 2013 , respectively. The Company incurred costs for various field projects that have been ongoing with an entity that became an affiliate of the Company in the third quarter of 2014. During the fourth quarter of 2015, the affiliate relationship terminated. The total amount invoiced and capitalized for 2015 and 2014 associated with the projects was $8.8 million and $1.8 million , respectively. The total amount paid, a portion of which was billed to other interest owners, was $9.2 million and $1.9 million for 2015 and 2014 respectively. Nothing was owed by the Company at December 31, 2015 and $1.2 million was owed by the Company at December 31, 2014, which is included in the caption “Payables to affiliated parties” in the consolidated balance sheets. |
Stock-Based Compensation
Stock-Based Compensation | 12 Months Ended |
Dec. 31, 2015 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Stock-Based Compensation | Stock-Based Compensation The Company has granted restricted stock to employees and directors pursuant to the Continental Resources, Inc. 2005 Long-Term Incentive Plan (“2005 Plan”) and 2013 Long-Term Incentive Plan ("2013 Plan") as discussed below. The Company’s associated compensation expense, which is included in the caption “General and administrative expenses” in the consolidated statements of comprehensive income (loss), was $51.8 million , $54.4 million , and $39.9 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. In May 2013, the Company adopted the 2013 Plan and reserved a maximum of 19,680,072 shares of common stock that may be issued pursuant to the plan. The 2013 Plan replaced the Company's 2005 Plan as the instrument used to grant long-term incentive awards and no further awards will be granted under the 2005 Plan. However, restricted stock awards granted under the 2005 Plan prior to the adoption of the 2013 Plan will remain outstanding in accordance with their terms. As of December 31, 2015 , the Company had a maximum of 17,028,213 shares of restricted stock available to grant to officers, directors and employees under the 2013 Plan. Restricted stock is awarded in the name of the recipient and constitutes issued and outstanding shares of the Company’s common stock for all corporate purposes during the period of restriction and, except as otherwise provided under the 2013 Plan, 2005 Plan, or agreement relevant to a given award, includes the right to vote the restricted stock or to receive dividends, subject to forfeiture. Restricted stock grants generally vest over periods ranging from one to three years. A summary of changes in non-vested restricted shares from December 31, 2012 to December 31, 2015 is presented below. Number of Weighted Non-vested restricted shares at December 31, 2012 3,258,924 $ 31.64 Granted 522,518 48.98 Vested (929,618 ) 23.65 Forfeited (137,512 ) 35.96 Non-vested restricted shares at December 31, 2013 2,714,312 $ 37.50 Granted 1,424,764 61.11 Vested (1,007,166 ) 35.91 Forfeited (453,146 ) 44.90 Non-vested restricted shares at December 31, 2014 2,678,764 $ 49.40 Granted 1,462,534 46.65 Vested (555,517 ) 48.07 Forfeited (336,170 ) 51.23 Non-vested restricted shares at December 31, 2015 3,249,611 $ 48.20 The grant date fair value of restricted stock represents the closing market price of the Company’s common stock on the date of grant. Compensation expense for a restricted stock grant is a fixed amount determined at the grant date fair value and is recognized ratably over the vesting period as services are rendered by employees and directors. The expected life of restricted stock is based on the non-vested period that remains subsequent to the date of grant. There are no post-vesting restrictions related to the Company’s restricted stock. The fair value at the vesting date of restricted stock that vested during 2015 , 2014 and 2013 was $23.6 million , $58.2 million and $49.4 million , respectively. As of December 31, 2015 , there was approximately $67 million of unrecognized compensation expense related to non-vested restricted stock. This expense is expected to be recognized ratably over a weighted average period of 1.2 years. |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Income Accumulated Other Comprehensive Income (Loss) (Notes) | 12 Months Ended |
Dec. 31, 2015 | |
Statement of Comprehensive Income [Abstract] | |
Comprehensive Income (Loss) Note [Text Block] | Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in "Accumulated other comprehensive loss" within shareholders’ equity on the consolidated balance sheets. The following table summarizes the change in accumulated other comprehensive loss for the years ended December 31, 2015 and 2014 : Year ended December 31, In thousands 2015 2014 Beginning accumulated other comprehensive loss, net of tax $ (385 ) $ — Foreign currency translation adjustments (2,969 ) (385 ) Income tax benefit (1) — — Other comprehensive loss, net of tax (2,969 ) (385 ) Ending accumulated other comprehensive loss, net of tax $ (3,354 ) $ (385 ) (1) A valuation allowance has been recognized against deferred tax assets associated with losses generated by the Company's Canadian operations, thereby resulting in no income taxes on other comprehensive loss. |
Property Dispositions
Property Dispositions | 12 Months Ended |
Dec. 31, 2015 | |
Extractive Industries [Abstract] | |
Property Acquisitions and Dispositions | Property Dispositions During the year ended December 31, 2015 , the Company sold certain non-strategic properties in various areas to third parties for proceeds totaling $34.0 million . The proceeds primarily related to the assignment of certain non-producing leasehold acreage in Oklahoma to a third party for $25.9 million in May 2015. The Company recognized a pre-tax gain on the transaction of $20.5 million . The assigned properties represented an immaterial portion of the Company’s leasehold acreage. During the year ended December 31, 2014 , the Company sold certain non-strategic properties in various areas to third parties for proceeds totaling $129.4 million . The proceeds primarily related to dispositions of properties in the Niobrara play in Colorado and Wyoming in March 2014 for proceeds totaling $30.3 million and $85.8 million of proceeds received in conjunction with the disposition of a portion of the Company's Northwest Cana properties in Oklahoma in September 2014. The disposed properties represented an immaterial portion of the Company’s total proved reserves, production, and revenues. |
Crude Oil and Natural Gas Prope
Crude Oil and Natural Gas Property Information | 12 Months Ended |
Dec. 31, 2015 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Crude Oil and Natural Gas Property Information | Crude Oil and Natural Gas Property Information The tables reflected below represent consolidated figures for the Company and its subsidiaries. In 2014, the Company initiated exploratory drilling activities in Canada. Through December 31, 2015, those drilling activities have not had a material impact on the Company's total capital expenditures, production, and revenues. Accordingly, the results of operations, costs incurred, and capitalized costs associated with the Canadian operations have not been shown separately from the consolidated figures in the tables below. The following table sets forth the Company’s consolidated results of operations from crude oil and natural gas producing activities for the years ended December 31, 2015 , 2014 and 2013 . Year ended December 31, In thousands 2015 2014 2013 Crude oil and natural gas sales $ 2,552,531 $ 4,203,022 $ 3,573,431 Production expenses (348,897 ) (352,472 ) (282,197 ) Production taxes and other expenses (200,637 ) (349,760 ) (298,787 ) Exploration expenses (19,413 ) (50,067 ) (34,947 ) Depreciation, depletion, amortization and accretion (1,722,336 ) (1,338,351 ) (953,796 ) Property impairments (402,131 ) (616,888 ) (220,508 ) Income tax benefit (provision) 33,680 (559,311 ) (659,783 ) Results from crude oil and natural gas producing activities $ (107,203 ) $ 936,173 $ 1,123,413 Costs incurred in crude oil and natural gas activities Costs incurred, both capitalized and expensed, in connection with the Company’s consolidated crude oil and natural gas acquisition, exploration and development activities for the years ended December 31, 2015 , 2014 and 2013 are presented below: Year ended December 31, In thousands 2015 2014 2013 Property acquisition costs: Proved $ 557 $ 48,917 $ 16,604 Unproved 168,492 409,529 546,881 Total property acquisition costs 169,049 458,446 563,485 Exploration Costs 241,523 863,606 687,767 Development Costs 2,148,530 3,670,448 2,549,203 Total $ 2,559,102 $ 4,992,500 $ 3,800,455 Exploration costs above include asset retirement costs of $3.3 million , $1.2 million and $1.8 million and development costs above include asset retirement costs of $19.5 million , $19.1 million and $6.0 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. Aggregate capitalized costs Aggregate capitalized costs relating to the Company’s consolidated crude oil and natural gas producing activities and related accumulated depreciation, depletion and amortization as of December 31, 2015 and 2014 are as follows: December 31, In thousands 2015 2014 Proved crude oil and natural gas properties $ 19,520,724 $ 17,045,967 Unproved crude oil and natural gas properties 682,988 966,080 Total 20,203,712 18,012,047 Less accumulated depreciation, depletion and amortization (6,374,218 ) (4,601,864 ) Net capitalized costs $ 13,829,494 $ 13,410,183 Under the successful efforts method of accounting, the costs of drilling an exploratory well are capitalized pending determination of whether proved reserves can be attributed to the discovery. When initial drilling operations are complete, management attempts to determine whether the well has discovered crude oil and natural gas reserves and, if so, whether those reserves can be classified as proved reserves. Often, the determination of whether proved reserves can be recorded under SEC guidelines cannot be made when drilling is completed. In those situations where management believes that economically producible hydrocarbons have not been discovered, the exploratory drilling costs are reflected on the consolidated statements of comprehensive income (loss) as dry hole costs, a component of “Exploration expenses”. Where sufficient hydrocarbons have been discovered to justify further exploration or appraisal activities, exploratory drilling costs are deferred under the caption “Net property and equipment” on the consolidated balance sheets pending the outcome of those activities. On a quarterly basis, operating and financial management review the status of all deferred exploratory drilling costs in light of ongoing exploration activities—in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts. If management determines that future appraisal drilling or development activities are not likely to occur, any associated exploratory well costs are expensed in that period of determination. The following table presents the amount of capitalized exploratory drilling costs pending evaluation at December 31 for each of the last three years and changes in those amounts during the years then ended: Year ended December 31, In thousands 2015 2014 2013 Balance at January 1 $ 93,421 $ 152,775 $ 92,699 Additions to capitalized exploratory well costs pending determination of proved reserves 132,806 627,853 548,933 Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves (160,779 ) (671,618 ) (479,507 ) Capitalized exploratory well costs charged to expense (6,051 ) (15,589 ) (9,350 ) Balance at December 31 $ 59,397 $ 93,421 $ 152,775 Number of gross wells 73 119 67 As of December 31, 2015 , exploratory drilling costs of $1.7 million , representing three non-operated wells, were suspended one year beyond the completion of drilling. Evaluation of these non-operated wells is not within the Company's control and a final determination by the operator may not occur until 2017. Of the suspended costs, $0.1 million was incurred in 2014 and $1.6 million was incurred in 2013 . |
Supplemental Crude Oil and Natu
Supplemental Crude Oil and Natural Gas Information (Unaudited) | 12 Months Ended |
Dec. 31, 2015 | |
Supplemental Crude Oil and Natural Gas Information [Abstract] | |
Supplemental Crude Oil and Natural Gas Information (Unaudited) | Supplemental Crude Oil and Natural Gas Information (Unaudited) The table below shows estimates of proved reserves prepared by the Company’s internal technical staff and independent external reserve engineers in accordance with SEC definitions. Ryder Scott Company, L.P. ("Ryder Scott") prepared reserve estimates for properties comprising approximately 99% , 99% , and 99% of the Company’s discounted future net cash flows (PV-10) as of December 31, 2015 , 2014 , and 2013 , respectively. Properties comprising 99% of proved crude oil reserves and 97% of proved natural gas reserves were evaluated by Ryder Scott as of December 31, 2015 . Remaining reserve estimates were prepared by the Company’s internal technical staff. All proved reserves stated herein are located in the United States. No proved reserves have been recorded for the Company's Canadian operations at December 31, 2015 . Proved reserves are estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be economically producible in future periods from known reservoirs under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured, and estimates of engineers other than the Company’s might differ materially from the estimates set forth herein. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Periodic revisions to the estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Accordingly, reserve estimates may differ significantly from the quantities of crude oil and natural gas ultimately recovered. Reserves at December 31, 2015 , 2014 and 2013 were computed using the 12-month unweighted average of the first-day-of-the-month commodity prices as required by SEC rules. Natural gas imbalance receivables and payables for each of the three years ended December 31, 2015 , 2014 and 2013 were not material and have not been included in the reserve estimates. Proved crude oil and natural gas reserves Changes in proved reserves were as follows for the periods presented: Crude Oil Natural Gas Total Proved reserves as of December 31, 2012 561,163 1,341,084 784,677 Revisions of previous estimates (55,783 ) (241,623 ) (96,054 ) Extensions, discoveries and other additions 267,009 1,065,870 444,654 Production (34,989 ) (87,730 ) (49,610 ) Sales of minerals in place — — — Purchases of minerals in place 388 419 458 Proved reserves as of December 31, 2013 737,788 2,078,020 1,084,125 Revisions of previous estimates (67,151 ) (244,783 ) (107,949 ) Extensions, discoveries and other additions 239,526 1,206,569 440,621 Production (44,530 ) (114,295 ) (63,579 ) Sales of minerals in place (123 ) (18,623 ) (3,227 ) Purchases of minerals in place 850 1,498 1,100 Proved reserves as of December 31, 2014 866,360 2,908,386 1,351,091 Revisions of previous estimates (246,840 ) (302,143 ) (297,198 ) Extensions, discoveries and other additions 134,764 710,453 253,173 Production (53,517 ) (164,454 ) (80,926 ) Sales of minerals in place (253 ) (456 ) (329 ) Purchases of minerals in place — — — Proved reserves as of December 31, 2015 700,514 3,151,786 1,225,811 Revisions of previous estimates. Revisions represent changes in previous reserve estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs. Downward revisions to proved reserves in 2013 primarily represented the removal of PUD reserves resulting from a decision in 2013 to focus the Company's drilling program on certain areas of the Bakken and SCOOP plays with more attractive rates of return and multi-well pad drilling capabilities, while building on success in the Company's development of the Lower Three Forks reservoirs in the Bakken. Downward revisions to proved reserves in 2014 resulted from the Company refining its drilling program and reducing its planned rig count in response to the significant decrease in crude oil prices in the latter part of 2014, which contributed to the removal of PUD reserves no longer scheduled to be developed within five years from the date in which they were first booked. Downward revisions to proved reserves in 2015 resulted primarily from the significant decrease in commodity prices in 2015. The 12-month average price for crude oil decreased 47% from $94.99 per Bbl for 2014 to $50.28 per Bbl for 2015, while the 12-month average price for natural gas decreased 41% from $4.35 per MMBtu for 2014 to $2.58 per MMBtu for 2015. These decreases shortened the economic lives of certain producing properties and caused certain exploration and development projects to become uneconomic which had an adverse impact on the Company's proved reserve estimates, resulting in downward revisions of 185 MMBo and 391 Bcf (totaling 251 MMBoe) in 2015. In response to the continued decrease in commodity prices throughout 2015, the Company has further refined its drilling program and reduced its planned rig count to concentrate its efforts in core areas of North Dakota and Oklahoma that provide the best opportunities to improve recoveries and rates of return. The refinement of the Company's drilling program contributed to the removal of PUD reserves no longer scheduled to be developed within five years from the date in which they were first booked. One element leading to the removal is an increased emphasis on multi-well pad drilling in the Bakken, which resulted in the removal of PUDs in certain areas in favor of PUDs more likely to be developed with pad drilling where operating efficiencies may be realized. Further, in the SCOOP play the Company removed certain PUD locations originally planned to be developed with standard lateral drilling lengths in favor of PUDs to be developed with extended length laterals in similar locations that provide opportunities for improved well productivity and economics. The combination of these and other factors resulted in the removal of 65 MMBo and 197 Bcf (totaling 98 MMBoe) of PUD reserves in 2015. Additionally, changes in anticipated production performance on certain properties resulted in 63 MMBo of downward revisions to crude oil proved reserves and 125 Bcf of upward revisions to natural gas proved reserves (netting to 42 MMBoe of downward revisions) in 2015. The downward revisions described above were partially offset by upward revisions in 2015 due to lower operating costs being realized in conjunction with depressed commodity prices and improvements in operating efficiencies as well as other factors. Extensions, discoveries and other additions . These are additions to proved reserves resulting from (1) extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery and (2) discovery of new fields with proved reserves or of new reservoirs of proved reserves in old fields. Extensions, discoveries and other additions for each of the three years reflected in the table above were primarily due to increases in proved reserves associated with our successful drilling activity in our Bakken and SCOOP plays. Proved reserve additions in the Bakken totaled 75 MMBo and 124 Bcf (totaling 96 MMBoe) and reserve additions in SCOOP totaled 36 MMBo and 340 Bcf (totaling 93 MMBoe) for the year ended December 31, 2015 . Additionally, 2015 extensions and discoveries were significantly impacted by successful drilling results in the Northwest Cana/STACK area, resulting in proved reserve additions of 20 MMBo and 222 Bcf (totaling 57 MMBoe) in 2015 . Sales of minerals in place. These are reductions to proved reserves resulting from the disposition of properties during a period. See Note 14. Property Dispositions for a discussion of notable dispositions. Purchases of minerals in place. These are additions to proved reserves resulting from the acquisition of properties during a period. There were no notable acquisitions in the three years reflected in the table above. The following reserve information sets forth the estimated quantities of proved developed and proved undeveloped crude oil and natural gas reserves of the Company as of December 31, 2015 , 2014 and 2013 : December 31, 2015 2014 2013 Proved Developed Reserves Crude oil (MBbl) 326,798 342,137 278,630 Natural Gas (MMcf) 1,190,343 962,051 768,969 Total (MBoe) 525,188 502,479 406,792 Proved Undeveloped Reserves Crude oil (MBbl) 373,716 524,223 459,158 Natural Gas (MMcf) 1,961,443 1,946,335 1,309,051 Total (MBoe) 700,623 848,612 677,333 Total Proved Reserves Crude oil (MBbl) 700,514 866,360 737,788 Natural Gas (MMcf) 3,151,786 2,908,386 2,078,020 Total (MBoe) 1,225,811 1,351,091 1,084,125 Proved developed reserves are reserves expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are reserves that require relatively major capital expenditures to recover. Natural gas is converted to barrels of crude oil equivalent using a conversion factor of six thousand cubic feet per barrel of crude oil based on the average equivalent energy content of natural gas compared to crude oil. Standardized measure of discounted future net cash flows relating to proved crude oil and natural gas reserves The standardized measure of discounted future net cash flows presented in the following table was computed using the 12-month unweighted average of the first-day-of-the-month commodity prices, the costs in effect at December 31 of each year and a 10% discount factor. The Company cautions that actual future net cash flows may vary considerably from these estimates. Although the Company’s estimates of total proved reserves, development costs and production rates were based on the best available information, the development and production of the crude oil and natural gas reserves may not occur in the periods assumed. Actual prices realized, costs incurred and production quantities may vary significantly from those used. Therefore, the estimated future net cash flow computations should not be considered to represent the Company’s estimate of the expected revenues or the current value of existing proved reserves. The following table sets forth the standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves as of December 31, 2015 , 2014 and 2013 . December 31, In thousands 2015 2014 2013 Future cash inflows $ 36,551,672 $ 90,867,459 $ 78,646,274 Future production costs (10,869,493 ) (25,799,221 ) (21,333,460 ) Future development and abandonment costs (6,935,958 ) (12,842,174 ) (10,250,789 ) Future income taxes (3,717,612 ) (13,800,737 ) (12,447,127 ) Future net cash flows 15,028,609 38,425,327 34,614,898 10% annual discount for estimated timing of cash flows (8,552,325 ) (19,992,293 ) (18,319,131 ) Standardized measure of discounted future net cash flows $ 6,476,284 $ 18,433,034 $ 16,295,767 The weighted average crude oil price (adjusted for location and quality differentials) utilized in the computation of future cash inflows was $41.63 , $84.54 , and $91.50 per barrel at December 31, 2015 , 2014 and 2013 , respectively. The weighted average natural gas price (adjusted for location and quality differentials) utilized in the computation of future cash inflows was $2.35 , $6.06 , and $5.36 per Mcf at December 31, 2015 , 2014 and 2013 , respectively. Future cash flows are reduced by estimated future costs to develop and produce the proved reserves, as well as certain abandonment costs, based on year-end cost estimates assuming continuation of existing economic conditions. The expected tax benefits to be realized from the utilization of net operating loss carryforwards and tax credits are used in the computation of future income tax cash flows. The changes in the aggregate standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves are presented below for each of the past three years. December 31, In thousands 2015 2014 2013 Standardized measure of discounted future net cash flows at January 1 $ 18,433,034 $ 16,295,767 $ 11,180,357 Extensions, discoveries and improved recoveries, less related costs 1,091,283 5,516,528 6,613,665 Revisions of previous quantity estimates (2,156,028 ) (1,755,366 ) (1,765,300 ) Changes in estimated future development and abandonment costs 5,008,731 476,665 1,942,585 Purchases (sales) of minerals in place, net (7,768 ) (3,196 ) 12,012 Net change in prices and production costs (16,111,142 ) (1,925,349 ) 263,541 Accretion of discount 1,843,303 1,629,576 1,118,036 Sales of crude oil and natural gas produced, net of production costs (2,002,997 ) (3,500,790 ) (2,992,447 ) Development costs incurred during the period 1,394,584 2,466,748 1,210,223 Change in timing of estimated future production and other (3,844,259 ) (309,902 ) 464,111 Change in income taxes 2,827,543 (457,647 ) (1,751,016 ) Net change (11,956,750 ) 2,137,267 5,115,410 Standardized measure of discounted future net cash flows at December 31 $ 6,476,284 $ 18,433,034 $ 16,295,767 |
Quarterly Financial Data (Unaud
Quarterly Financial Data (Unaudited) | 12 Months Ended |
Dec. 31, 2015 | |
Quarterly Financial Information Disclosure [Abstract] | |
Quarterly Financial Data (Unaudited) | Quarterly Financial Data (Unaudited) The Company’s unaudited quarterly financial data for 2015 and 2014 is summarized below. Quarter ended In thousands, except per share data March 31 June 30 September 30 December 31 2015 Total revenues (1) $ 625,644 $ 796,374 $ 682,669 $ 575,480 Gain (loss) on derivative instruments, net (1) $ 32,755 $ (4,737 ) $ 46,527 $ 16,540 Property impairments (2) $ 147,561 $ 76,872 $ 96,697 $ 81,001 Income (loss) from operations $ (111,276 ) $ 82,447 $ (52,356 ) $ (142,816 ) Net income (loss) $ (131,971 ) $ 403 $ (82,423 ) $ (139,677 ) Net income (loss) per share: Basic $ (0.36 ) $ — $ (0.22 ) $ (0.38 ) Diluted $ (0.36 ) $ — $ (0.22 ) $ (0.38 ) 2014 (3) (4) Total revenues (1) $ 972,495 $ 886,095 $ 1,645,328 $ 1,297,700 Gain (loss) on derivative instruments, net (1) $ (39,674 ) $ (262,524 ) $ 473,999 $ 387,958 Property impairments (2) $ 58,208 $ 79,316 $ 85,561 $ 393,803 Income from operations $ 421,317 $ 236,394 $ 944,897 $ 265,228 Net income $ 226,234 $ 103,538 $ 533,521 $ 114,048 Net income per share: Basic $ 0.61 $ 0.28 $ 1.45 $ 0.31 Diluted $ 0.61 $ 0.28 $ 1.44 $ 0.31 (1) Gains and losses on mark-to-market derivative instruments are reflected in “Total revenues” on both the consolidated statements of comprehensive income (loss) and this table of unaudited quarterly financial data. Derivative gains and losses have been shown separately to illustrate the fluctuations in revenues that are attributable to the Company’s derivative instruments. Commodity price fluctuations each quarter can result in significant swings in mark-to-market gains and losses, which affects comparability between periods. (2) Property impairments have been shown separately to illustrate the fluctuations in income (loss) that are attributable to write downs of the Company's assets. Commodity price fluctuations each quarter can result in significant changes in estimated future cash flows and resulting impairments, which affects comparability between periods. (3) The 2014 third quarter includes a $24.5 million pre-tax ( $15.4 million after tax, or $0.04 per basic and diluted share) loss on extinguishment of debt as discussed in Note 7. Long-Term Debt . (4) Balances for the fourth quarter of 2014 include $433 million of pre-tax gains ( $273 million after tax, or $0.74 per basic and diluted share) recognized from crude oil derivative contracts that were settled prior to their contractual maturities. |
Organization and Summary of S24
Organization and Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Description of the Company | Description of the Company Continental Resources, Inc. (the “Company”) was originally formed in 1967 and is incorporated under the laws of the State of Oklahoma. The Company's principal business is crude oil and natural gas exploration, development and production with properties primarily located in the North, South, and East regions of the United States. The North region consists of properties north of Kansas and west of the Mississippi River and includes North Dakota Bakken, Montana Bakken, and the Red River units. The South region includes all properties south of Kansas and west of the Mississippi River including various plays in the SCOOP (South Central Oklahoma Oil Province), STACK (Sooner Trend Anadarko Canadian Kingfisher), Northwest Cana and Arkoma Woodford areas of Oklahoma. The East region is comprised of undeveloped leasehold acreage east of the Mississippi River with no current drilling or production operations. A substantial portion of the Company’s operations are concentrated in the North region, with that region comprising approximately 68% of the Company’s crude oil and natural gas production and approximately 77% of its crude oil and natural gas revenues for the year ended December 31, 2015 . The Company's principal producing properties in the North region are located in the Bakken field of North Dakota and Montana. As of December 31, 2015 , approximately 58% of the Company’s estimated proved reserves were located in the North region. In recent years, the Company has significantly expanded its activity in the South region with its discovery of the SCOOP play and its increased activity in the Northwest Cana and STACK plays. The South region comprised approximately 32% of the Company's crude oil and natural gas production, 23% of its crude oil and natural gas revenues, and 42% of its estimated proved reserves at December 31, 2015 . The Company has focused its operations on the exploration and development of crude oil since the 1980s. For the year ended December 31, 2015 , crude oil accounted for approximately 66% of the Company’s total production and approximately 85% of its crude oil and natural gas revenues. Crude oil represents approximately 57% of the Company's estimated proved reserves as of December 31, 2015 . |
Basis of presentation of consolidated financial statements | Basis of presentation of consolidated financial statements The consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are 100% owned, after all significant intercompany accounts and transactions have been eliminated upon consolidation. |
Use of Estimates | Use of estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure and estimation of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from those estimates. The most significant of the estimates and assumptions that affect reported results are the estimates of the Company’s crude oil and natural gas reserves, which are used to compute depreciation, depletion, amortization and impairment of proved crude oil and natural gas properties. |
Revenue Recognition | Revenue recognition Crude oil and natural gas sales result from interests owned by the Company in crude oil and natural gas properties. Sales of crude oil and natural gas produced from crude oil and natural gas operations are recognized when the product is delivered to the purchaser and title transfers to the purchaser. Payment is generally received one to three months after the sale has occurred. The Company uses the sales method of accounting for natural gas imbalances in those circumstances where it has under-produced or over-produced its ownership percentage in a property. Under this method, a receivable or payable is recognized only to the extent an imbalance cannot be recouped from the reserves in the underlying properties. The Company’s aggregate imbalance positions at December 31, 2015 and 2014 were not material. |
Cash and Cash Equivalents | Cash and cash equivalents The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The Company maintains its cash and cash equivalents in accounts that may not be federally insured. As of December 31, 2015 , the Company had cash deposits in excess of federally insured amounts of approximately $10.7 million . The Company has not experienced any losses in such accounts and believes it is not exposed to significant credit risk in this area. |
Accounts Receivable | Accounts receivable The Company operates exclusively in crude oil and natural gas exploration and production related activities. Receivables arising from crude oil and natural gas sales and joint interest receivables are generally unsecured. Accounts receivable are due within 30 days and are considered delinquent after 60 days. The Company determines its allowance for doubtful accounts by considering a number of factors, including the length of time accounts are past due, the Company’s history of losses, and the customer or working interest owner’s ability to pay. The Company writes off specific receivables when they become noncollectable and any payments subsequently received on those receivables are credited to the allowance for doubtful accounts. Write-offs of noncollectable receivables have historically not been material. |
Concentration of Credit Risk | Concentration of credit risk The Company is subject to credit risk resulting from the concentration of its crude oil and natural gas receivables with several significant purchasers. For the year ended December 31, 2015 , sales to the Company’s largest purchaser accounted for approximately 11% of its total crude oil and natural gas sales. No other purchasers accounted for more than 10% of the Company’s total crude oil and natural gas sales for 2015 . The Company does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers in various regions. |
Inventories | Inventories Inventory is comprised of crude oil held in storage or as line fill in pipelines and tubular goods and equipment to be used in the Company's exploration and development activities. Crude oil inventories are valued at the lower of cost or market primarily using the first-in, first-out inventory method. Tubular goods and equipment are valued at the lower of cost or market, with cost determined primarily using a weighted average cost method applied to specific classes of inventory items. The components of inventory as of December 31, 2015 and 2014 consisted of the following: December 31, In thousands 2015 2014 Tubular goods and equipment $ 15,633 $ 15,659 Crude oil 78,518 86,520 Total $ 94,151 $ 102,179 |
Crude Oil and Natural Gas Properties | Crude oil and natural gas properties The Company uses the successful efforts method of accounting for crude oil and natural gas properties whereby costs incurred to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, to drill and equip development wells, and expenditures for enhanced recovery operations are capitalized. Geological and geophysical costs, seismic costs incurred for exploratory projects, lease rentals and costs associated with unsuccessful exploratory wells or projects are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. To the extent a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between capitalized development costs and exploration expense. Maintenance, repairs and costs of injection are expensed as incurred, except that the costs of replacements or renewals that expand capacity or improve production are capitalized. Under the successful efforts method of accounting, the Company capitalizes exploratory drilling costs on the balance sheet pending determination of whether the well has found proved reserves in economically producible quantities. The Company capitalizes costs associated with the acquisition or construction of support equipment and facilities with the drilling and development costs to which they relate. If proved reserves are found by an exploratory well, the associated capitalized costs become part of well equipment and facilities. However, if proved reserves are not found, the capitalized costs associated with the well are expensed, net of any salvage value. Production expenses are those costs incurred by the Company to operate and maintain its crude oil and natural gas properties and associated equipment and facilities. Production expenses include labor costs to operate the Company’s properties, repairs and maintenance, waste water disposal costs, and materials and supplies utilized in the Company’s operations. |
Service Property and Equipment | Service property and equipment Service property and equipment consist primarily of automobiles and aircraft; machinery and equipment; gathering systems; storage tanks; office and computer equipment, software, furniture and fixtures; and buildings and improvements. Major renewals and replacements are capitalized and stated at cost, while maintenance and repairs are expensed as incurred. Depreciation and amortization of service property and equipment are provided in amounts sufficient to expense the cost of depreciable assets to operations over their estimated useful lives using the straight-line method. The estimated useful lives of service property and equipment are as follows: Service property and equipment Useful Lives In Years Automobiles and aircraft 5-10 Machinery and equipment 6-10 Gathering systems 15-30 Storage tanks 10-30 Office and computer equipment, software, furniture and fixtures 3-10 Enterprise resource planning software 25 Buildings and improvements 10-40 |
Depreciation, Depletion and Amortization | Depreciation, depletion and amortization Depreciation, depletion and amortization of capitalized drilling and development costs of producing crude oil and natural gas properties, including related support equipment and facilities, are computed using the unit-of-production method on a field basis based on total estimated proved developed reserves. Amortization of producing leaseholds is based on the unit-of-production method using total estimated proved reserves. In arriving at rates under the unit-of-production method, the quantities of recoverable crude oil and natural gas reserves are established based on estimates made by the Company’s internal geologists and engineers and external independent reserve engineers. Upon sale or retirement of properties, the cost and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss, if any, is recognized. Unit of production rates are revised whenever there is an indication of a need, but at least in conjunction with semi-annual reserve reports. Revisions are accounted for prospectively as changes in accounting estimates. |
Asset Retirement Obligations | Asset retirement obligations The Company accounts for its asset retirement obligations by recording the fair value of a liability for an asset retirement obligation in the period in which a legal obligation is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the capitalized asset retirement costs are charged to expense through the depreciation, depletion and amortization of crude oil and natural gas properties and the liability is accreted to the expected future abandonment cost ratably over the related asset’s life. |
Asset Impairment | Asset impairment Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter. The estimated future cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value. Non-producing crude oil and natural gas properties primarily consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Impairment losses for non-producing properties are recognized by amortizing the portion of the properties’ costs which management estimates will not be transferred to proved properties over the lives of the leases based on drilling plans, experience of successful drilling, and the average holding period. The Company’s impairment assessments are affected by economic factors such as the results of exploration activities, commodity price outlooks, anticipated drilling programs, remaining lease terms, and potential shifts in business strategy employed by management. |
Debt Issuance Costs | Debt issuance costs Costs incurred in connection with the execution of the Company’s three-year term loan, note payable, and revolving credit facility and any amendments thereto are capitalized and amortized over the terms of the arrangements on a straight-line basis, the use of which approximates the effective interest method. Costs incurred upon the issuances of the Company's various senior notes (collectively, the “Notes”) were capitalized and are being amortized over the terms of the Notes using the effective interest method. |
Derivative Instruments | Derivative instruments The Company recognizes its derivative instruments on the balance sheet as either assets or liabilities measured at fair value with such amounts classified as current or long-term based on contractual settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the changes in fair value in the consolidated statements of comprehensive income (loss) under the caption “Gain (loss) on derivative instruments, net.” |
Fair Value of Financial Instruments | Fair value of financial instruments The Company’s financial instruments consist primarily of cash, trade receivables, trade payables, derivative instruments and long-term debt. See Note 6. Fair Value Measurements for a discussion of the methods used to determine fair value for the Company's financial instruments and the quantification of fair value for its derivatives and long-term debt obligations at December 31, 2015 and 2014 . |
Income Taxes | Income taxes Income taxes are accounted for using the liability method under which deferred income taxes are recognized for the future tax effects of temporary differences between financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year-end. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. The Company’s policy is to recognize penalties and interest related to unrecognized tax benefits, if any, in income tax expense. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized. |
Earnings Per Share | arnings per share Basic net income (loss) per share is computed by dividing net income (loss) by the weighted-average number of shares outstanding for the period. Diluted net income (loss) per share reflects the potential dilution of non-vested restricted stock awards, which are calculated using the treasury stock method. |
Foreign Currency Transactions and Translations Policy | oreign currency translation In 2014, the Company initiated exploratory drilling activities in Canada through a 100%-owned Canadian subsidiary. The Company has designated the Canadian dollar as the functional currency for its Canadian operations. Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in "Accumulated other comprehensive loss" within shareholders’ equity on the consolidated balance sheets. |
New Accounting Pronouncements | ew accounting pronouncements In April 2015, the Financial Accounting Standards Board issued Accounting Standards Update ("ASU") 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs ("ASU 2015-03"). The new standard requires debt issuance costs related to a recognized term debt liability, such as the Company's senior notes, three-year term loan and note payable, be presented in the balance sheet as a direct deduction from the carrying amount of that term debt liability, consistent with the presentation of a debt discount. Under previous guidance, debt issuance costs were required to be presented in the balance sheet as an asset. The new standard does not affect the existing recognition and measurement guidance for debt issuance costs. The new standard is effective for annual and interim periods beginning after December 15, 2015, with early adoption permitted. The Company early adopted ASU 2015-03 as of June 30, 2015 on a retrospective basis to all prior balance sheet periods presented. As a result of the adoption, the Company reclassified unamortized debt issuance costs associated with its senior notes and note payable, which totaled $65.7 million and $69.0 million as of June 30, 2015 and December 31, 2014, respectively, from "Other noncurrent assets" to a reduction of "Long-term debt, net of current portion" on the consolidated balance sheets. Unamortized debt issuance costs reflected as a reduction of long-term debt subsequently totaled $64.0 million as of December 31, 2015 , inclusive of costs incurred upon execution of the Company's new term loan in November 2015 as discussed in Note 7. Long-Term Debt . Adoption of ASU 2015-03 had no impact on the Company's current and previously reported shareholders' equity, results of operations, or cash flows. The December 31, 2014 carrying amounts for the Company's senior notes and note payable presented throughout this report on Form 10-K have been adjusted to reflect the retroactive adoption of ASU 2015-03. Unamortized debt issuance costs associated with the Company's revolving credit facility, which amounted to $7.8 million and $7.0 million as of December 31, 2015 and 2014, respectively, were not reclassified and remain reflected in "Other noncurrent assets" on the consolidated balance sheets. In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes , which requires entities with a classified balance sheet to present all deferred tax assets and deferred tax liabilities as noncurrent instead of separating deferred taxes into current and noncurrent amounts. The standard will be effective for public companies for annual and interim periods beginning after December 15, 2016, with early adoption permitted. The Company early adopted ASU 2015-17 as of December 31, 2015 on a retrospective basis to all prior balance sheet periods presented. As a result of the adoption, the Company reclassified $36.2 million and $145.3 million as of December 31, 2015 and 2014, respectively, from "Accrued liabilities and other" to “Deferred income tax liabilities, net” on the consolidated balance sheets. Adoption of ASU 2015-17 had no impact on the Company's current and previously reported shareholders' equity, results of operations, or cash flows. The affected prior period deferred income tax account balances presented throughout this report on Form 10-K have been adjusted to reflect the retroactive adoption of ASU 2015-17. |
Organization and Summary of S25
Organization and Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Components of Inventories | The components of inventory as of December 31, 2015 and 2014 consisted of the following: December 31, In thousands 2015 2014 Tubular goods and equipment $ 15,633 $ 15,659 Crude oil 78,518 86,520 Total $ 94,151 $ 102,179 |
Schedule of Estimated Useful Lives of Service Property and Equipment | The estimated useful lives of service property and equipment are as follows: Service property and equipment Useful Lives In Years Automobiles and aircraft 5-10 Machinery and equipment 6-10 Gathering systems 15-30 Storage tanks 10-30 Office and computer equipment, software, furniture and fixtures 3-10 Enterprise resource planning software 25 Buildings and improvements 10-40 |
Summary of Changes in Future Abandonment Liabilities | The following table summarizes the changes in the Company’s future abandonment liabilities from January 1, 2013 through December 31, 2015 : In thousands 2015 2014 2013 Asset retirement obligations at January 1 $ 76,708 $ 55,787 $ 47,171 Accretion expense 4,740 3,366 2,767 Revisions (1) 15,068 9,916 2,826 Plus: Additions for new assets 7,404 9,022 6,009 Less: Plugging costs and sold assets (1,011 ) (1,383 ) (2,986 ) Total asset retirement obligations at December 31 $ 102,909 $ 76,708 $ 55,787 Less: Current portion of asset retirement obligations at December 31 (2) 1,658 1,246 1,434 Non-current portion of asset retirement obligations at December 31 $ 101,251 $ 75,462 $ 54,353 (1) Revisions for the years ended December 31, 2015 and 2014 primarily represent an increase in the present value of liabilities from an acceleration in the estimated timing of abandonment prompted by decreases in commodity prices in 2015 and 2014 which shortened the economic lives of certain producing properties. (2) Balance is included in the caption "Accrued liabilities and other" in the consolidated balance sheets. |
Calculation of Basic and Diluted Weighted Average Shares and Net Income per Share | he following table presents the calculation of basic and diluted weighted average shares outstanding and net income (loss) per share for the years ended December 31, 2015 , 2014 and 2013 . Year ended December 31, In thousands, except per share data 2015 2014 2013 Income (loss) (numerator): Net income (loss) - basic and diluted $ (353,668 ) $ 977,341 $ 764,219 Weighted average shares (denominator): Weighted average shares - basic 369,540 368,829 368,150 Non-vested restricted stock (1) — 1,929 1,548 Weighted average shares - diluted 369,540 370,758 369,698 Net income (loss) per share: Basic $ (0.96 ) $ 2.65 $ 2.08 Diluted $ (0.96 ) $ 2.64 $ 2.07 (1) During the year ended December 31, 2015 , the Company had a net loss and therefore the potential dilutive effect of approximately 1,567,000 weighted average restricted shares were not included in the calculation of diluted net loss per share for 2015 because to do so would have been anti-dilutive to the computations. |
Supplemental Cash Flow Inform26
Supplemental Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Supplemental Cash Flow Information [Abstract] | |
Summary of Supplemental Cash Flow Information | The following table discloses supplemental cash flow information about cash paid for interest and income tax payments and refunds. Also disclosed is information about investing activities that affects recognized assets and liabilities but does not result in cash receipts or payments. Year ended December 31, In thousands 2015 2014 2013 Supplemental cash flow information: Cash paid for interest $ 301,743 $ 267,384 $ 209,815 Cash paid for income taxes 30 53,457 29,017 Cash received for income tax refunds 61,403 7 174 Non-cash investing activities: Increase (decrease) in accrued capital expenditures (519,949 ) 290,782 89,482 Asset retirement obligation additions and revisions, net 22,472 18,938 8,835 |
Net Property and Equipment (Tab
Net Property and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Property, Plant and Equipment, Net [Abstract] | |
Schedule of Net Property and Equipment | Net property and equipment includes the following at December 31, 2015 and 2014 : December 31, In thousands 2015 2014 Proved crude oil and natural gas properties $ 19,520,724 $ 17,045,967 Unproved crude oil and natural gas properties 682,988 966,080 Service properties, equipment and other 307,059 274,584 Total property and equipment 20,510,771 18,286,631 Accumulated depreciation, depletion and amortization (6,447,443 ) (4,650,779 ) Net property and equipment $ 14,063,328 $ 13,635,852 |
Accrued Liabilities and Other (
Accrued Liabilities and Other (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Accrued Liabilities and Other Liabilities [Abstract] | |
Schedule of Accrued Liabilities and Other | Accrued liabilities and other includes the following at December 31, 2015 and 2014 : December 31, In thousands 2015 2014 Prepaid advances from joint interest owners $ 49,917 $ 115,687 Accrued compensation 40,060 39,848 Accrued production taxes, ad valorem taxes and other non-income taxes 21,678 36,550 Accrued interest 62,058 60,861 Current portion of asset retirement obligations 1,658 1,246 Other 1,576 4,965 Accrued liabilities and other $ 176,947 $ 259,157 |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Derivative [Line Items] | |
Summary of Outstanding Contracts with Respect to Natural Gas | Natural Gas - Henry Hub Swaps Weighted Average Price Floors Ceilings Weighted Average Price Weighted Average Price Period and Type of Contract MMBtus Range Range January 2016 - December 2016 Swaps - Henry Hub 133,710,000 $ 3.17 January 2017 - December 2017 Swaps - Henry Hub 25,550,000 $ 3.35 Collars - Henry Hub 65,700,000 $2.40 - $3.00 $ 2.47 $2.92 - $3.88 $ 3.08 |
Realized and Unrealized Gains and Losses on Derivative Instruments | The following table presents cash settlements on matured or liquidated derivative instruments and non-cash gains and losses on open derivative instruments for the periods presented. Cash receipts and payments below reflect proceeds received upon early liquidation of derivative positions and gains or losses 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 or were liquidated during the period. Year ended December 31, In thousands 2015 2014 2013 Cash received (paid) on derivatives: Crude oil fixed price swaps (1) $ — $ 331,591 $ (54,289 ) Crude oil collars (1) — 65,310 (16,867 ) Natural gas fixed price swaps 39,670 (11,551 ) 9,601 Natural gas collars 29,883 — — Cash received (paid) on derivatives, net 69,553 385,350 (61,555 ) Non-cash gain (loss) on derivatives: Crude oil fixed price swaps — 84,792 (117,580 ) Crude oil collars — 1,121 (8,587 ) Crude oil written call options 4,715 3,981 — Natural gas fixed price swaps 41,828 62,699 (4,029 ) Natural gas collars (25,011 ) 21,816 — Non-cash gain (loss) on derivatives, net 21,532 174,409 (130,196 ) Gain (loss) on derivative instruments, net $ 91,085 $ 559,759 $ (191,751 ) (1) Net cash receipts for crude oil swaps and collars for the year ended December 31, 2014 include $433 million of proceeds received from crude oil derivative contracts that were settled in the fourth quarter of 2014 prior to their contractual maturities. Of the proceeds, $373 million related to crude oil swap liquidations and $60 million related to crude oil collar liquidations. |
Balance sheet offsetting of derivative assets and liabilities | The following table present the gross amounts of recognized derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the consolidated balance sheets for the periods presented, all at fair value. December 31, In thousands 2015 2014 Commodity derivative assets: Gross amounts of recognized assets $ 120,385 $ 84,431 Gross amounts offset on balance sheet (11,903 ) (16 ) Net amounts of assets on balance sheet 108,482 84,415 Commodity derivative liabilities: Gross amounts of recognized liabilities (19,192 ) (4,770 ) Gross amounts offset on balance sheet 11,903 16 Net amounts of liabilities on balance sheet $ (7,289 ) $ (4,754 ) |
Schedule Of Derivative Assets Liabilities At Fair Value Net By Balance Sheet Classification Table | The following table reconciles the net amounts disclosed above to the individual financial statement line items in the consolidated balance sheets. December 31, In thousands 2015 2014 Derivative assets $ 93,922 $ 52,423 Noncurrent derivative assets 14,560 31,992 Net amounts of assets on balance sheet 108,482 84,415 Derivative liabilities (3,583 ) (1,645 ) Noncurrent derivative liabilities (3,706 ) (3,109 ) Net amounts of liabilities on balance sheet (7,289 ) (4,754 ) Total derivative assets, net $ 101,193 $ 79,661 |
ICE Brent [Member] | |
Derivative [Line Items] | |
Summary of Outstanding Contracts with Respect to Crude Oil | At December 31, 2015 , the Company had outstanding derivative contracts with respect to future production as set forth in the tables below. The hedged volumes reflected below represent an aggregation of multiple derivative contracts that have varying durations and may not be realized on a ratable basis over a calendar year. Crude Oil - ICE Brent Period and Type of Contract Bbls Ceiling Price January 2016 - December 2016 Written call options - ICE Brent (1) 1,464,000 $ 107.70 (1) Written call options represent the ceiling positions remaining from the Company's previous crude oil collar contracts. The floor positions of the collars were liquidated in the fourth quarter of 2014. For these written call options, the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price. |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value Disclosures [Abstract] | |
Valuation of Financial Instruments by Pricing Levels | The following tables summarize the valuation of financial instruments by pricing levels that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014 . Fair value measurements at December 31, 2015 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets (liabilities): Fixed price swaps $ — $ 104,426 $ — $ 104,426 Collars — (3,195 ) — (3,195 ) Written call options — (38 ) — (38 ) Total $ — $ 101,193 $ — $ 101,193 Fair value measurements at December 31, 2014 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets (liabilities): Fixed price swaps $ — $ 62,599 $ — $ 62,599 Collars — 21,816 — 21,816 Written call options — (4,754 ) $ — (4,754 ) Total $ — $ 79,661 $ — $ 79,661 |
Unobservable inputs used in level 3 fair value measurements | Unobservable Input Assumption Future production Future production estimates for each property Forward commodity prices Forward NYMEX swap prices through 2020 (adjusted for differentials), escalating 3% per year thereafter Operating costs Estimated costs for the current year, escalating 3% per year thereafter Productive life of field Ranging from 0 to 34 years Discount rate 10% Unobservable inputs to the fair value assessment are reviewed quarterly and are revised as warranted based on a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Fair value measurements of proved properties are reviewed and approved by certain members of the Company’s management. |
Property Impairments | The following table sets forth the non-cash impairments of both proved and unproved properties for the indicated periods. Proved and unproved property impairments are recorded under the caption “Property impairments” in the consolidated statements of comprehensive income (loss). Year ended December 31, In thousands 2015 2014 2013 Proved property impairments $ 138,878 $ 324,302 $ 51,805 Unproved property impairments 263,253 292,586 168,703 Total $ 402,131 $ 616,888 $ 220,508 |
Fair Values of Financial Instruments not Recorded at Fair Value | The following table sets forth the fair values of financial instruments that are not recorded at fair value in the consolidated financial statements. December 31, 2015 December 31, 2014 In thousands Carrying Amount Fair Value Carrying Amount Fair Value Debt: Credit facility $ 853,000 $ 853,000 $ 165,000 $ 165,000 Term loan 498,274 500,000 — — Note payable 14,309 12,500 16,375 14,900 7.375% Senior Notes due 2020 196,574 179,200 195,997 213,000 7.125% Senior Notes due 2021 395,365 388,300 394,668 421,000 5% Senior Notes due 2022 1,996,831 1,480,400 1,996,507 1,857,900 4.5% Senior Notes due 2023 1,482,451 1,061,000 1,480,479 1,372,800 3.8% Senior Notes due 2024 989,932 700,300 988,940 868,700 4.9% Senior Notes due 2044 691,052 430,500 690,912 572,400 Total debt $ 7,117,788 $ 5,605,200 $ 5,928,878 $ 5,485,700 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $49.6 million and $52.6 million at December 31, 2015 and 2014 , respectively, consists of the following. See Note 1. Organization and Summary of Significant Accounting Policies—New accounting pronouncements for a discussion of the impact on long-term debt from the Company's adoption of ASU 2015-03. December 31, In thousands 2015 2014 Credit facility $ 853,000 $ 165,000 Term loan 498,274 — Note payable 14,309 16,375 7.375% Senior Notes due 2020 196,574 195,997 7.125% Senior Notes due 2021 395,365 394,668 5% Senior Notes due 2022 1,996,831 1,996,507 4.5% Senior Notes due 2023 1,482,451 1,480,479 3.8% Senior Notes due 2024 989,932 988,940 4.9% Senior Notes due 2044 691,052 690,912 Total debt 7,117,788 5,928,878 Less: Current portion of long-term debt 2,144 2,078 Long-term debt, net of current portion $ 7,115,644 $ 5,926,800 |
Summary of Maturity Dates, Semi-Annual Interest Payment Dates, and Optional Redemption Periods of Outstanding Senior Note Obligations | The following table summarizes the face values, maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding senior note obligations at December 31, 2015 . 2020 Notes 2021 Notes 2022 Notes 2023 Notes 2024 Notes 2044 Notes Face value (in thousands) $200,000 $400,000 $2,000,000 $1,500,000 $1,000,000 $700,000 Maturity date Oct 1, 2020 April 1, 2021 Sep 15, 2022 April 15, 2023 June 1, 2024 June 1, 2044 Interest payment dates April 1, Oct 1 April 1, Oct 1 March 15, Sep 15 April 15, Oct 15 June 1, Dec 1 June 1, Dec 1 Call premium redemption period (1) Oct 1, 2015 April 1, 2016 March 15, 2017 — — — Make-whole redemption period (2) Oct 1, 2015 April 1, 2016 March 15, 2017 Jan 15, 2023 Mar 1, 2024 Dec 1, 2043 (1) On or after these dates, the Company has the option to redeem all or a portion of its senior notes of the applicable series at the decreasing redemption prices specified in the respective senior note indentures (together, the “Indentures”) plus any accrued and unpaid interest to the date of redemption. (2) At any time prior to these dates, the Company has the option to redeem all or a portion of its senior notes of the applicable series at the “make-whole” redemption prices or amounts specified in the Indentures plus any accrued and unpaid interest to the date of redemption. |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |
Provision for Income Taxes | The items comprising the provision (benefit) for income taxes are as follows for the periods presented: Year ended December 31, In thousands 2015 2014 2013 Current income tax provision: United States federal $ — $ — $ 6,193 Various states 24 20 16 Total current income tax provision 24 20 6,209 Deferred income tax provision (benefit): United States federal (140,578 ) 527,315 403,002 Various states (40,863 ) 57,362 39,619 Total deferred income tax provision (benefit) (181,441 ) 584,677 442,621 Total provision (benefit) for income taxes $ (181,417 ) $ 584,697 $ 448,830 |
Schedule of Provision for Income Taxes with Income Tax at Federal Statutory Rate | Year ended December 31, In thousands 2015 2014 2013 Expected income tax expense (benefit) based on US statutory tax rate of 35% $ (187,280 ) $ 546,713 $ 424,567 State income taxes, net of federal benefit (16,219 ) 42,169 25,838 Canadian valuation allowance 13,503 4,389 — Effect of differing statutory tax rate in Canada 5,239 (1,900 ) — Other, net 3,340 (6,674 ) (1,575 ) Provision (benefit) for income taxes $ (181,417 ) $ 584,697 $ 448,830 |
Components of Deferred Tax Assets and Liabilities | The components of the Company’s deferred tax assets and deferred tax liabilities as of December 31, 2015 and 2014 are reflected in the table below. As discussed in Note 1. Organization and Summary of Significant Accounting Policies—New accounting pronouncements , in November 2015 the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes . This new standard requires that all deferred tax assets and deferred tax liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. The new standard was early-adopted by the Company as of December 31, 2015 on a retrospective basis to all prior balance sheet periods presented. Accordingly, all deferred tax assets and deferred tax liabilities have been reflected as noncurrent and the Company reclassified $36.2 million and $145.3 million as of December 31, 2015 and 2014, respectively, from "Accrued liabilities and other" to “Deferred income tax liabilities, net” on the consolidated balance sheets. December 31, In thousands 2015 2014 Deferred tax assets United States net operating loss carryforwards 398,024 60,904 Canadian net operating loss carryforwards 17,892 4,899 Alternative minimum tax carryforwards 40,796 38,715 Equity compensation 32,910 22,255 Other 11,048 8,920 Total deferred tax assets 500,670 135,693 Canadian valuation allowance (17,892 ) (4,389 ) Total deferred tax assets, net of valuation allowance 482,778 131,304 Deferred tax liabilities Property and equipment (2,528,125 ) (2,254,343 ) Non-cash gains on derivatives (38,452 ) (30,269 ) Gain on derivative liquidation (4,158 ) (132,356 ) Other (2,271 ) (1,132 ) Total deferred tax liabilities (2,573,006 ) (2,418,100 ) Deferred income tax liabilities, net $ (2,090,228 ) $ (2,286,796 ) |
Lease Commitments (Tables)
Lease Commitments (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Leases [Abstract] | |
Schedule of Minimum Future Rental Commitments Under Operating Leases | At December 31, 2015 , the minimum future rental commitments under operating leases having lease terms in excess of one year are as follows: In thousands Total amount 2016 $ 3,348 2017 1,327 2018 979 2019 291 2020 210 Thereafter 3,105 Total obligations $ 9,260 |
Stock-Based Compensation (Table
Stock-Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Stock-Based Compensation Expense | The Company’s associated compensation expense, which is included in the caption “General and administrative expenses” in the consolidated statements of comprehensive income (loss), was $51.8 million , $54.4 million , and $39.9 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. |
Restricted stock [Member] | |
Summary of Changes in Non-vested Shares of Restricted Stock | A summary of changes in non-vested restricted shares from December 31, 2012 to December 31, 2015 is presented below. Number of Weighted Non-vested restricted shares at December 31, 2012 3,258,924 $ 31.64 Granted 522,518 48.98 Vested (929,618 ) 23.65 Forfeited (137,512 ) 35.96 Non-vested restricted shares at December 31, 2013 2,714,312 $ 37.50 Granted 1,424,764 61.11 Vested (1,007,166 ) 35.91 Forfeited (453,146 ) 44.90 Non-vested restricted shares at December 31, 2014 2,678,764 $ 49.40 Granted 1,462,534 46.65 Vested (555,517 ) 48.07 Forfeited (336,170 ) 51.23 Non-vested restricted shares at December 31, 2015 3,249,611 $ 48.20 |
Accumulated Other Comprehensi35
Accumulated Other Comprehensive Income (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Statement of Comprehensive Income [Abstract] | |
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block] | The following table summarizes the change in accumulated other comprehensive loss for the years ended December 31, 2015 and 2014 : Year ended December 31, In thousands 2015 2014 Beginning accumulated other comprehensive loss, net of tax $ (385 ) $ — Foreign currency translation adjustments (2,969 ) (385 ) Income tax benefit (1) — — Other comprehensive loss, net of tax (2,969 ) (385 ) Ending accumulated other comprehensive loss, net of tax $ (3,354 ) $ (385 ) (1) A valuation allowance has been recognized against deferred tax assets associated with losses generated by the Company's Canadian operations, thereby resulting in no income taxes on other comprehensive loss. |
Crude Oil and Natural Gas Pro36
Crude Oil and Natural Gas Property Information (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Schedule of Results of Operations from Crude Oil and Natural Gas Producing Activities | The following table sets forth the Company’s consolidated results of operations from crude oil and natural gas producing activities for the years ended December 31, 2015 , 2014 and 2013 . Year ended December 31, In thousands 2015 2014 2013 Crude oil and natural gas sales $ 2,552,531 $ 4,203,022 $ 3,573,431 Production expenses (348,897 ) (352,472 ) (282,197 ) Production taxes and other expenses (200,637 ) (349,760 ) (298,787 ) Exploration expenses (19,413 ) (50,067 ) (34,947 ) Depreciation, depletion, amortization and accretion (1,722,336 ) (1,338,351 ) (953,796 ) Property impairments (402,131 ) (616,888 ) (220,508 ) Income tax benefit (provision) 33,680 (559,311 ) (659,783 ) Results from crude oil and natural gas producing activities $ (107,203 ) $ 936,173 $ 1,123,413 |
Schedule of Costs Incurred in Oil and Gas Property Acquisition Exploration and Development Activities | Costs incurred, both capitalized and expensed, in connection with the Company’s consolidated crude oil and natural gas acquisition, exploration and development activities for the years ended December 31, 2015 , 2014 and 2013 are presented below: Year ended December 31, In thousands 2015 2014 2013 Property acquisition costs: Proved $ 557 $ 48,917 $ 16,604 Unproved 168,492 409,529 546,881 Total property acquisition costs 169,049 458,446 563,485 Exploration Costs 241,523 863,606 687,767 Development Costs 2,148,530 3,670,448 2,549,203 Total $ 2,559,102 $ 4,992,500 $ 3,800,455 |
Schedule of Aggregate Capitalized Costs Related to Crude Oil and Natural Gas Producing Activities | Aggregate capitalized costs relating to the Company’s consolidated crude oil and natural gas producing activities and related accumulated depreciation, depletion and amortization as of December 31, 2015 and 2014 are as follows: December 31, In thousands 2015 2014 Proved crude oil and natural gas properties $ 19,520,724 $ 17,045,967 Unproved crude oil and natural gas properties 682,988 966,080 Total 20,203,712 18,012,047 Less accumulated depreciation, depletion and amortization (6,374,218 ) (4,601,864 ) Net capitalized costs $ 13,829,494 $ 13,410,183 |
Schedule of Capitalized Exploratory Drilling Costs Pending Evaluation | The following table presents the amount of capitalized exploratory drilling costs pending evaluation at December 31 for each of the last three years and changes in those amounts during the years then ended: Year ended December 31, In thousands 2015 2014 2013 Balance at January 1 $ 93,421 $ 152,775 $ 92,699 Additions to capitalized exploratory well costs pending determination of proved reserves 132,806 627,853 548,933 Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves (160,779 ) (671,618 ) (479,507 ) Capitalized exploratory well costs charged to expense (6,051 ) (15,589 ) (9,350 ) Balance at December 31 $ 59,397 $ 93,421 $ 152,775 Number of gross wells 73 119 67 |
Supplemental Crude Oil and Na37
Supplemental Crude Oil and Natural Gas Information (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Supplemental Crude Oil and Natural Gas Information [Abstract] | |
Proved crude oil and natural gas reserves | Proved crude oil and natural gas reserves Changes in proved reserves were as follows for the periods presented: Crude Oil Natural Gas Total Proved reserves as of December 31, 2012 561,163 1,341,084 784,677 Revisions of previous estimates (55,783 ) (241,623 ) (96,054 ) Extensions, discoveries and other additions 267,009 1,065,870 444,654 Production (34,989 ) (87,730 ) (49,610 ) Sales of minerals in place — — — Purchases of minerals in place 388 419 458 Proved reserves as of December 31, 2013 737,788 2,078,020 1,084,125 Revisions of previous estimates (67,151 ) (244,783 ) (107,949 ) Extensions, discoveries and other additions 239,526 1,206,569 440,621 Production (44,530 ) (114,295 ) (63,579 ) Sales of minerals in place (123 ) (18,623 ) (3,227 ) Purchases of minerals in place 850 1,498 1,100 Proved reserves as of December 31, 2014 866,360 2,908,386 1,351,091 Revisions of previous estimates (246,840 ) (302,143 ) (297,198 ) Extensions, discoveries and other additions 134,764 710,453 253,173 Production (53,517 ) (164,454 ) (80,926 ) Sales of minerals in place (253 ) (456 ) (329 ) Purchases of minerals in place — — — Proved reserves as of December 31, 2015 700,514 3,151,786 1,225,811 |
Schedule of proved developed and undeveloped oil and gas reserve quantities | The following reserve information sets forth the estimated quantities of proved developed and proved undeveloped crude oil and natural gas reserves of the Company as of December 31, 2015 , 2014 and 2013 : December 31, 2015 2014 2013 Proved Developed Reserves Crude oil (MBbl) 326,798 342,137 278,630 Natural Gas (MMcf) 1,190,343 962,051 768,969 Total (MBoe) 525,188 502,479 406,792 Proved Undeveloped Reserves Crude oil (MBbl) 373,716 524,223 459,158 Natural Gas (MMcf) 1,961,443 1,946,335 1,309,051 Total (MBoe) 700,623 848,612 677,333 Total Proved Reserves Crude oil (MBbl) 700,514 866,360 737,788 Natural Gas (MMcf) 3,151,786 2,908,386 2,078,020 Total (MBoe) 1,225,811 1,351,091 1,084,125 |
Standardized Measure of Discounted Future Net Cash Flows | The following table sets forth the standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves as of December 31, 2015 , 2014 and 2013 . December 31, In thousands 2015 2014 2013 Future cash inflows $ 36,551,672 $ 90,867,459 $ 78,646,274 Future production costs (10,869,493 ) (25,799,221 ) (21,333,460 ) Future development and abandonment costs (6,935,958 ) (12,842,174 ) (10,250,789 ) Future income taxes (3,717,612 ) (13,800,737 ) (12,447,127 ) Future net cash flows 15,028,609 38,425,327 34,614,898 10% annual discount for estimated timing of cash flows (8,552,325 ) (19,992,293 ) (18,319,131 ) Standardized measure of discounted future net cash flows $ 6,476,284 $ 18,433,034 $ 16,295,767 |
Changes in Standardized Measure of Discounted Future Net Cash Flows | The changes in the aggregate standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves are presented below for each of the past three years. December 31, In thousands 2015 2014 2013 Standardized measure of discounted future net cash flows at January 1 $ 18,433,034 $ 16,295,767 $ 11,180,357 Extensions, discoveries and improved recoveries, less related costs 1,091,283 5,516,528 6,613,665 Revisions of previous quantity estimates (2,156,028 ) (1,755,366 ) (1,765,300 ) Changes in estimated future development and abandonment costs 5,008,731 476,665 1,942,585 Purchases (sales) of minerals in place, net (7,768 ) (3,196 ) 12,012 Net change in prices and production costs (16,111,142 ) (1,925,349 ) 263,541 Accretion of discount 1,843,303 1,629,576 1,118,036 Sales of crude oil and natural gas produced, net of production costs (2,002,997 ) (3,500,790 ) (2,992,447 ) Development costs incurred during the period 1,394,584 2,466,748 1,210,223 Change in timing of estimated future production and other (3,844,259 ) (309,902 ) 464,111 Change in income taxes 2,827,543 (457,647 ) (1,751,016 ) Net change (11,956,750 ) 2,137,267 5,115,410 Standardized measure of discounted future net cash flows at December 31 $ 6,476,284 $ 18,433,034 $ 16,295,767 |
Quarterly Financial Data (Una38
Quarterly Financial Data (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule Of Quarterly Financial Data | The Company’s unaudited quarterly financial data for 2015 and 2014 is summarized below. Quarter ended In thousands, except per share data March 31 June 30 September 30 December 31 2015 Total revenues (1) $ 625,644 $ 796,374 $ 682,669 $ 575,480 Gain (loss) on derivative instruments, net (1) $ 32,755 $ (4,737 ) $ 46,527 $ 16,540 Property impairments (2) $ 147,561 $ 76,872 $ 96,697 $ 81,001 Income (loss) from operations $ (111,276 ) $ 82,447 $ (52,356 ) $ (142,816 ) Net income (loss) $ (131,971 ) $ 403 $ (82,423 ) $ (139,677 ) Net income (loss) per share: Basic $ (0.36 ) $ — $ (0.22 ) $ (0.38 ) Diluted $ (0.36 ) $ — $ (0.22 ) $ (0.38 ) 2014 (3) (4) Total revenues (1) $ 972,495 $ 886,095 $ 1,645,328 $ 1,297,700 Gain (loss) on derivative instruments, net (1) $ (39,674 ) $ (262,524 ) $ 473,999 $ 387,958 Property impairments (2) $ 58,208 $ 79,316 $ 85,561 $ 393,803 Income from operations $ 421,317 $ 236,394 $ 944,897 $ 265,228 Net income $ 226,234 $ 103,538 $ 533,521 $ 114,048 Net income per share: Basic $ 0.61 $ 0.28 $ 1.45 $ 0.31 Diluted $ 0.61 $ 0.28 $ 1.44 $ 0.31 (1) Gains and losses on mark-to-market derivative instruments are reflected in “Total revenues” on both the consolidated statements of comprehensive income (loss) and this table of unaudited quarterly financial data. Derivative gains and losses have been shown separately to illustrate the fluctuations in revenues that are attributable to the Company’s derivative instruments. Commodity price fluctuations each quarter can result in significant swings in mark-to-market gains and losses, which affects comparability between periods. (2) Property impairments have been shown separately to illustrate the fluctuations in income (loss) that are attributable to write downs of the Company's assets. Commodity price fluctuations each quarter can result in significant changes in estimated future cash flows and resulting impairments, which affects comparability between periods. (3) The 2014 third quarter includes a $24.5 million pre-tax ( $15.4 million after tax, or $0.04 per basic and diluted share) loss on extinguishment of debt as discussed in Note 7. Long-Term Debt . (4) Balances for the fourth quarter of 2014 include $433 million of pre-tax gains ( $273 million after tax, or $0.74 per basic and diluted share) recognized from crude oil derivative contracts that were settled prior to their contractual maturities. |
Organization and Summary of S39
Organization and Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Jun. 30, 2015 | |
Organization And Summary Of Significant Accounting Policies [Line Items] | ||||
Unamortized Debt Issuance Expense | $ 64,000 | $ 69,000 | $ 65,700 | |
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount | $ 13,503 | 4,389 | $ 0 | |
Percentage of operations concentrated in geographically areas | 68.00% | |||
Percentage of estimated proved reserves in north region | 58.00% | |||
Percentage of crude oil and natural gas production concentrated in south region | 32.00% | |||
Percentage of estimated proved reserves in south region | 42.00% | |||
Percentage Of Crude Oil And Natural Gas Production Concentrated In Crude Oil | 66.00% | |||
Percentage Of Crude Oil and Natural Gas Revenue Concentrated in Crude Oil | 85.00% | |||
Cash deposits in excess of federally insured amounts | $ 10,700 | |||
Net asset retirement costs | 87,500 | 64,700 | ||
Capitalized debt issue costs, relating to long-term debt | 71,800 | 76,100 | ||
Accumulated amortization, relating to capitalized debt issue costs | 47,000 | 38,100 | ||
Amortization expense related to capitalized debt issuance costs | $ 8,900 | 9,300 | $ 8,600 | |
Percentage Of Estimated Proved Reserves Concentrated In Crude Oil | 57.00% | |||
Deferred Tax Liabilities, Net, Current | $ 36,200 | 145,300 | ||
Deferred Tax Assets, Valuation Allowance | (17,892) | (4,389) | ||
Revolving Credit Facility [Member] | ||||
Organization And Summary Of Significant Accounting Policies [Line Items] | ||||
Unamortized Debt Issuance Expense | $ 7,800 | $ 7,000 | ||
7 3/8% Senior Notes due 2020 [Member] | ||||
Organization And Summary Of Significant Accounting Policies [Line Items] | ||||
Debt instrument interest percentage | 7.375% | |||
7 1/8% Senior Notes due 2021 [Member] | ||||
Organization And Summary Of Significant Accounting Policies [Line Items] | ||||
Debt instrument interest percentage | 7.125% | |||
5% Senior Notes due 2022 [Member] | ||||
Organization And Summary Of Significant Accounting Policies [Line Items] | ||||
Debt instrument interest percentage | 5.00% | |||
4.5% Senior Notes due 2023 [Member] | ||||
Organization And Summary Of Significant Accounting Policies [Line Items] | ||||
Debt instrument interest percentage | 4.50% | |||
Largest Customer [Member] | Oil And Natural Gas [Member] | Sales [Member] | ||||
Organization And Summary Of Significant Accounting Policies [Line Items] | ||||
Percentage of crude oil sales to one single purchaser accounted on total revenues | 11.00% | |||
North Region [Member] | ||||
Organization And Summary Of Significant Accounting Policies [Line Items] | ||||
Percentage Of Revenues Concentrated In Geographically Areas | 77.00% | |||
South Region [Member] | ||||
Organization And Summary Of Significant Accounting Policies [Line Items] | ||||
Percentage Of Revenues Concentrated In Geographically Areas | 23.00% |
Organization and Summary of S40
Organization and Summary of Significant Accounting Policies - Components of Inventories (Detail) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Tubular goods and equipment | $ 15,633 | $ 15,659 |
Crude oil | 78,518 | 86,520 |
Total | $ 94,151 | $ 102,179 |
Organization and Summary of S41
Organization and Summary of Significant Accounting Policies - Schedule of Estimated Useful Lives of Service Property and Equipment (Detail) | 12 Months Ended |
Dec. 31, 2015 | |
Enterprise Resource Planning Software [Member] | |
Property, Plant and Equipment [Line Items] | |
Estimated useful lives (in years) | 25 years |
Minimum [Member] | Automobiles and Aircraft [Member] | |
Property, Plant and Equipment [Line Items] | |
Estimated useful lives (in years) | 5 years |
Minimum [Member] | Gathering Systems [Member] | |
Property, Plant and Equipment [Line Items] | |
Estimated useful lives (in years) | 15 years |
Minimum [Member] | Storage Tanks [Member] | |
Property, Plant and Equipment [Line Items] | |
Estimated useful lives (in years) | 10 years |
Minimum [Member] | Machinery and Equipment [Member] | |
Property, Plant and Equipment [Line Items] | |
Estimated useful lives (in years) | 6 years |
Minimum [Member] | Office Equipment, Computer Equipment and Software [Member] | |
Property, Plant and Equipment [Line Items] | |
Estimated useful lives (in years) | 3 years |
Minimum [Member] | Buildings And Improvements [Member] | |
Property, Plant and Equipment [Line Items] | |
Estimated useful lives (in years) | 10 years |
Maximum [Member] | Automobiles and Aircraft [Member] | |
Property, Plant and Equipment [Line Items] | |
Estimated useful lives (in years) | 10 years |
Maximum [Member] | Gathering Systems [Member] | |
Property, Plant and Equipment [Line Items] | |
Estimated useful lives (in years) | 30 years |
Maximum [Member] | Storage Tanks [Member] | |
Property, Plant and Equipment [Line Items] | |
Estimated useful lives (in years) | 30 years |
Maximum [Member] | Machinery and Equipment [Member] | |
Property, Plant and Equipment [Line Items] | |
Estimated useful lives (in years) | 10 years |
Maximum [Member] | Office Equipment, Computer Equipment and Software [Member] | |
Property, Plant and Equipment [Line Items] | |
Estimated useful lives (in years) | 10 years |
Maximum [Member] | Buildings And Improvements [Member] | |
Property, Plant and Equipment [Line Items] | |
Estimated useful lives (in years) | 40 years |
Organization and Summary of S42
Organization and Summary of Significant Accounting Policies - Summary Of Changes In Future Abandonment Liabilities (Detail) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Asset retirement obligations at January 1 | $ 76,708 | $ 55,787 | $ 47,171 | |
Accretion expense | 4,740 | 3,366 | 2,767 | |
Revisions | [1] | 15,068 | 9,916 | 2,826 |
Plus: Additions for new assets | 7,404 | 9,022 | 6,009 | |
Less: Plugging costs and sold assets | (1,011) | (1,383) | (2,986) | |
Total asset retirement obligations at December 31 | 102,909 | 76,708 | 55,787 | |
Less: Current portion of asset retirement obligations at December 31 | [2] | 1,658 | 1,246 | 1,434 |
Non-current portion of asset retirement obligations at December 31 | $ 101,251 | $ 75,462 | $ 54,353 | |
[1] | Revisions for the years ended December 31, 2015 and 2014 primarily represent an increase in the present value of liabilities from an acceleration in the estimated timing of abandonment prompted by decreases in commodity prices in 2015 and 2014 which shortened the economic lives of certain producing properties. | |||
[2] | Balance is included in the caption "Accrued liabilities and other" in the consolidated balance sheets. |
Organization and Summary of S43
Organization and Summary of Significant Accounting Policies - Earnings Per Share (Detail) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | ||||||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | [1] | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |||
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||||||||||||||
Weighted average number diluted shares excluded from calculation | 1,567,000 | |||||||||||||
Income (numerator): | ||||||||||||||
Net income - basic and diluted | $ (139,677) | $ (82,423) | $ 403 | $ (131,971) | $ 114,048 | $ 533,521 | $ 103,538 | $ 226,234 | $ (353,668) | $ 977,341 | $ 764,219 | |||
Weighted average shares - basic | 369,540,000 | 368,829,000 | 368,150,000 | |||||||||||
Non-vested restricted stock | 0 | [2] | 1,929,000 | 1,548,000 | ||||||||||
Weighted average shares - diluted | 369,540,000 | 370,758,000 | 369,698,000 | |||||||||||
Net income per share: | ||||||||||||||
Basic (in dollars per share) | $ (0.38) | $ (0.22) | $ 0 | $ (0.36) | $ 0.31 | $ 1.45 | [3] | $ 0.28 | $ 0.61 | $ (0.96) | $ 2.65 | $ 2.08 | ||
Diluted (in dollars per share) | $ (0.38) | $ (0.22) | $ 0 | $ (0.36) | $ 0.31 | $ 1.44 | [3] | $ 0.28 | $ 0.61 | $ (0.96) | $ 2.64 | $ 2.07 | ||
[1] | Balances for the fourth quarter of 2014 include $433 million of pre-tax gains ($273 million after tax, or $0.74 per basic and diluted share) recognized from crude oil derivative contracts that were settled prior to their contractual maturities. | |||||||||||||
[2] | 1)During the year ended December 31, 2015, the Company had a net loss and therefore the potential dilutive effect of approximately 1,567,000 weighted average restricted shares were not included in the calculation of diluted net loss per share for 2015 because to do so would have been anti-dilutive to the computations. | |||||||||||||
[3] | The 2014 third quarter includes a $24.5 million pre-tax ($15.4 million after tax, or $0.04 per basic and diluted share) loss on extinguishment of debt as discussed in Note 7. Long-Term Debt. |
Supplemental Cash Flow Inform44
Supplemental Cash Flow Information - Summary of Supplemental Cash Flow Information (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Supplemental cash flow information: | |||
Cash paid for interest | $ 301,743 | $ 267,384 | $ 209,815 |
Cash paid for income taxes | 30 | 53,457 | 29,017 |
Cash received for income tax refunds | 61,403 | 7 | 174 |
Change in capital expenditures incurred but not paid | (519,949) | 290,782 | 89,482 |
Non-cash investing activities: | |||
Asset retirement obligation additions and revisions, net | $ 22,472 | $ 18,938 | $ 8,835 |
Net Property and Equipment - Sc
Net Property and Equipment - Schedule of Net Property and Equipment (Detail) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Property, Plant and Equipment, Net [Abstract] | ||
Proved crude oil and natural gas properties | $ 19,520,724 | $ 17,045,967 |
Unproved crude oil and natural gas properties | 682,988 | 966,080 |
Service properties, equipment and other | 307,059 | 274,584 |
Total property and equipment | 20,510,771 | 18,286,631 |
Accumulated depreciation, depletion and amortization | (6,447,443) | (4,650,779) |
Net property and equipment | $ 14,063,328 | $ 13,635,852 |
Accrued Liabilities and Other -
Accrued Liabilities and Other - Schedule of Accrued Liabilities and Other (Detail) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Accrued Liabilities and Other Liabilities [Abstract] | ||||
Prepaid advances from joint interest owners | $ 49,917 | $ 115,687 | ||
Accrued compensation | 40,060 | 39,848 | ||
Accrued production taxes, ad valorem taxes and other non-income taxes | 21,678 | 36,550 | ||
Accrued interest | 62,058 | 60,861 | ||
Current portion of asset retirement obligations | [1] | 1,658 | 1,246 | $ 1,434 |
Other | 1,576 | 4,965 | ||
Accrued liabilities and other | $ 176,947 | $ 259,157 | ||
[1] | Balance is included in the caption "Accrued liabilities and other" in the consolidated balance sheets. |
Derivative Instruments - Summar
Derivative Instruments - Summary of Outstanding Contracts with Respect to Crude Oil (Detail) - ICE Brent [Member] - Call Option January 2016 to December 2016 [Member] | 12 Months Ended | |
Dec. 31, 2015$ / Barrelsbbl | [1] | |
Derivative [Line Items] | ||
Volume (Bbls) | bbl | 1,464,000 | |
Derivative, Average Price Risk Option Strike Price | $ / Barrels | 107.70 | |
[1] | (1) Written call options represent the ceiling positions remaining from the Company's previous crude oil collar contracts. The floor positions of the collars were liquidated in the fourth quarter of 2014. For these written call options, the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price. |
Derivative Instruments - Summ48
Derivative Instruments - Summary of Outstanding Contracts with Respect to Natural Gas (Detail) - Natural Gas [Member] | 12 Months Ended |
Dec. 31, 2015MMBTU$ / MMBTU$ / bbl | |
January 2016 to December 2016 Swaps [Member] | |
Derivative [Line Items] | |
Natural Gas Production Derivative Volume, MMBtus | MMBTU | 133,710,000 |
Swaps Weighted Average Price | $ / MMBTU | 3.17 |
January 2017 to December 2017 Swaps [Member] | |
Derivative [Line Items] | |
Natural Gas Production Derivative Volume, MMBtus | MMBTU | 25,550,000 |
Swaps Weighted Average Price | $ / MMBTU | 3.35 |
January 2017 to December 2017 Collars [Member] | |
Derivative [Line Items] | |
Derivative, Average Cap Price | 3.08 |
Natural Gas Production Derivative Volume, MMBtus | MMBTU | 65,700,000 |
Derivative, Average Floor Price | 2.47 |
Maximum [Member] | January 2017 to December 2017 Collars [Member] | |
Derivative [Line Items] | |
Derivative, Floor Price | 3 |
Derivative, Cap Price | 3.88 |
Minimum [Member] | January 2017 to December 2017 Collars [Member] | |
Derivative [Line Items] | |
Derivative, Floor Price | 2.40 |
Derivative, Cap Price | 2.92 |
Derivative Instruments - Realiz
Derivative Instruments - Realized and Unrealized Gains and Losses on Derivative Instruments (Detail) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||||||||||
Dec. 31, 2015 | [1] | Sep. 30, 2015 | [1] | Jun. 30, 2015 | [1] | Mar. 31, 2015 | [1] | Dec. 31, 2014 | Sep. 30, 2014 | [1] | Jun. 30, 2014 | [1] | Mar. 31, 2014 | [1] | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Derivatives, Fair Value [Line Items] | |||||||||||||||||||
Cash Proceeds from Liquidated Derivatives | $ 433,000 | $ 433,000 | |||||||||||||||||
Cash received (paid) on derivatives: | |||||||||||||||||||
Cash received (paid) on derivatives, net | $ 69,553 | 385,350 | $ (61,555) | ||||||||||||||||
Non-cash gain (loss) on derivatives: | |||||||||||||||||||
Non-cash gain (loss) on derivatives, net | 21,532 | 174,409 | (130,196) | ||||||||||||||||
Gain (loss) on derivative instruments, net | $ 16,540 | $ 46,527 | $ (4,737) | $ 32,755 | $ 387,958 | [1],[2] | $ 473,999 | $ (262,524) | $ (39,674) | 91,085 | 559,759 | (191,751) | |||||||
Fixed Price Swaps [Member] | Crude Oil [Member] | |||||||||||||||||||
Derivatives, Fair Value [Line Items] | |||||||||||||||||||
Cash Proceeds from Liquidated Derivatives | 373,000 | ||||||||||||||||||
Cash received (paid) on derivatives: | |||||||||||||||||||
Cash received (paid) on derivatives, net | 0 | 331,591 | (54,289) | ||||||||||||||||
Non-cash gain (loss) on derivatives: | |||||||||||||||||||
Non-cash gain (loss) on derivatives, net | 0 | 84,792 | (117,580) | ||||||||||||||||
Fixed Price Swaps [Member] | Natural Gas [Member] | |||||||||||||||||||
Cash received (paid) on derivatives: | |||||||||||||||||||
Cash received (paid) on derivatives, net | 39,670 | (11,551) | 9,601 | ||||||||||||||||
Non-cash gain (loss) on derivatives: | |||||||||||||||||||
Non-cash gain (loss) on derivatives, net | 41,828 | 62,699 | (4,029) | ||||||||||||||||
Collars [Member] | Crude Oil [Member] | |||||||||||||||||||
Derivatives, Fair Value [Line Items] | |||||||||||||||||||
Cash Proceeds from Liquidated Derivatives | 60,000 | ||||||||||||||||||
Cash received (paid) on derivatives: | |||||||||||||||||||
Cash received (paid) on derivatives, net | 0 | 65,310 | (16,867) | ||||||||||||||||
Non-cash gain (loss) on derivatives: | |||||||||||||||||||
Non-cash gain (loss) on derivatives, net | 0 | 1,121 | (8,587) | ||||||||||||||||
Collars [Member] | Natural Gas [Member] | |||||||||||||||||||
Cash received (paid) on derivatives: | |||||||||||||||||||
Cash received (paid) on derivatives, net | 29,883 | 0 | 0 | ||||||||||||||||
Non-cash gain (loss) on derivatives: | |||||||||||||||||||
Non-cash gain (loss) on derivatives, net | (25,011) | 21,816 | 0 | ||||||||||||||||
Call Option [Member] | Crude Oil [Member] | |||||||||||||||||||
Non-cash gain (loss) on derivatives: | |||||||||||||||||||
Non-cash gain (loss) on derivatives, net | $ 4,715 | $ 3,981 | $ 0 | ||||||||||||||||
[1] | Gains and losses on mark-to-market derivative instruments are reflected in “Total revenues” on both the consolidated statements of comprehensive income (loss) and this table of unaudited quarterly financial data. Derivative gains and losses have been shown separately to illustrate the fluctuations in revenues that are attributable to the Company’s derivative instruments. Commodity price fluctuations each quarter can result in significant swings in mark-to-market gains and losses, which affects comparability between periods. | ||||||||||||||||||
[2] | Balances for the fourth quarter of 2014 include $433 million of pre-tax gains ($273 million after tax, or $0.74 per basic and diluted share) recognized from crude oil derivative contracts that were settled prior to their contractual maturities. |
Derivative Instruments Derivati
Derivative Instruments Derivative Instruments - Gross Amounts of Recognized Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Derivative [Line Items] | ||
Commodity derivative assets, Gross amounts of recognized assets | $ 120,385 | $ 84,431 |
Commodity derivative assets, Gross amounts offset on balance sheet | (11,903) | (16) |
Derivative assets, Net amounts of assets on balance sheet | 108,482 | 84,415 |
Commodity derivative liability, Gross amounts of recognized liabilities | (19,192) | (4,770) |
Commodity derivative liability, Gross amounts offset on balance sheet | 11,903 | 16 |
Derivative liability, Net amounts of liabilities on balance sheet | $ (7,289) | $ (4,754) |
Derivative Instruments Deriva51
Derivative Instruments Derivative Instruments - Reconciles Net Amounts Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Derivative assets | $ 93,922 | $ 52,423 |
Noncurrent derivative assets | 14,560 | 31,992 |
Derivative assets, Net amounts of assets on balance sheet | 108,482 | 84,415 |
Derivative liabilities | (3,583) | (1,645) |
Noncurrent derivative liabilities | (3,706) | (3,109) |
Derivative liability, Net amounts of liabilities on balance sheet | (7,289) | (4,754) |
Total derivative assets, net | $ 101,193 | $ 79,661 |
Fair Value Measurements - Valua
Fair Value Measurements - Valuation of Financial Instruments by Pricing Levels (Detail) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | $ 101,193 | $ 79,661 |
Fair Value, Inputs, Level 1 [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | 0 | 0 |
Fair Value, Inputs, Level 1 [Member] | Fixed Price Swaps [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | 0 | 0 |
Fair Value, Inputs, Level 1 [Member] | Collars [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | 0 | 0 |
Fair Value, Inputs, Level 1 [Member] | Call Option [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | 0 | 0 |
Fair Value, Inputs, Level 2 [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | 101,193 | 79,661 |
Fair Value, Inputs, Level 2 [Member] | Fixed Price Swaps [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | 104,426 | 62,599 |
Fair Value, Inputs, Level 2 [Member] | Collars [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | (3,195) | 21,816 |
Fair Value, Inputs, Level 2 [Member] | Call Option [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | (38) | (4,754) |
Fair Value, Inputs, Level 3 [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | 0 | 0 |
Fair Value, Inputs, Level 3 [Member] | Fixed Price Swaps [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | 0 | 0 |
Fair Value, Inputs, Level 3 [Member] | Collars [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | 0 | 0 |
Fair Value, Inputs, Level 3 [Member] | Call Option [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | 0 | 0 |
Fair Value [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | 101,193 | 79,661 |
Fair Value [Member] | Fixed Price Swaps [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | 104,426 | 62,599 |
Fair Value [Member] | Collars [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | (3,195) | 21,816 |
Fair Value [Member] | Call Option [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | $ (38) | $ (4,754) |
Fair Value Measurements - Addit
Fair Value Measurements - Additional Information (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Fair Value Measurements [Line Items] | |||
Operating cost escalation assumption used in impairment assessment | 3.00% | ||
Discount factor utilized as standardized measure for future net cash flows | 10.00% | ||
Impairments of proved properties | $ 138,878 | $ 324,302 | $ 51,805 |
Estimated fair value of proved properties | $ 59,900 | ||
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) | 34 years | ||
Forward Commodity Prices [Member] | |||
Fair Value Measurements [Line Items] | |||
Forward commodity price escalation assumption used in impairment assessment | 3.00% |
Fair Value Measurements - Prope
Fair Value Measurements - Property Impairments (Detail) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||||||||||
Dec. 31, 2015 | [1] | Sep. 30, 2015 | [1] | Jun. 30, 2015 | [1] | Mar. 31, 2015 | [1] | Dec. 31, 2014 | [1] | Sep. 30, 2014 | [1] | Jun. 30, 2014 | [1] | Mar. 31, 2014 | [1] | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||
Proved property impairments | $ 138,878 | $ 324,302 | $ 51,805 | ||||||||||||||||
Unproved property impairments | 263,253 | 292,586 | 168,703 | ||||||||||||||||
Total | $ 81,001 | $ 96,697 | $ 76,872 | $ 147,561 | $ 393,803 | $ 85,561 | $ 79,316 | $ 58,208 | 402,131 | $ 616,888 | $ 220,508 | ||||||||
Buffalo Red River Units [Member] | |||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||
Proved property impairments | 26,300 | ||||||||||||||||||
Medicine Pole Hill Units [Member] | |||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||
Proved property impairments | 32,500 | ||||||||||||||||||
South Region [Member] | |||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||
Proved property impairments | 11,400 | ||||||||||||||||||
Non-Bakken North Region [Member] | |||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||
Proved property impairments | 8,200 | ||||||||||||||||||
WYOMING | |||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||
Proved property impairments | 17,900 | ||||||||||||||||||
Emerging Areas [Member] | |||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||
Proved property impairments | $ 42,500 | ||||||||||||||||||
[1] | Property impairments have been shown separately to illustrate the fluctuations in income (loss) that are attributable to write downs of the Company's assets. Commodity price fluctuations each quarter can result in significant changes in estimated future cash flows and resulting impairments, which affects comparability between periods. |
Fair Value Measurements - Fair
Fair Value Measurements - Fair Values of Financial Instruments not Recorded at Fair Value (Detail) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
7 3/8% Senior Notes due 2020 [Member] | ||
Fair Value Measurements [Line Items] | ||
Debt instrument, maturity date | 2,020 | |
Debt instrument, stated interest rate | 7.375% | |
7 1/8% Senior Notes due 2021 [Member] | ||
Fair Value Measurements [Line Items] | ||
Debt instrument, maturity date | 2,021 | |
Debt instrument, stated interest rate | 7.125% | |
5% Senior Notes due 2022 [Member] | ||
Fair Value Measurements [Line Items] | ||
Debt instrument, maturity date | 2,022 | |
Debt instrument, stated interest rate | 5.00% | |
4 1/2% Senior Notes due 2023 [Member] | ||
Fair Value Measurements [Line Items] | ||
Debt instrument, maturity date | 2,023 | |
Debt instrument, stated interest rate | 4.50% | |
3.8% Senior Notes due 2024 [Member] | ||
Fair Value Measurements [Line Items] | ||
Debt instrument, maturity date | 2,024 | |
Debt instrument, stated interest rate | 3.80% | |
Senior notes | $ 988,940 | |
4.9% Senior Notes due 2044 [Member] | ||
Fair Value Measurements [Line Items] | ||
Debt instrument, maturity date | 2,044 | |
Debt instrument, stated interest rate | 4.90% | |
Senior notes | 690,912 | |
Carrying Amount [Member] | ||
Fair Value Measurements [Line Items] | ||
Revolving credit facility | $ 853,000 | 165,000 |
Term loan | 0 | |
Note payable | 14,309 | 16,375 |
Total debt | 7,117,788 | 5,928,878 |
Carrying Amount [Member] | 7 3/8% Senior Notes due 2020 [Member] | ||
Fair Value Measurements [Line Items] | ||
Senior notes | 196,574 | 195,997 |
Carrying Amount [Member] | 7 1/8% Senior Notes due 2021 [Member] | ||
Fair Value Measurements [Line Items] | ||
Senior notes | 395,365 | 394,668 |
Carrying Amount [Member] | 5% Senior Notes due 2022 [Member] | ||
Fair Value Measurements [Line Items] | ||
Senior notes | 1,996,831 | 1,996,507 |
Carrying Amount [Member] | 4 1/2% Senior Notes due 2023 [Member] | ||
Fair Value Measurements [Line Items] | ||
Senior notes | 1,482,451 | 1,480,479 |
Carrying Amount [Member] | 3.8% Senior Notes due 2024 [Member] | ||
Fair Value Measurements [Line Items] | ||
Senior notes | 989,932 | 988,940 |
Carrying Amount [Member] | 4.9% Senior Notes due 2044 [Member] | ||
Fair Value Measurements [Line Items] | ||
Senior notes | 691,052 | 690,912 |
Fair Value [Member] | ||
Fair Value Measurements [Line Items] | ||
Revolving credit facility | 853,000 | 165,000 |
Term loan | 500,000 | 0 |
Note payable | 12,500 | 14,900 |
Total debt | 5,605,200 | 5,485,700 |
Fair Value [Member] | 7 3/8% Senior Notes due 2020 [Member] | ||
Fair Value Measurements [Line Items] | ||
Senior notes | 179,200 | 213,000 |
Fair Value [Member] | 7 1/8% Senior Notes due 2021 [Member] | ||
Fair Value Measurements [Line Items] | ||
Senior notes | 388,300 | 421,000 |
Fair Value [Member] | 5% Senior Notes due 2022 [Member] | ||
Fair Value Measurements [Line Items] | ||
Senior notes | 1,480,400 | 1,857,900 |
Fair Value [Member] | 4 1/2% Senior Notes due 2023 [Member] | ||
Fair Value Measurements [Line Items] | ||
Senior notes | 1,061,000 | 1,372,800 |
Fair Value [Member] | 3.8% Senior Notes due 2024 [Member] | ||
Fair Value Measurements [Line Items] | ||
Senior notes | 700,300 | 868,700 |
Fair Value [Member] | 4.9% Senior Notes due 2044 [Member] | ||
Fair Value Measurements [Line Items] | ||
Senior notes | $ 430,500 | $ 572,400 |
Long-Term Debt - Long-Term Debt
Long-Term Debt - Long-Term Debt (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Debt Instrument [Line Items] | |||
Unamortized Loan Commitment and Origination Fees and Unamortized Discounts or Premiums | $ 49,600 | $ 52,600 | |
Less: Current portion of long-term debt | (2,144) | (2,078) | |
Long-term debt, net of current portion | 7,115,644 | 5,926,800 | |
Loss on extinguishment of debt | 0 | (24,517) | $ 0 |
Term Loan | $ 500,000 | ||
8 1/4% Senior Notes due 2019 [Member] | |||
Debt Instrument [Line Items] | |||
Total Redemption Amount | 317,500 | ||
7 3/8% Senior Notes due 2020 [Member] | |||
Debt Instrument [Line Items] | |||
Debt instrument, stated interest rate | 7.375% | ||
7 1/8% Senior Notes due 2021 [Member] | |||
Debt Instrument [Line Items] | |||
Debt instrument, stated interest rate | 7.125% | ||
5% Senior Notes due 2022 [Member] | |||
Debt Instrument [Line Items] | |||
Debt instrument, stated interest rate | 5.00% | ||
4.5% Senior Notes due 2023 [Member] | |||
Debt Instrument [Line Items] | |||
Debt instrument, stated interest rate | 4.50% | ||
3.8% Senior Notes due 2024 [Member] | |||
Debt Instrument [Line Items] | |||
Senior notes | 988,940 | ||
Debt instrument, stated interest rate | 3.80% | ||
4.9% Senior Notes due 2044 [Member] | |||
Debt Instrument [Line Items] | |||
Senior notes | 690,912 | ||
Debt instrument, stated interest rate | 4.90% | ||
Revolving Credit Facility [Member] | |||
Debt Instrument [Line Items] | |||
Line of Credit Facility, Remaining Borrowing Capacity | $ 1,900,000 | ||
Carrying Amount [Member] | |||
Debt Instrument [Line Items] | |||
Revolving credit facility | 853,000 | 165,000 | |
Note payable | 14,309 | 16,375 | |
Total debt | 7,117,788 | 5,928,878 | |
Term Loan | 498,274 | 0 | |
Carrying Amount [Member] | 7 3/8% Senior Notes due 2020 [Member] | |||
Debt Instrument [Line Items] | |||
Senior notes | 196,574 | 195,997 | |
Carrying Amount [Member] | 7 1/8% Senior Notes due 2021 [Member] | |||
Debt Instrument [Line Items] | |||
Senior notes | 395,365 | 394,668 | |
Carrying Amount [Member] | 5% Senior Notes due 2022 [Member] | |||
Debt Instrument [Line Items] | |||
Senior notes | 1,996,831 | 1,996,507 | |
Carrying Amount [Member] | 4.5% Senior Notes due 2023 [Member] | |||
Debt Instrument [Line Items] | |||
Senior notes | 1,482,451 | 1,480,479 | |
Carrying Amount [Member] | 3.8% Senior Notes due 2024 [Member] | |||
Debt Instrument [Line Items] | |||
Senior notes | 989,932 | 988,940 | |
Carrying Amount [Member] | 4.9% Senior Notes due 2044 [Member] | |||
Debt Instrument [Line Items] | |||
Senior notes | $ 691,052 | $ 690,912 |
Long-Term Debt - Additional Inf
Long-Term Debt - Additional Information (Detail) - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Debt Instrument [Line Items] | |||
Loss on extinguishment of debt | $ 0 | $ (24,517,000) | $ 0 |
Aggregate amount of lender commitments on credit facility | 2,750,000,000 | ||
Maximum borrowing capacity | $ 4,000,000,000 | ||
Line of credit facility, commitment fee percentage, per annum | 0.225% | ||
Line of Credit Facility, Covenant Terms | 0.65 | ||
Proceeds from issuance of Senior Notes | $ 0 | 1,681,834,000 | 1,479,375,000 |
Repayments of Lines of Credit | 1,313,000,000 | 1,805,000,000 | $ 1,290,000,000 |
Current portion of long-term debt | 2,144,000 | 2,078,000 | |
Revolving Credit Facility [Member] | |||
Debt Instrument [Line Items] | |||
Line of Credit Facility, Remaining Borrowing Capacity | $ 1,900,000,000 | ||
Credit Facility [Domain] | |||
Debt Instrument [Line Items] | |||
Debt, Weighted Average Interest Rate | 1.90% | ||
Note Payable [Member] | |||
Debt Instrument [Line Items] | |||
Notes Payable | $ 22,000,000 | ||
Loan period, in years | 10 years | ||
Debt instrument, stated interest rate | 3.14% | ||
Debt instrument, maturity date | Feb. 26, 2022 | ||
5% Senior Notes due 2022 [Member] | |||
Debt Instrument [Line Items] | |||
Debt instrument, stated interest rate | 5.00% | ||
Senior Notes Due 2023 [Member] | |||
Debt Instrument [Line Items] | |||
Debt instrument, maturity date | Apr. 15, 2023 | ||
4.5% Senior Notes due 2023 [Member] | |||
Debt Instrument [Line Items] | |||
Debt instrument, stated interest rate | 4.50% | ||
3.8% Senior Notes due 2024 [Member] | |||
Debt Instrument [Line Items] | |||
Senior notes | 988,940,000 | ||
Debt instrument, stated interest rate | 3.80% | ||
4.9% Senior Notes due 2044 [Member] | |||
Debt Instrument [Line Items] | |||
Senior notes | 690,912,000 | ||
Debt instrument, stated interest rate | 4.90% | ||
8 1/4% Senior Notes due 2019 [Member] | |||
Debt Instrument [Line Items] | |||
Total Redemption Amount | 317,500,000 | ||
Loans Payable [Member] | |||
Debt Instrument [Line Items] | |||
Debt, Weighted Average Interest Rate | 1.80% | ||
Carrying Amount [Member] | |||
Debt Instrument [Line Items] | |||
Line of credit facility, amount outstanding | $ 853,000,000 | 165,000,000 | |
Notes Payable | 14,309,000 | 16,375,000 | |
Carrying Amount [Member] | 5% Senior Notes due 2022 [Member] | |||
Debt Instrument [Line Items] | |||
Senior notes | 1,996,831,000 | 1,996,507,000 | |
Carrying Amount [Member] | 4.5% Senior Notes due 2023 [Member] | |||
Debt Instrument [Line Items] | |||
Senior notes | 1,482,451,000 | 1,480,479,000 | |
Carrying Amount [Member] | 3.8% Senior Notes due 2024 [Member] | |||
Debt Instrument [Line Items] | |||
Senior notes | 989,932,000 | 988,940,000 | |
Carrying Amount [Member] | 4.9% Senior Notes due 2044 [Member] | |||
Debt Instrument [Line Items] | |||
Senior notes | $ 691,052,000 | $ 690,912,000 |
Long-Term Debt - Summary of Mat
Long-Term Debt - Summary of Maturity Dates, Semi-Annual Interest Payment Dates, and Optional Redemption Periods Of Outstanding Senior Note Obligations (Detail) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015USD ($) | ||
2020 Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt Instrument, Face Amount | $ 200,000 | |
Maturity date | Oct. 1, 2020 | |
Interest Payment Dates | April 1, Oct 1 | |
Decreasing call premium redemption period | Oct. 1, 2015 | |
Make-whole redemption period | Oct. 1, 2015 | |
2021 Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt Instrument, Face Amount | $ 400,000 | |
Maturity date | Apr. 1, 2021 | |
Interest Payment Dates | April 1, Oct 1 | |
Decreasing call premium redemption period | Apr. 1, 2016 | [1] |
Make-whole redemption period | Apr. 1, 2016 | [2] |
2022 Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt Instrument, Face Amount | $ 2,000,000 | |
Maturity date | Sep. 15, 2022 | |
Interest Payment Dates | March 15, Sep 15 | |
Decreasing call premium redemption period | Mar. 15, 2017 | [1] |
Make-whole redemption period | Mar. 15, 2017 | [2] |
Senior Notes Due 2023 [Member] | ||
Debt Instrument [Line Items] | ||
Debt Instrument, Face Amount | $ 1,500,000 | |
Maturity date | Apr. 15, 2023 | |
Interest Payment Dates | April 15, Oct 15 | |
Make-whole redemption period | Jan. 15, 2023 | [2] |
Senior Notes due 2024 [Member] | ||
Debt Instrument [Line Items] | ||
Debt Instrument, Face Amount | $ 1,000,000 | |
Maturity date | Jun. 1, 2024 | |
Interest Payment Dates | June 1, Dec 1 | |
Make-whole redemption period | Mar. 1, 2024 | [2] |
Senior Notes due 2044 [Member] | ||
Debt Instrument [Line Items] | ||
Debt Instrument, Face Amount | $ 700,000 | |
Maturity date | Jun. 1, 2044 | |
Interest Payment Dates | June 1, Dec 1 | |
Make-whole redemption period | Dec. 1, 2043 | [2] |
[1] | On or after these dates, the Company has the option to redeem all or a portion of its senior notes of the applicable series at the decreasing redemption prices specified in the respective senior note indentures (together, the “Indentures”) plus any accrued and unpaid interest to the date of redemption. | |
[2] | At any time prior to these dates, the Company has the option to redeem all or a portion of its senior notes of the applicable series at the “make-whole” redemption prices or amounts specified in the Indentures plus any accrued and unpaid interest to the date of redemption. |
Income Taxes - Provision for In
Income Taxes - Provision for Income Taxes (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Income Tax Disclosure [Abstract] | |||
Current tax provision, Federal | $ 0 | $ 0 | $ 6,193 |
Current tax provision, State | 24 | 20 | 16 |
Total current income tax provision | 24 | 20 | 6,209 |
Deferred tax provision, Federal | (140,578) | 527,315 | 403,002 |
Deferred tax provision, State | (40,863) | 57,362 | 39,619 |
Total deferred income tax provision (benefit) | (181,441) | 584,677 | 442,621 |
Provision (benefit) for income taxes | $ (181,417) | $ 584,697 | $ 448,830 |
Income Taxes - Schedule of Prov
Income Taxes - Schedule of Provision for Income Taxes with Income Tax at Federal Statutory Rate (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Income Tax Disclosure [Abstract] | |||
Expected income tax expense (benefit) based on US statutory tax rate of 35% | $ (187,280) | $ 546,713 | $ 424,567 |
State income taxes, net of federal benefit | (16,219) | 42,169 | 25,838 |
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount | 13,503 | 4,389 | 0 |
Effect of differing statutory tax rate in Canada | 5,239 | (1,900) | 0 |
Other, net | 3,340 | (6,674) | (1,575) |
Provision (benefit) for income taxes | $ (181,417) | $ 584,697 | $ 448,830 |
Federal statutory income tax rate | 35.00% |
Income Taxes - Components of De
Income Taxes - Components of Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Income Tax Disclosure [Abstract] | ||
Deferred tax assets, Net operating loss carryforwards, Noncurrent | $ 398,024 | $ 60,904 |
Deferred tax assets, Non-cash losses on derivatives, Noncurrent | 17,892 | 4,899 |
Deferred tax assets, Alternative minimum tax carryforwards, Noncurrent | 40,796 | 38,715 |
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Share-based Compensation Cost | 32,910 | 22,255 |
Deferred Tax Assets, Other | 11,048 | 8,920 |
Total noncurrent deferred tax assets | 500,670 | 135,693 |
Deferred Tax Assets, Valuation Allowance | (17,892) | (4,389) |
Deferred Tax Assets, Net, Noncurrent | 482,778 | 131,304 |
Deferred tax liabilities, Property and equipment, Noncurrent | (2,528,125) | (2,254,343) |
Deferred Tax Liabilities Unrealized Gains on Derivatives, noncurrent | (38,452) | (30,269) |
Deferred tax liabilities, Non-cash gains on derivatives, Noncurrent | (4,158) | (132,356) |
Deferred Tax Liabilities, Other | (2,271) | (1,132) |
Total noncurrent deferred tax liabilities | (2,573,006) | (2,418,100) |
Net noncurrent deferred tax liabilities | $ (2,090,228) | $ (2,286,796) |
Income Taxes - Additional Infor
Income Taxes - Additional Information (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Operating Loss Carryforwards [Line Items] | |||
Net operating loss carryforwards, State | $ 2,630,000 | ||
Alternative minimum tax credit carryforward | 41,000 | ||
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount | 13,503 | $ 4,389 | $ 0 |
Deferred Tax Assets, Valuation Allowance | (17,892) | $ (4,389) | |
UNITED STATES | |||
Operating Loss Carryforwards [Line Items] | |||
Federal Operating Loss Carryforwards | 865,000 | ||
Oklahoma [Member] | |||
Operating Loss Carryforwards [Line Items] | |||
Net operating loss carryforwards, State | $ 2,120,000 |
Lease Commitments - Lease Commi
Lease Commitments - Lease Commitments (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Leases [Abstract] | |||
Lease expenses associated with operating leases | $ 9,600 | $ 8,000 | $ 3,000 |
2,014 | 3,348 | ||
2,015 | 1,327 | ||
2,016 | 979 | ||
2,017 | 291 | ||
2,018 | 210 | ||
Thereafter | 3,105 | ||
Total obligations | $ 9,260 |
Commitments and Contingencies -
Commitments and Contingencies - Additional Information (Detail) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Long-term Purchase Commitment [Line Items] | ||
Total future drilling commitments at balance sheet date | $ 422 | |
Drilling commitments 2016 | 200 | |
Drilling commitments 2017 | 136 | |
Drilling commitments 2018 | 62 | |
Drilling commitments 2019 | 24 | |
Damages claimed related to contingency matter | 200 | |
Legal proceedings recorded as a liability under other noncurrent liabilities | $ 6.1 | $ 2.9 |
Future Drilling Commitments End Date | 2019-12 | |
Pipeline Transportation Commitments [Member] | ||
Long-term Purchase Commitment [Line Items] | ||
Future commitment, end date | 2,027 | |
Future commitment, total | $ 1,000 | |
Future commitment, due in 2016 | 215 | |
Future commitment, due in 2017 | 212 | |
Future commitment, due in 2018 | 207 | |
Future commitment, due in 2019 | 154 | |
Future commitment, due in 2020 | 47 | |
Future commitments, thereafter | 170 | |
Non-operational Pipeline Transportation Commitments[Member] | ||
Long-term Purchase Commitment [Line Items] | ||
Future commitment, total | 260 | |
Fuel [Member] | ||
Long-term Purchase Commitment [Line Items] | ||
Future commitment, total | $ 31 |
Related Party Transactions - Ad
Related Party Transactions - Additional Information (Detail) | 12 Months Ended | ||
Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($)bbl | |
Related Party Transaction [Line Items] | |||
Revenues from transactions with related party | $ 1,400,000 | $ 95,128,000 | $ 100,405,000 |
Due from affiliates | 13,100,000 | ||
Due to Affiliate | 300,000 | ||
Related party transaction, due to related party | 1,200,000 | ||
Production expenses to affiliates | 1,654,000 | 5,123,000 | 1,408,000 |
Total amount paid to related party | 7,700,000 | 58,200,000 | 48,500,000 |
Due to affiliates | 5,600,000 | ||
Amount charged to affiliate for aircraft use | 9,600 | 51,000 | 55,000 |
Amount charged to company by affiliate for aircraft use | 236,000 | 97,000 | $ 51,000 |
Affiliated Entity [Member] | |||
Related Party Transaction [Line Items] | |||
Number of barrels purchased from affiliate | bbl | 30,000 | ||
Purchases from transactions with related party | $ 3,000,000 | ||
Expenses from transactions with related party | 8,800,000 | 1,800,000 | |
Capitalized costs | 2,600,000 | 5,900,000 | 5,700,000 |
Production expenses to affiliates | 1,700,000 | 5,100,000 | 1,400,000 |
Total amount paid to related party | 9,200,000 | 1,900,000 | |
Officers And Other Key Employees [Member] | |||
Related Party Transaction [Line Items] | |||
Revenues from transactions with related party | 500,000 | 800,000 | 1,300,000 |
Due to affiliates | 52,000 | 133,000 | |
Revenues paid to related party | 700,000 | 1,700,000 | 2,300,000 |
Due from affiliates | 106,000 | 207,000 | |
Other Affiliates [Member] | |||
Related Party Transaction [Line Items] | |||
Total amount paid to related party | 221,000 | 34,000 | 238,000 |
Total amount received from related party | $ 33,000 | 39,000 | 379,000 |
Affiliated Entity [Member] | |||
Related Party Transaction [Line Items] | |||
Revenues from transactions with related party | $ 95,100,000 | $ 100,400,000 |
Stock Based Compensation - Asso
Stock Based Compensation - Associated Compensation Expense (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||
Stock-based compensation | $ 51,834 | $ 54,353 | $ 39,890 |
Stock-Based Compensation - Addi
Stock-Based Compensation - Additional Information (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Restricted stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Fair value at vesting date | $ 23.6 | $ 58.2 | $ 49.4 |
Unrecognized compensation expense related to non-vested | $ 67 | ||
Unrecognized compensation expense related to non-vested, period for recognition, in years | 1 year 2 months | ||
Restricted stock [Member] | Minimum [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Grants vest over periods, in years | 1 year | ||
Restricted stock [Member] | Maximum [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Grants vest over periods, in years | 3 years | ||
2013 Plan [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Common stock available for issue | 19,680,072 | ||
2013 Plan [Member] | Restricted stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock available to grant | 17,028,213 |
Stock Based Compensation - Summ
Stock Based Compensation - Summary of Changes in Non Vested Shares of Restricted Stock (Detail) - $ / shares | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |||
Non-vested shares, beginning balance | 2,678,764 | 2,714,312 | 3,258,924 |
Granted shares | 1,462,534 | 1,424,764 | 522,518 |
Vested shares | (555,517) | (1,007,166) | (929,618) |
Forfeited shares | (336,170) | (453,146) | (137,512) |
Non-vested shares, ending balance | 3,249,611 | 2,678,764 | 2,714,312 |
Non-vested, weighted average grant-date fair value, beginning of period | $ 49.40 | $ 37.50 | $ 31.64 |
Granted, weighted average grant-date fair value | 46.65 | 61.11 | 48.98 |
Vested, weighted average grant-date fair value | 48.07 | 35.91 | 23.65 |
Forfeited, weighted average grant-date fair value | 51.23 | 44.90 | 35.96 |
Non-vested, weighted average grant-date fair value, end of period | $ 48.20 | $ 49.40 | $ 37.50 |
Accumulated Other Comprehensi69
Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Foreign Currency [Abstract] | ||||
Foreign currency translation adjustments | $ (2,969) | $ (385) | $ 0 | |
Translation Adjustment Functional to Reporting Currency, Tax Benefit (Expense) | [1] | 0 | 0 | |
Other Comprehensive Income (Loss), Net of Tax | (2,969) | (385) | 0 | |
Accumulated other comprehensive loss | $ (3,354) | $ (385) | $ 0 | |
[1] | A valuation allowance has been recognized against deferred tax assets associated with losses generated by the Company's Canadian operations, thereby resulting in no income taxes on other comprehensive loss. |
Property Dispositions - Additio
Property Dispositions - Additional Information (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Property Acquisition And Dispositions [Line Items] | |||
Proceeds from sale of assets and other | $ 34,008 | $ 129,388 | $ 28,420 |
Proceeds from sale of non-producing leasehold | 25,900 | ||
Gain (Loss) on disposition of non-producing leasehold | $ 20,500 | ||
Niobrara [Domain] | |||
Property Acquisition And Dispositions [Line Items] | |||
Proceeds from sale of assets and other | 30,300 | ||
Northwest Cana [Member] | |||
Property Acquisition And Dispositions [Line Items] | |||
Proceeds from sale of assets and other | $ 85,800 |
Crude Oil and Natural Gas Pro71
Crude Oil and Natural Gas Property Information - Schedule of Results of Operations from Crude Oil and Natural Gas Producing Activities (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |||
Crude oil and natural gas sales | $ 2,552,531 | $ 4,203,022 | $ 3,573,431 |
Production expenses | (348,897) | (352,472) | (282,197) |
Production taxes and other expenses | (200,637) | (349,760) | (298,787) |
Exploration Expense | (19,413) | (50,067) | (34,947) |
Depreciation, depletion, amortization and accretion | (1,722,336) | (1,338,351) | (953,796) |
Property impairments | (402,131) | (616,888) | (220,508) |
Income tax benefit (provision) | 33,680 | (559,311) | (659,783) |
Results from crude oil and natural gas producing activities | $ (107,203) | $ 936,173 | $ 1,123,413 |
Crude Oil and Natural Gas Pro72
Crude Oil and Natural Gas Property Information - Schedule of Costs Incurred in Oil and Gas Property Acquisition Exploration and Development Activities (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |||
Property Acquisition Costs - Proved | $ 557 | $ 48,917 | $ 16,604 |
Property Acquisition Costs - Unproved | 168,492 | 409,529 | 546,881 |
Total property acquisition costs | 169,049 | 458,446 | 563,485 |
Exploration Costs | 241,523 | 863,606 | 687,767 |
Development Costs | 2,148,530 | 3,670,448 | 2,549,203 |
Total | $ 2,559,102 | $ 4,992,500 | $ 3,800,455 |
Crude Oil and Natural Gas Pro73
Crude Oil and Natural Gas Property Information - Additional Information (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |||
Exploration costs included in asset retirement costs | $ 3.3 | $ 1.2 | $ 1.8 |
Development costs included in asset retirement costs | $ 19.5 | $ 19.1 | $ 6 |
Crude Oil and Natural Gas Pro74
Crude Oil and Natural Gas Property Information - Schedule of Aggregate Capitalized Costs Relates to Crude Oil and Natural Gas Producing Activities (Detail) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | ||
Proved crude oil and natural gas properties | $ 19,520,724 | $ 17,045,967 |
Unproved crude oil and natural gas properties | 682,988 | 966,080 |
Total | 20,203,712 | 18,012,047 |
Less accumulated depreciation, depletion and amortization | (6,374,218) | (4,601,864) |
Net capitalized costs | $ 13,829,494 | $ 13,410,183 |
Crude Oil and Natural Gas Pro75
Crude Oil and Natural Gas Property Information - Schedule of Capitalized Exploratory Drilling Costs Pending Evaluation (Detail) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015USD ($)Well | Dec. 31, 2014USD ($)Well | Dec. 31, 2013USD ($)Well | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |||
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year | $ 1,700 | ||
Number Of Wells With Capitalized Exploratory Well Costs Suspended One Year Beyond Completion Of Drilling | 3 | ||
Suspended Well Costs Incurred | $ 100 | $ 1,600 | |
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward] | |||
Balance at January 1 | $ 93,421 | 152,775 | 92,699 |
Additions to capitalized exploratory well costs pending determination of proved reserves | 132,806 | 627,853 | 548,933 |
Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves | (160,779) | (671,618) | (479,507) |
Capitalized exploratory well costs charged to expense | (6,051) | (15,589) | (9,350) |
Balance at December 31 | $ 59,397 | $ 93,421 | $ 152,775 |
Number of wells | Well | 73 | 119 | 67 |
Supplemental Crude Oil and Na76
Supplemental Crude Oil and Natural Gas Information - Additional Information (Detail) | 12 Months Ended | ||||||
Dec. 31, 2015 | Dec. 31, 2015$ / Barrels | Dec. 31, 2015MBoe | Dec. 31, 2015MBbls | Dec. 31, 2015MMcf | Dec. 31, 2014$ / bbl$ / McfMBoeMBblsMMcf | Dec. 31, 2013$ / bbl$ / McfMBoeMBblsMMcf | |
Reserve Quantities [Line Items] | |||||||
Percentage of discounted future net cash flows prepared by external reserve engineers | 99.00% | 99.00% | 99.00% | ||||
Percent of proved crude oil reserve estimates prepared by external reserve engineers | 99.00% | ||||||
Percent of proved natural gas reserve estimates prepared by external reserve engineers | 97.00% | ||||||
Revisions of previous estimates | MBoe | (297,198) | (107,949) | (96,054) | ||||
Extensions, discoveries and other additions | MBoe | 253,173 | 440,621 | 444,654 | ||||
Discount factor utilized as standardized measure for future net cash flows | 10.00% | ||||||
Crude Oil [Member] | |||||||
Reserve Quantities [Line Items] | |||||||
Weighted average price utilized in computation of future cash inflows | 41.63 | 84.54 | 91.50 | ||||
Crude Oil [Member] | |||||||
Reserve Quantities [Line Items] | |||||||
Percentage change in average SEC price | 47.00% | ||||||
Revisions of previous estimates | MBbls | (246,840) | (67,151) | (55,783) | ||||
Extensions, discoveries and other additions | MBbls | 134,764 | 239,526 | 267,009 | ||||
Natural Gas [Member] | |||||||
Reserve Quantities [Line Items] | |||||||
Percentage change in average SEC price | 41.00% | ||||||
Revisions of previous estimates | MMcf | (302,143) | (244,783) | (241,623) | ||||
Extensions, discoveries and other additions | MMcf | 710,453 | 1,206,569 | 1,065,870 | ||||
Weighted average price utilized in computation of future cash inflows | 2.35 | 6.06 | 5.36 | ||||
Proved Undeveloped Reserves [Domain] | |||||||
Reserve Quantities [Line Items] | |||||||
Revisions of previous estimates | MBoe | 98 | ||||||
Proved Undeveloped Reserves [Domain] | Natural Gas [Member] | |||||||
Reserve Quantities [Line Items] | |||||||
Revisions of previous estimates | MBbls | 197 | ||||||
Proved Undeveloped Reserves [Domain] | Crude Oil [Member] | |||||||
Reserve Quantities [Line Items] | |||||||
Revisions of previous estimates | MBbls | 65 | ||||||
Bakken [Member] | |||||||
Reserve Quantities [Line Items] | |||||||
Extensions, discoveries and other additions | 75,000 | 124,000 | |||||
Extensions, discoveries and other additions | MBoe | 96,000 | ||||||
SCOOP [Member] | |||||||
Reserve Quantities [Line Items] | |||||||
Extensions, discoveries and other additions | 36,000 | 340,000 | |||||
Extensions, discoveries and other additions | MBoe | 93,000 | ||||||
Northwest Cana [Member] | |||||||
Reserve Quantities [Line Items] | |||||||
Extensions, discoveries and other additions | 20,000 | 222,000 | |||||
Extensions, discoveries and other additions | MBoe | 57,000 | ||||||
Price Driven [Domain] | Proved Reserves [Domain] | |||||||
Reserve Quantities [Line Items] | |||||||
Revisions of previous estimates | MBoe | 251 | ||||||
Price Driven [Domain] | Proved Reserves [Domain] | Natural Gas [Member] | |||||||
Reserve Quantities [Line Items] | |||||||
Revisions of previous estimates | MBbls | 391 | ||||||
Price Driven [Domain] | Proved Reserves [Domain] | Crude Oil [Member] | |||||||
Reserve Quantities [Line Items] | |||||||
Revisions of previous estimates | MBbls | 185 | ||||||
Production [Domain] | Proved Reserves [Domain] | |||||||
Reserve Quantities [Line Items] | |||||||
Revisions of previous estimates | MBoe | 42 | ||||||
Production [Domain] | Proved Reserves [Domain] | Natural Gas [Member] | |||||||
Reserve Quantities [Line Items] | |||||||
Revisions of previous estimates | MBbls | 125 | ||||||
Production [Domain] | Proved Reserves [Domain] | Crude Oil [Member] | |||||||
Reserve Quantities [Line Items] | |||||||
Revisions of previous estimates | MBbls | 63 |
Supplemental Crude Oil and Na77
Supplemental Crude Oil and Natural Gas Information - Schedule of Proved Crude Oil and Natural Gas Reserves (Detail) | 12 Months Ended | ||||||
Dec. 31, 2015 | Dec. 31, 2015$ / Barrels | Dec. 31, 2015MBoe | Dec. 31, 2015MBbls | Dec. 31, 2015MMcf | Dec. 31, 2014$ / BarrelsMBoeMBblsMMcf | Dec. 31, 2013MBoeMBblsMMcf | |
Reserve Quantities [Line Items] | |||||||
Percentage of discounted future net cash flows prepared by external reserve engineers | 99.00% | 99.00% | 99.00% | ||||
Changes in Proved Reserves [Roll Forward] | |||||||
Proved reserves at beginning of period, Total | 1,351,091 | 1,084,125 | 784,677 | ||||
Revisions of previous estimates, Total | (297,198) | (107,949) | (96,054) | ||||
Extensions, discoveries and other additions, Total | 253,173 | 440,621 | 444,654 | ||||
Production, Total | (80,926) | (63,579) | (49,610) | ||||
Sales of minerals in place, Total | (329) | (3,227) | 0 | ||||
Purchases of minerals in place, Total | 0 | 1,100 | 458 | ||||
Proved reserves at end of period, Total | 1,225,811 | 1,351,091 | 1,084,125 | ||||
Percent of proved crude oil reserve estimates prepared by external reserve engineers | 99.00% | ||||||
Percent of proved natural gas reserve estimates prepared by external reserve engineers | 97.00% | ||||||
Natural Gas [Member] | |||||||
Reserve Quantities [Line Items] | |||||||
Twelve month average SEC price | $ / Barrels | 2.58 | 4.35 | |||||
Changes in Proved Reserves [Roll Forward] | |||||||
Proved reserves at beginning of period | MMcf | 2,908,386 | 2,078,020 | 1,341,084 | ||||
Revisions of previous estimates | MMcf | (302,143) | (244,783) | (241,623) | ||||
Extensions, discoveries and other additions | MMcf | 710,453 | 1,206,569 | 1,065,870 | ||||
Production | MMcf | (164,454) | (114,295) | (87,730) | ||||
Sales of minerals in place | MMcf | (456) | (18,623) | 0 | ||||
Purchases of minerals in place | MMcf | 0 | 1,498 | 419 | ||||
Proved reserves at end of period | MMcf | 3,151,786 | 2,908,386 | 2,078,020 | ||||
Crude Oil [Member] | |||||||
Reserve Quantities [Line Items] | |||||||
Twelve month average SEC price | $ / Barrels | 50.28 | 94.99 | |||||
Changes in Proved Reserves [Roll Forward] | |||||||
Proved reserves at beginning of period | MBbls | 866,360 | 737,788 | 561,163 | ||||
Revisions of previous estimates | MBbls | (246,840) | (67,151) | (55,783) | ||||
Extensions, discoveries and other additions | MBbls | 134,764 | 239,526 | 267,009 | ||||
Production | MBbls | (53,517) | (44,530) | (34,989) | ||||
Sales of minerals in place | MBbls | (253) | (123) | 0 | ||||
Purchases of minerals in place | MBbls | 0 | 850 | 388 | ||||
Proved reserves at end of period | MBbls | 700,514 | 866,360 | 737,788 | ||||
Northwest Cana [Member] | |||||||
Changes in Proved Reserves [Roll Forward] | |||||||
Extensions, discoveries and other additions | 20,000 | 222,000 | |||||
Extensions, discoveries and other additions, Total | 57,000 |
Supplemental Crude Oil and Na78
Supplemental Crude Oil and Natural Gas Information - Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities (Detail) | Dec. 31, 2015MBoeMBblsMMcf | Dec. 31, 2014MBoeMBblsMMcf | Dec. 31, 2013MBoeMBblsMMcf | Dec. 31, 2012MMcf |
Reserve Quantities [Line Items] | ||||
Proved Developed Reserves (MBOE) | MBoe | 525,188 | 502,479 | 406,792 | |
Proved Undeveloped Reserve (MBOE) | MBoe | 700,623 | 848,612 | 677,333 | |
Total Proved Reserves (MBOE) | MBoe | 1,225,811 | 1,351,091 | 1,084,125 | |
Crude Oil [Member] | ||||
Reserve Quantities [Line Items] | ||||
Proved Developed Reserves (Volume) | MBbls | 326,798 | 342,137 | 278,630 | |
Proved Undeveloped Reserve (Volume) | MBbls | 373,716 | 524,223 | 459,158 | |
Total Proved Reserves (Volume) | MBbls | 700,514 | 866,360 | 737,788 | |
Natural Gas [Member] | ||||
Reserve Quantities [Line Items] | ||||
Proved Developed Reserves (Volume) | MMcf | 1,190,343 | 962,051 | 768,969 | |
Proved Undeveloped Reserve (Volume) | MMcf | 1,961,443 | 1,946,335 | 1,309,051 | |
Total Proved Reserves (Volume) | MMcf | 3,151,786 | 2,908,386 | 2,078,020 | 1,341,084 |
Supplemental Crude Oil and Na79
Supplemental Crude Oil and Natural Gas Information - Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Supplemental Crude Oil and Natural Gas Information [Abstract] | ||||
Discount factor utilized as standardized measure for future net cash flows | 10.00% | |||
Future cash inflows | $ 36,551,672 | $ 90,867,459 | $ 78,646,274 | |
Future production costs | (10,869,493) | (25,799,221) | (21,333,460) | |
Future development and abandonment costs | (6,935,958) | (12,842,174) | (10,250,789) | |
Future income taxes | (3,717,612) | (13,800,737) | (12,447,127) | |
Future net cash flows | 15,028,609 | 38,425,327 | 34,614,898 | |
10% annual discount for estimated timing of cash flows | (8,552,325) | (19,992,293) | (18,319,131) | |
Standardized measure of discounted future net cash flows | $ 6,476,284 | $ 18,433,034 | $ 16,295,767 | $ 11,180,357 |
Supplemental Crude Oil and Na80
Supplemental Crude Oil and Natural Gas Information - Changes in Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward] | |||
Standardized measure of discounted future net cash flows at beginning of year | $ 18,433,034 | $ 16,295,767 | $ 11,180,357 |
Extensions, discoveries and improved recoveries, less related costs | 1,091,283 | 5,516,528 | 6,613,665 |
Revisions of previous quantity estimates | (2,156,028) | (1,755,366) | (1,765,300) |
Changes in estimated future development and abandonment costs | 5,008,731 | 476,665 | 1,942,585 |
Sales of Minerals in Place | (7,768) | (3,196) | |
Purchases of minerals in place | 12,012 | ||
Net change in prices and production costs | (16,111,142) | (1,925,349) | 263,541 |
Accretion of discount | 1,843,303 | 1,629,576 | 1,118,036 |
Sales of crude oil and natural gas produced, net of production costs | (2,002,997) | (3,500,790) | (2,992,447) |
Development costs incurred during the period | 1,394,584 | 2,466,748 | 1,210,223 |
Change in timing of estimated future production and other | (3,844,259) | (309,902) | 464,111 |
Change in income taxes | 2,827,543 | (457,647) | (1,751,016) |
Net change | (11,956,750) | 2,137,267 | 5,115,410 |
Standardized measure of discounted future net cash flows at end of year | $ 6,476,284 | $ 18,433,034 | $ 16,295,767 |
Quarterly Financial Data - Sche
Quarterly Financial Data - Schedule Of Quarterly Financial Data (Detail) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |||||||||
Quarterly Financial Information Disclosure [Abstract] | |||||||||||||||||||
Loss on extinguishment of debt | $ 0 | $ 24,517 | $ 0 | ||||||||||||||||
Extinguishment of Debt, Gain (Loss), Net of Tax | $ 15,400 | ||||||||||||||||||
Extinguishment of Debt, Gain (Loss), Per Share, Net of Tax | $ 0.04 | ||||||||||||||||||
Cash Proceeds from Liquidated Derivatives | $ 433,000 | $ 433,000 | |||||||||||||||||
Cash Proceeds from Liquidated Derivatives, after tax | $ 273,000 | ||||||||||||||||||
Cash Proceeds from Liquidated Derivatives, per share | $ 0.74 | ||||||||||||||||||
Total revenues | $ 575,480 | [1] | $ 682,669 | [1] | $ 796,374 | [1] | $ 625,644 | [1] | $ 1,297,700 | [1],[2] | $ 1,645,328 | [3] | $ 886,095 | [1] | $ 972,495 | [1] | 2,680,167 | 4,801,618 | 3,421,807 |
Gain (loss) on derivative instruments, net | 16,540 | [1] | 46,527 | [1] | (4,737) | [1] | 32,755 | [1] | 387,958 | [1],[2] | 473,999 | [1] | (262,524) | [1] | (39,674) | [1] | 91,085 | 559,759 | (191,751) |
Property impairments | 81,001 | [4] | 96,697 | [4] | 76,872 | [4] | 147,561 | [4] | 393,803 | [4] | 85,561 | [4] | 79,316 | [4] | 58,208 | [4] | 402,131 | 616,888 | 220,508 |
Income from operations | (142,816) | (52,356) | 82,447 | (111,276) | 265,228 | [2] | 944,897 | 236,394 | 421,317 | (224,001) | 1,867,836 | 1,445,767 | |||||||
Net income (loss) | $ (139,677) | $ (82,423) | $ 403 | $ (131,971) | $ 114,048 | [2] | $ 533,521 | $ 103,538 | $ 226,234 | $ (353,668) | $ 977,341 | $ 764,219 | |||||||
Net income per share: Basic | $ (0.38) | $ (0.22) | $ 0 | $ (0.36) | $ 0.31 | [2] | $ 1.45 | [3] | $ 0.28 | $ 0.61 | $ (0.96) | $ 2.65 | $ 2.08 | ||||||
Net income per share: Diluted | $ (0.38) | $ (0.22) | $ 0 | $ (0.36) | $ 0.31 | [2] | $ 1.44 | [3] | $ 0.28 | $ 0.61 | $ (0.96) | $ 2.64 | $ 2.07 | ||||||
[1] | Gains and losses on mark-to-market derivative instruments are reflected in “Total revenues” on both the consolidated statements of comprehensive income (loss) and this table of unaudited quarterly financial data. Derivative gains and losses have been shown separately to illustrate the fluctuations in revenues that are attributable to the Company’s derivative instruments. Commodity price fluctuations each quarter can result in significant swings in mark-to-market gains and losses, which affects comparability between periods. | ||||||||||||||||||
[2] | Balances for the fourth quarter of 2014 include $433 million of pre-tax gains ($273 million after tax, or $0.74 per basic and diluted share) recognized from crude oil derivative contracts that were settled prior to their contractual maturities. | ||||||||||||||||||
[3] | The 2014 third quarter includes a $24.5 million pre-tax ($15.4 million after tax, or $0.04 per basic and diluted share) loss on extinguishment of debt as discussed in Note 7. Long-Term Debt. | ||||||||||||||||||
[4] | Property impairments have been shown separately to illustrate the fluctuations in income (loss) that are attributable to write downs of the Company's assets. Commodity price fluctuations each quarter can result in significant changes in estimated future cash flows and resulting impairments, which affects comparability between periods. |