Document_and_Entity_Informatio
Document and Entity Information (USD $) | 12 Months Ended | ||
In Billions, except Share data, unless otherwise specified | Dec. 31, 2014 | Feb. 17, 2015 | Jun. 30, 2014 |
Entity Information [Line Items] | |||
Document Type | 10-K | ||
Amendment Flag | FALSE | ||
Document Period End Date | 31-Dec-14 | ||
Document Fiscal Year Focus | 2014 | ||
Document Fiscal Period Focus | FY | ||
Trading Symbol | CLR | ||
Entity Registrant Name | CONTINENTAL RESOURCES, INC | ||
Entity Central Index Key | 732834 | ||
Current Fiscal Year End Date | -19 | ||
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 | 371,906,845 | ||
Entity Public Float | $9.10 |
Consolidated_Balance_Sheets
Consolidated Balance Sheets (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Current assets: | ||
Cash and cash equivalents | $24,381 | $28,482 |
Receivables: | ||
Crude oil and natural gas sales | 552,476 | 643,498 |
Affiliated parties | 13,360 | 13,107 |
Joint interest and other, net | 567,476 | 349,579 |
Derivative assets | 52,423 | 3,616 |
Inventories | 102,179 | 54,440 |
Deferred and prepaid taxes | 63,266 | 44,337 |
Prepaid expenses and other | 14,040 | 10,207 |
Total current assets | 1,389,601 | 1,147,266 |
Net property and equipment, based on successful efforts method of accounting | 13,635,852 | 10,721,272 |
Net debt issuance costs and other | 87,625 | 72,644 |
Noncurrent derivative assets | 31,992 | 0 |
Total assets | 15,145,070 | 11,941,182 |
Current liabilities: | ||
Accounts payable trade | 1,263,724 | 885,289 |
Revenues and royalties payable | 272,755 | 291,772 |
Payables to affiliated parties | 7,305 | 5,436 |
Accrued liabilities and other | 404,506 | 198,113 |
Derivative liabilities | 1,645 | 90,535 |
Current portion of long-term debt | 2,078 | 2,011 |
Total current liabilities | 1,952,013 | 1,473,156 |
Long-term debt, net of current portion | 5,995,837 | 4,713,821 |
Other noncurrent liabilities: | ||
Deferred income tax liabilities | 2,141,447 | 1,736,812 |
Asset retirement obligations, net of current portion | 75,462 | 54,353 |
Noncurrent derivative liabilities | 3,109 | 7,829 |
Other noncurrent liabilities | 9,358 | 2,093 |
Total other noncurrent liabilities | 2,229,376 | 1,801,087 |
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; 500,000,000 shares authorized; 372,005,502 shares issued and outstanding at December 31, 2014; 371,317,318 shares issued and outstanding at December 31, 2013 | 3,720 | 3,713 |
Additional paid-in capital | 1,287,941 | 1,250,178 |
Accumulated Other Comprehensive Income (Loss), Net of Tax | -385 | 0 |
Retained earnings | 3,676,568 | 2,699,227 |
Total shareholders’ equity | 4,967,844 | 3,953,118 |
Total liabilities and shareholders’ equity | $15,145,070 | $11,941,182 |
Consolidated_Balance_Sheets_Pa
Consolidated Balance Sheets (Parenthetical) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
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 | 500,000,000 | 500,000,000 |
Common stock, shares issued | 372,005,502 | 371,317,318 |
Common stock, outstanding | 372,005,502 | 371,317,318 |
Consolidated_Statements_of_Com
Consolidated Statements of Comprehensive Income (USD $) | 12 Months Ended | ||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Revenues: | |||
Crude oil and natural gas sales | $4,107,894 | $3,473,026 | $2,290,608 |
Crude oil and natural gas sales to affiliates | 95,128 | 100,405 | 58,892 |
Gain (loss) on derivative instruments, net | 559,759 | -191,751 | 154,016 |
Crude oil and natural gas service operations | 38,837 | 40,127 | 39,071 |
Total revenues | 4,801,618 | 3,421,807 | 2,542,587 |
Operating costs and expenses: | |||
Production expenses | 347,349 | 280,789 | 193,466 |
Production and other expenses to affiliates | 5,123 | 1,408 | 1,974 |
Production taxes and other expenses | 349,760 | 298,787 | 198,505 |
Exploration expenses | 50,067 | 34,947 | 23,507 |
Crude oil and natural gas service operations | 21,871 | 29,665 | 32,248 |
Depreciation, depletion, amortization and accretion | 1,358,669 | 965,645 | 692,118 |
Property impairments | 616,888 | 220,508 | 122,274 |
General and administrative expenses | 184,655 | 144,379 | 121,735 |
Gain on sale of assets, net | -600 | -88 | -136,047 |
Total operating costs and expenses | 2,933,782 | 1,976,040 | 1,249,780 |
Income from operations | 1,867,836 | 1,445,767 | 1,292,807 |
Other income (expense): | |||
Interest expense | -283,928 | -235,275 | -140,708 |
Loss on extinguishment of debt | -24,517 | 0 | 0 |
Other | 2,647 | 2,557 | 3,097 |
Total other income (expense) | -305,798 | -232,718 | -137,611 |
Income before income taxes | 1,562,038 | 1,213,049 | 1,155,196 |
Provision for income taxes | 584,697 | 448,830 | 415,811 |
Net income | 977,341 | 764,219 | 739,385 |
Basic net income per share (in dollars per share) | $2.65 | $2.08 | $2.04 |
Diluted net income per share (in dollars per share) | $2.64 | $2.07 | $2.03 |
Foreign currency translation adjustments | -385 | 0 | 0 |
Other Comprehensive Income (Loss), Net of Tax | -385 | 0 | 0 |
Comprehensive Income (Loss), Net of Tax | $976,956 | $764,219 | $739,385 |
Consolidated_Statements_of_Sha
Consolidated Statements of Shareholders' Equity (USD $) | Total | Common stock | Additional paid-in capital | Accumulated Other Comprehensive Income (Loss) | Retained earnings |
In Thousands, except Share data, unless otherwise specified | |||||
Balance at Dec. 31, 2011 | $2,308,125 | $3,617 | $1,108,885 | $1,195,623 | |
Balance, shares at Dec. 31, 2011 | 361,743,376 | ||||
Net income | 739,385 | 739,385 | |||
Other Comprehensive Income (Loss), Net of Tax | 0 | ||||
Public offering of common stock | 81,528 | 78 | 81,450 | ||
Public offering of common stock, shares | 7,832,314 | ||||
Stock-based compensation | 30,202 | 30,202 | |||
Excess tax benefit on stock-based compensation | 15,618 | ||||
Stock options: | |||||
Exercised | 60 | 2 | 58 | ||
Exercised, shares | 173,000 | 173,000 | |||
Repurchased and canceled | -2,951 | 0 | -2,951 | ||
Repurchased and canceled, shares | -65,968 | ||||
Restricted stock: | |||||
Issued | 18 | 18 | 0 | ||
Issued, shares | 1,832,056 | ||||
Repurchased and canceled | -8,285 | -2 | -8,283 | ||
Repurchased and canceled, shares | -225,042 | ||||
Forfeited | -1 | -1 | |||
Forfeited, shares | -80,374 | ||||
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 | ||||
Net income | 764,219 | 764,219 | |||
Other Comprehensive Income (Loss), Net of Tax | 0 | ||||
Stock-based compensation | 39,886 | 39,886 | |||
Stock options: | |||||
Repurchased and canceled | 0 | ||||
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 | 371,317,318 | |||
Net income | 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 |
Consolidated_Statements_of_Cas
Consolidated Statements of Cash Flows (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Cash flows from operating activities: | |||
Net income | $977,341 | $764,219 | $739,385 |
Adjustments to reconcile net income to cash provided by operating activities: | |||
Depreciation, depletion, amortization and accretion | 1,368,311 | 965,437 | 694,698 |
Property impairments | 616,888 | 220,508 | 122,274 |
Non-cash (gain) loss on derivatives, net | -174,409 | 130,196 | -199,737 |
Stock-based compensation | 54,353 | 39,890 | 29,057 |
Provision for deferred income taxes | 584,677 | 442,621 | 405,294 |
Excess tax benefit from stock-based compensation | 0 | 0 | -15,618 |
Dry hole costs | 23,679 | 9,350 | 767 |
Gain on sale of assets, net | -600 | -88 | -136,047 |
Loss on extinguishment of debt | 24,517 | 0 | 0 |
Other, net | 7,637 | 2,037 | 5,007 |
Changes in assets and liabilities: | |||
Accounts receivable | -129,634 | -166,138 | -91,791 |
Inventories | -65,919 | -7,697 | -7,165 |
Prepaid expenses and other | -57,489 | -11,537 | 14,381 |
Accounts payable trade | 85,540 | 107,250 | -8,487 |
Revenues and royalties payable | -18,022 | 28,401 | 40,030 |
Accrued liabilities and other | 58,880 | 44,260 | 40,309 |
Other noncurrent assets and liabilities | -35 | -5,414 | -292 |
Net cash provided by operating activities | 3,355,715 | 2,563,295 | 1,632,065 |
Cash flows from investing activities: | |||
Exploration and development | -4,604,468 | -3,660,773 | -3,493,652 |
Purchase of producing crude oil and natural gas properties | -48,917 | -16,604 | -570,985 |
Purchase of other property and equipment | -63,402 | -62,054 | -53,468 |
Proceeds from sale of assets and other | 129,388 | 28,420 | 214,735 |
Net cash used in investing activities | -4,587,399 | -3,711,011 | -3,903,370 |
Cash flows from financing activities: | |||
Credit facility borrowings | 1,695,000 | 970,000 | 2,119,000 |
Repayment of credit facility | -1,805,000 | -1,290,000 | -1,882,000 |
Proceeds from issuance of Senior Notes | 1,681,834 | 1,479,375 | 1,999,000 |
Redemption of Senior Notes | -300,000 | 0 | 0 |
Premium on redemption of Senior Notes | -17,497 | 0 | 0 |
Proceeds from other debt | 0 | 0 | 22,000 |
Repayment of other debt | -2,013 | -1,951 | -1,579 |
Debt issuance costs | -8,026 | -2,265 | -7,373 |
Repurchase of equity grants | -16,583 | -14,690 | -11,236 |
Excess tax benefit from stock-based compensation | 0 | 0 | 15,618 |
Exercise of stock options | 0 | 0 | 60 |
Net cash provided by financing activities | 1,227,715 | 1,140,469 | 2,253,490 |
Effect of exchange rate on cash and cash equivalents | -132 | ||
Net change in cash and cash equivalents | -4,101 | -7,247 | -17,815 |
Cash and cash equivalents at beginning of period | 28,482 | 35,729 | 53,544 |
Cash and cash equivalents at end of period | $24,381 | $28,482 | $35,729 |
Organization_and_Summary_of_Si
Organization and Summary of Significant Accounting Policies | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
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 in the North, South, and East regions of the United States. The North region consists of properties north of Kansas and west of the Mississippi River and includes North Dakota Bakken, Montana Bakken, and the Red River units. The South region includes Kansas and all properties south of Kansas and west of the Mississippi River including various plays in the South Central Oklahoma Oil Province (“SCOOP”), Northwest Cana and Arkoma areas of Oklahoma. The East region is comprised of undeveloped leasehold acreage east of the Mississippi River with no current drilling or production operations. | |||||||||||||
The Company’s operations are geographically concentrated in the North region, with that region comprising approximately 74% of the Company’s crude oil and natural gas production and approximately 83% of its crude oil and natural gas revenues for the year ended December 31, 2014. 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, 2014, approximately 69% of the Company’s estimated proved reserves were located in the North region. In 2012 and 2013, the Company significantly expanded its activity in the South region with its discovery and announcement of the SCOOP play in Oklahoma. The South region now comprises 26% of the Company's crude oil and natural gas production and 31% of its estimated proved reserves as of December 31, 2014. | |||||||||||||
The Company has focused its operations on the exploration and development of crude oil since the 1980s. For the year ended December 31, 2014, crude oil accounted for approximately 70% of the Company’s total production and approximately 85% of its crude oil and natural gas revenues. Crude oil represents approximately 64% of the Company's estimated proved reserves as of December 31, 2014. | |||||||||||||
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. | |||||||||||||
Stock split | |||||||||||||
On August 18, 2014, the Company's Board of Directors declared a 2-for-1 stock split of the Company's common stock to be effected in the form of a stock dividend. The stock dividend was distributed on September 10, 2014 to shareholders of record as of September 3, 2014. All previously reported common stock and earnings per share amounts have been retroactively adjusted in the accompanying financial statements and related notes to reflect the stock split. | |||||||||||||
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. In the opinion of management, all adjustments (consisting only of normal recurring adjustments) necessary for a fair presentation in accordance with U.S. GAAP have been included in these consolidated financial statements. | |||||||||||||
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, 2014 and 2013 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, 2014, the Company had cash deposits in excess of federally insured amounts of approximately $22.6 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, 2014, sales to the Company’s two largest purchasers accounted for approximately 14% and 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 2014. 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 the Company’s operating regions. | |||||||||||||
Inventories | |||||||||||||
Inventories are stated at the lower of cost or market and consist of the following: | |||||||||||||
December 31, | |||||||||||||
In thousands | 2014 | 2013 | |||||||||||
Tubular goods and equipment | $ | 15,659 | $ | 11,139 | |||||||||
Crude oil | 86,520 | 43,301 | |||||||||||
Total | $ | 102,179 | $ | 54,440 | |||||||||
Crude oil inventories are valued at the lower of cost or market using the first-in, first-out inventory method. Crude oil inventories consist of the following volumes: | |||||||||||||
December 31, | |||||||||||||
MBbls | 2014 | 2013 | |||||||||||
Crude oil line fill and tank requirements | 1,323 | 370 | |||||||||||
Temporarily stored crude oil | 596 | 344 | |||||||||||
Total | 1,919 | 714 | |||||||||||
An increase in crude oil line fill requirements associated with new pipelines put into service during 2014 along with initial tank fill at new storage facilities resulted in an increase in crude oil stored in inventory at December 31, 2014 compared to December 31, 2013. | |||||||||||||
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 furniture and fixtures, automobiles, machinery and equipment, office equipment, computer equipment and software, 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 | |||||||||||||
Furniture and fixtures | 10 | ||||||||||||
Automobiles | 6-May | ||||||||||||
Machinery and equipment | 20-Oct | ||||||||||||
Office equipment, computer equipment and software | 10-Mar | ||||||||||||
Enterprise resource planning software | 25 | ||||||||||||
Buildings and improvements | Oct-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, 2012 through December 31, 2014: | |||||||||||||
In thousands | 2014 | 2013 | 2012 | ||||||||||
Asset retirement obligations at January 1 | $ | 55,787 | $ | 47,171 | $ | 62,625 | |||||||
Accretion expense | 3,366 | 2,767 | 3,105 | ||||||||||
Revisions | 9,916 | 2,826 | (2,871 | ) | |||||||||
Plus: Additions for new assets | 9,022 | 6,009 | 6,679 | ||||||||||
Less: Plugging costs and sold assets (1) | (1,383 | ) | (2,986 | ) | (22,367 | ) | |||||||
Total asset retirement obligations at December 31 | $ | 76,708 | $ | 55,787 | $ | 47,171 | |||||||
Less: Current portion of asset retirement obligations at December 31 (2) | 1,246 | 1,434 | 2,227 | ||||||||||
Non-current portion of asset retirement obligations at December 31 | $ | 75,462 | $ | 54,353 | $ | 44,944 | |||||||
-1 | As a result of asset dispositions during the year ended December 31, 2012, the Company removed $20.0 million of its previously recognized asset retirement obligations that were assumed by the buyers. See Note 13. Property Acquisitions and Dispositions for further discussion. | ||||||||||||
-2 | Balance is included in the caption "Accrued liabilities and other" in the consolidated balance sheets. | ||||||||||||
As of December 31, 2014 and 2013, net property and equipment on the consolidated balance sheets included $64.7 million and $44.4 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, or when events and circumstances indicate a possible decline in the recoverability of the carrying value of such field. 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. Individually significant non-producing properties, if any, are assessed for impairment on a property-by-property basis and, if the assessment indicates an impairment, a loss is recognized by providing a valuation allowance consistent with the level at which impairment was assessed. For individually insignificant non-producing properties, impairment losses 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 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 credit facility and amendments thereto are capitalized and amortized over the term of the facility 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 $76.1 million and $69.5 million (net of accumulated amortization of $38.1 million and $28.8 million) relating to its long-term debt at December 31, 2014 and 2013, respectively. The increase in 2014 resulted from the capitalization of costs incurred in connection with the Company’s new credit facility and the May 2014 issuances of 3.8% Senior Notes due 2024 and 4.9% Senior Notes due 2044 as discussed in Note 7. Long-Term Debt. For the years ended December 31, 2014, 2013 and 2012, the Company recognized amortization expense associated with capitalized debt issuance costs of $9.3 million, $8.6 million and $5.6 million, respectively, which are reflected in “Interest expense” in the consolidated statements of comprehensive income. | |||||||||||||
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 anticipated 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 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, 2014 and 2013. | |||||||||||||
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. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized. The Company’s policy is to recognize penalties and interest related to unrecognized tax benefits, if any, in income tax expense. | |||||||||||||
Earnings per share | |||||||||||||
Basic net income per share is computed by dividing net income by the weighted-average number of shares outstanding for the period. Diluted net income per share reflects the potential dilution of non-vested restricted stock awards and stock options, 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 per share for the years ended December 31, 2014, 2013 and 2012. All stock options issued by the Company in prior periods had been exercised or had expired as of March 31, 2012. Weighted average shares and net income per share amounts for 2012 and 2013 have been retroactively adjusted to reflect the Company's 2-for-1 stock split occurring in September 2014. | |||||||||||||
Year ended December 31, | |||||||||||||
In thousands, except per share data | 2014 | 2013 | 2012 | ||||||||||
Income (numerator): | |||||||||||||
Net income - basic and diluted | $ | 977,341 | $ | 764,219 | $ | 739,385 | |||||||
Weighted average shares (denominator): | |||||||||||||
Weighted average shares - basic | 368,829 | 368,150 | 362,680 | ||||||||||
Non-vested restricted stock | 1,929 | 1,548 | 980 | ||||||||||
Stock options | — | — | 32 | ||||||||||
Weighted average shares - diluted | 370,758 | 369,698 | 363,692 | ||||||||||
Net income per share: | |||||||||||||
Basic | $ | 2.65 | $ | 2.08 | $ | 2.04 | |||||||
Diluted | $ | 2.64 | $ | 2.07 | $ | 2.03 | |||||||
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 pronouncement | |||||||||||||
In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606). The standard generally requires an entity to identify performance obligations in its contracts, estimate the amount of variable consideration to be received in the transaction price, allocate the transaction price to each separate performance obligation, and recognize revenue as obligations are satisfied. The standard will be effective for annual and interim periods beginning after December 15, 2016. The standard allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. The Company is evaluating the impact of the provisions of ASU 2014-09; however, the standard is not expected to have a material effect on the Company’s financial position, results of operations or cash flows. | |||||||||||||
Reclassifications | |||||||||||||
Prior to 2014, the Company presented charges related to natural gas transportation and processing under the caption “Production taxes and other expenses” or “Production and other expenses to affiliates” in the consolidated statements of comprehensive income. Effective January 1, 2014, such charges are netted within “Crude oil and natural gas sales” or "Crude oil and natural gas sales to affiliates", as applicable. Previously reported amounts have been reclassified to conform to the current year presentation. Reclassified amounts total $33.3 million and $29.9 million for the years ended December 31, 2013 and 2012, respectively, including transactions with an affiliate totaling $4.7 million for each of those respective years. The reclassifications had no impact on previously reported operating income, net income, current assets, total assets, current liabilities, total liabilities, stockholders' equity or cash flows. |
Supplemental_Cash_Flow_Informa
Supplemental Cash Flow Information | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
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 taxes. 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 | 2014 | 2013 | 2012 | ||||||||||
Supplemental cash flow information: | |||||||||||||
Cash paid for interest | $ | 267,384 | $ | 209,815 | $ | 102,043 | |||||||
Cash paid for income taxes | 53,457 | 29,017 | 829 | ||||||||||
Cash received for income tax refunds | 7 | 174 | 13,866 | ||||||||||
Non-cash investing activities: | |||||||||||||
Increase in accrued capital expenditures | 290,782 | 89,482 | 49,039 | ||||||||||
Acquisition of assets through issuance of common stock (Note 11) | — | — | 176,563 | ||||||||||
Asset retirement obligation additions and revisions, net | 18,938 | 8,835 | 3,808 | ||||||||||
Net_Property_and_Equipment
Net Property and Equipment | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Property, Plant and Equipment, Net [Abstract] | |||||||||
Net Property and Equipment | Net Property and Equipment | ||||||||
Net property and equipment includes the following at December 31, 2014 and 2013: | |||||||||
December 31, | |||||||||
In thousands | 2014 | 2013 | |||||||
Proved crude oil and natural gas properties | $ | 17,045,967 | $ | 12,423,878 | |||||
Unproved crude oil and natural gas properties | 966,080 | 1,181,268 | |||||||
Service properties, equipment and other | 274,584 | 236,233 | |||||||
Total property and equipment | 18,286,631 | 13,841,379 | |||||||
Accumulated depreciation, depletion and amortization | (4,650,779 | ) | (3,120,107 | ) | |||||
Net property and equipment | $ | 13,635,852 | $ | 10,721,272 | |||||
Accrued_Liabilities_and_Other
Accrued Liabilities and Other | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Accrued Liabilities and Other Liabilities [Abstract] | |||||||||
Accrued Liabilities and Other | Accrued Liabilities and Other | ||||||||
Accrued liabilities and other includes the following at December 31, 2014 and 2013: | |||||||||
December 31, | |||||||||
In thousands | 2014 | 2013 | |||||||
Prepaid advances from joint interest owners | $ | 115,687 | $ | 57,196 | |||||
Accrued compensation | 39,848 | 41,757 | |||||||
Accrued production taxes, ad valorem taxes and other non-income taxes | 36,550 | 35,900 | |||||||
Deferred tax liabilities | 145,349 | — | |||||||
Accrued interest | 60,861 | 61,216 | |||||||
Current portion of asset retirement obligations | 1,246 | 1,434 | |||||||
Other | 4,965 | 610 | |||||||
Accrued liabilities and other | $ | 404,506 | $ | 198,113 | |||||
Derivative_Instruments
Derivative Instruments | 12 Months Ended | |||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||
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 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 forecasted 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, the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price, and 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 NYMEX West Texas Intermediate ("WTI") pricing or 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. | ||||||||||||||||||||
In the fourth quarter of 2014, substantially all of the Company's outstanding crude oil derivative contracts were settled prior to the expiration of their contractual maturities scheduled through December 2016, resulting in the receipt of cash proceeds and recognition of gains totaling approximately $433 million which are included in the caption “Gain (loss) on derivative instruments, net" in the consolidated statements of comprehensive income for the year ended December 31, 2014. No natural gas derivative contracts in place were liquidated in the fourth quarter of 2014. | ||||||||||||||||||||
At December 31, 2014, the Company had outstanding derivative contracts with respect to future production as set forth in the tables below. | ||||||||||||||||||||
Crude Oil - NYMEX WTI | Ceilings | |||||||||||||||||||
Weighted Average | ||||||||||||||||||||
Period and Type of Contract | Bbls | Range | Price | |||||||||||||||||
July 2015 - December 2015 | ||||||||||||||||||||
Written call options - WTI (1) | 2,208,000 | $95.85 - $103.75 | $ | 98.36 | ||||||||||||||||
Crude Oil - ICE Brent | Ceilings | |||||||||||||||||||
Weighted Average | ||||||||||||||||||||
Period and Type of Contract | Bbls | Range | Price | |||||||||||||||||
July 2015 - December 2015 | ||||||||||||||||||||
Written call options - ICE Brent (1) | 368,000 | $ | 107.4 | $ | 107.4 | |||||||||||||||
January 2016 - December 2016 | ||||||||||||||||||||
Written call options - ICE Brent (1) | 1,464,000 | $ | 107.7 | $ | 107.7 | |||||||||||||||
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 2015 - December 2015 | ||||||||||||||||||||
Swaps - Henry Hub | 24,500,000 | $ | 4.27 | |||||||||||||||||
Collars - Henry Hub | 29,200,000 | $3.50 - $3.75 | $ | 3.69 | $4.89 - $5.48 | $ | 5.04 | |||||||||||||
January 2016 - December 2016 | ||||||||||||||||||||
Swaps - Henry Hub | 63,110,000 | $ | 3.98 | |||||||||||||||||
-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 2014 fourth quarter. For these written call options, the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price. | |||||||||||||||||||
Derivative gains and losses | ||||||||||||||||||||
The following table presents cash settlements on matured 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 | 2014 | 2013 | 2012 | |||||||||||||||||
Cash received (paid) on derivatives: | ||||||||||||||||||||
Crude oil fixed price swaps (1) | $ | 331,591 | $ | (54,289 | ) | $ | (40,238 | ) | ||||||||||||
Crude oil collars (1) | 65,310 | (16,867 | ) | (15,341 | ) | |||||||||||||||
Natural gas fixed price swaps | (11,551 | ) | 9,601 | 9,858 | ||||||||||||||||
Cash received (paid) on derivatives, net | 385,350 | (61,555 | ) | (45,721 | ) | |||||||||||||||
Non-cash gain (loss) on derivatives: | ||||||||||||||||||||
Crude oil fixed price swaps | 84,792 | (117,580 | ) | 142,567 | ||||||||||||||||
Crude oil collars | 1,121 | (8,587 | ) | 59,911 | ||||||||||||||||
Crude oil written call options | 3,981 | — | — | |||||||||||||||||
Natural gas fixed price swaps | 62,699 | (4,029 | ) | (2,741 | ) | |||||||||||||||
Natural gas collars | 21,816 | — | — | |||||||||||||||||
Non-cash gain (loss) on derivatives, net | 174,409 | (130,196 | ) | 199,737 | ||||||||||||||||
Gain (loss) on derivative instruments, net | $ | 559,759 | $ | (191,751 | ) | $ | 154,016 | |||||||||||||
-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. The proceeds include $85 million for contracts with original maturities in November and December of 2014, $337 million for contracts with original maturities in 2015, and $11 million for contracts with original maturities in 2016. Of the proceeds, $373 million relates to crude oil swap liquidations and $60 million relates to crude oil collar liquidations. | |||||||||||||||||||
Balance sheet offsetting of derivative assets and liabilities | ||||||||||||||||||||
The Company’s derivative contracts are carried at their 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 tables 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 | 2014 | 2013 | ||||||||||||||||||
Commodity derivative assets: | ||||||||||||||||||||
Gross amounts of recognized assets | $ | 84,415 | $ | 4,213 | ||||||||||||||||
Gross amounts offset on balance sheet | — | (597 | ) | |||||||||||||||||
Net amounts of assets on balance sheet | 84,415 | 3,616 | ||||||||||||||||||
Commodity derivative liabilities: | ||||||||||||||||||||
Gross amounts of recognized liabilities | (4,770 | ) | (125,709 | ) | ||||||||||||||||
Gross amounts offset on balance sheet | 16 | 27,345 | ||||||||||||||||||
Net amounts of liabilities on balance sheet | $ | (4,754 | ) | $ | (98,364 | ) | ||||||||||||||
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 | 2014 | 2013 | ||||||||||||||||||
Derivative assets | $ | 52,423 | $ | 3,616 | ||||||||||||||||
Noncurrent derivative assets | 31,992 | — | ||||||||||||||||||
Net amounts of assets on balance sheet | 84,415 | 3,616 | ||||||||||||||||||
Derivative liabilities | (1,645 | ) | (90,535 | ) | ||||||||||||||||
Noncurrent derivative liabilities | (3,109 | ) | (7,829 | ) | ||||||||||||||||
Net amounts of liabilities on balance sheet | (4,754 | ) | (98,364 | ) | ||||||||||||||||
Total derivative assets (liabilities), net | $ | 79,661 | $ | (94,748 | ) | |||||||||||||||
Fair_Value_Measurements
Fair Value Measurements | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
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, 2014 and 2013. | |||||||||||||||||
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 | |||||||||
Fair value measurements at December 31, 2013 using: | |||||||||||||||||
In thousands | Level 1 | Level 2 | Level 3 | Total | |||||||||||||
Derivative assets (liabilities): | |||||||||||||||||
Fixed price swaps | $ | — | $ | (84,893 | ) | $ | — | $ | (84,893 | ) | |||||||
Collars | — | (9,855 | ) | — | (9,855 | ) | |||||||||||
Total | $ | — | $ | (94,748 | ) | $ | — | $ | (94,748 | ) | |||||||
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, or when events and circumstances indicate a possible decline in the recoverability of the carrying value of such field. 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 management’s estimates of future crude oil and natural gas production, commodity prices based on commodity futures price strips, operating and development 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 2019 (adjusted for differentials), escalating 3% per year thereafter | ||||||||||||||||
Operating and development costs | Estimated costs for the current year, escalating 3% per year thereafter | ||||||||||||||||
Productive life of field | Ranging from 0 to 50 years | ||||||||||||||||
Discount rate | 10% | ||||||||||||||||
Unobservable inputs to the fair value assessment are reviewed quarterly and are revised as warranted based on a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Fair value measurements of proved properties are reviewed and approved by certain members of the Company’s management. | |||||||||||||||||
Impairments of proved properties amounted to $324.3 million for the year ended December 31, 2014, of which $255.0 million was recognized in the fourth quarter resulting from a significant decrease in crude oil prices in late 2014 that indicated the carrying amounts for certain fields were not recoverable. The 2014 impairments reflected fair value adjustments primarily concentrated in the Buffalo Red River units ($96.9 million), the Medicine Pole Hills units ($75.9 million), various non-core areas in the South region ($39.7 million), non-Bakken areas of North Dakota and Montana ($18.4 million), and certain emerging areas with limited production history and costly reserve additions ($75.2 million). The impaired properties were written down to their estimated fair value totaling approximately $101.0 million. Impairments for 2014 also include an $18.2 million lower of cost or market adjustment for crude oil inventories. | |||||||||||||||||
Certain unproved crude oil and natural gas properties were impaired during the years ended December 31, 2014, 2013, and 2012, reflecting amortization of undeveloped leasehold costs on properties that management expects will not be transferred to proved properties over the lives of the leases based on experience of successful drilling and the average holding period. In 2014, undeveloped leasehold costs for a prospect in Texas were written down to $14.2 million due to changes in drilling plans in response to unsuccessful results and lower crude oil prices, which resulted in the recognition of $92.4 million of non-producing leasehold impairment charges for the prospect, of which $84.6 million was recognized in the fourth quarter. | |||||||||||||||||
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. | |||||||||||||||||
Year ended December 31, | |||||||||||||||||
In thousands | 2014 | 2013 | 2012 | ||||||||||||||
Proved property impairments | $ | 324,302 | $ | 51,805 | $ | 4,332 | |||||||||||
Unproved property impairments | 292,586 | 168,703 | 117,942 | ||||||||||||||
Total | $ | 616,888 | $ | 220,508 | $ | 122,274 | |||||||||||
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, 2014 | December 31, 2013 | ||||||||||||||||
In thousands | Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||
Debt: | |||||||||||||||||
Credit facility | $ | 165,000 | $ | 165,000 | $ | 275,000 | $ | 275,000 | |||||||||
Note payable | 16,457 | 14,900 | 18,470 | 16,500 | |||||||||||||
8.25% Senior Notes due 2019 (1) | — | — | 298,305 | 327,800 | |||||||||||||
7.375% Senior Notes due 2020 | 198,850 | 213,000 | 198,695 | 223,700 | |||||||||||||
7.125% Senior Notes due 2021 | 400,000 | 421,000 | 400,000 | 450,300 | |||||||||||||
5% Senior Notes due 2022 | 2,022,949 | 1,857,900 | 2,025,362 | 2,063,300 | |||||||||||||
4.5% Senior Notes due 2023 | 1,500,000 | 1,372,800 | 1,500,000 | 1,519,400 | |||||||||||||
3.8% Senior Notes due 2024 | 996,622 | 868,700 | — | — | |||||||||||||
4.9% Senior Notes due 2044 | 698,037 | 572,400 | — | — | |||||||||||||
Total debt | $ | 5,997,915 | $ | 5,485,700 | $ | 4,715,832 | $ | 4,876,000 | |||||||||
(1) These senior notes were redeemed in July 2014. See Note 7. Long-Term Debt for further discussion. | |||||||||||||||||
The fair value of credit facility borrowings approximates carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy. | |||||||||||||||||
The fair value of the note payable is determined using a discounted cash flow approach based on the interest rate and payment terms of the note payable and an assumed discount rate. The fair value of the note payable is significantly influenced by the discount rate assumption, which is derived by the Company and is unobservable. Accordingly, the fair value of the note payable is classified as Level 3 in the fair value hierarchy. | |||||||||||||||||
The fair values of the 8.25% Senior Notes due 2019 (“2019 Notes”), 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. |
LongTerm_Debt
Long-Term Debt | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Debt Disclosure [Abstract] | |||||||||||||
Long-Term Debt | Long-Term Debt | ||||||||||||
Long-term debt consists of the following at December 31, 2014 and 2013: | |||||||||||||
December 31, | |||||||||||||
In thousands | 2014 | 2013 | |||||||||||
Credit facility | $ | 165,000 | $ | 275,000 | |||||||||
Note payable | 16,457 | 18,470 | |||||||||||
8.25% Senior Notes due 2019 (1) | — | 298,305 | |||||||||||
7.375% Senior Notes due 2020 (2) | 198,850 | 198,695 | |||||||||||
7.125% Senior Notes due 2021 (3) | 400,000 | 400,000 | |||||||||||
5% Senior Notes due 2022 (4) | 2,022,949 | 2,025,362 | |||||||||||
4.5% Senior Notes due 2023 (3) | 1,500,000 | 1,500,000 | |||||||||||
3.8% Senior Notes due 2024 (5) | 996,622 | — | |||||||||||
4.9% Senior Notes due 2044 (6) | 698,037 | — | |||||||||||
Total debt | 5,997,915 | 4,715,832 | |||||||||||
Less: Current portion of long-term debt | 2,078 | 2,011 | |||||||||||
Long-term debt, net of current portion | $ | 5,995,837 | $ | 4,713,821 | |||||||||
-1 | The carrying amount is net of an unamortized discount of $1.7 million at December 31, 2013. The 2019 Notes were redeemed in July 2014 as discussed further below. | ||||||||||||
-2 | The carrying amount is net of unamortized discounts of $1.2 million and $1.3 million at December 31, 2014 and 2013, respectively. | ||||||||||||
-3 | These notes were sold at par and are recorded at 100% of face value. | ||||||||||||
-4 | The carrying amount includes an unamortized premium of $22.9 million and $25.4 million at December 31, 2014 and 2013, respectively. | ||||||||||||
-5 | The carrying amount is net of an unamortized discount of $3.4 million at December 31, 2014. | ||||||||||||
-6 | The carrying amount is net of an unamortized discount of $2.0 million at December 31, 2014. | ||||||||||||
Credit facility | |||||||||||||
In May 2014, the Company entered into a new unsecured credit facility that provides for increased aggregate commitments and an extended maturity beyond the term of its previous credit facility. The new credit facility matures on May 16, 2019 and had aggregate commitments totaling $1.75 billion at December 31, 2014. The new credit facility replaced the Company’s previous $1.5 billion unsecured credit facility that was due to mature on July 1, 2015. | |||||||||||||
In February 2015, aggregate commitments on the credit facility were increased to $2.5 billion to provide additional liquidity if needed to maintain the Company's growth strategy, take advantage of business opportunities, and fund its capital program and commitments. Credit facility commitments can be further increased up to a total of $4.0 billion upon agreement between the Company and participating lenders. | |||||||||||||
The Company had $165 million of outstanding borrowings on its credit facility at December 31, 2014, which subsequently increased to $605 million at February 17, 2015 as a result of additional borrowings incurred for the payment of amounts owed in connection with the Company's 2014 drilling program and to fund a portion of its 2015 drilling program. Borrowings bear interest at market-based interest rates plus a margin that is based on the terms of the borrowing and the credit ratings assigned to the Company's senior unsecured debt. | |||||||||||||
After increasing its aggregate commitments in February 2015, the Company had approximately $1.9 billion of borrowing availability on its credit facility at February 17, 2015. The Company incurs commitment fees based on currently assigned credit ratings of 0.225% per annum of the daily average amount of unused borrowing availability. | |||||||||||||
The credit facility contains certain restrictive covenants including a requirement that the Company maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. This ratio represents the ratio of net debt (total debt less cash and cash equivalents) divided by the sum of net debt plus total shareholders' equity. The Company was in compliance with this covenant at December 31, 2014. | |||||||||||||
Senior notes | |||||||||||||
In May 2014, the Company issued $1.0 billion of 3.8% Senior Notes due 2024 and $700 million of 4.9% Senior Notes due 2044 and received total net proceeds of approximately $1.68 billion after deducting the initial purchasers' fees. The Company used a portion of the net proceeds from the offerings to repay all borrowings then outstanding under its credit facility, which had a balance prior to payoff of $1.01 billion, and to finance the redemption of its 2019 Notes as discussed below. The remaining net proceeds were used to fund a portion of the Company's 2014 capital program and for general corporate purposes. | |||||||||||||
In July 2014, the Company redeemed its 2019 Notes 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 includes 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 for the year ended December 31, 2014. | |||||||||||||
The following table summarizes the maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding senior note obligations. | |||||||||||||
2020 Notes | 2021 Notes | 2022 Notes | 2023 Notes | 2024 Notes | 2044 Notes | ||||||||
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, Sept. 15 | April 15, Oct. 15 | June 1, Dec. 1 | June 1, Dec. 1 | |||||||
Call premium redemption period (1) | 1-Oct-15 | April 1, 2016 | 15-Mar-17 | — | — | — | |||||||
Make-whole redemption period (2) | 1-Oct-15 | April 1, 2016 | 15-Mar-17 | Jan 15, 2023 | Mar 1, 2024 | Dec 1, 2043 | |||||||
Equity offering redemption period (3) | — | — | 15-Mar-15 | — | — | — | |||||||
-1 | On or after these dates, the Company has the option to redeem all or a portion of its senior notes 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 at the “make-whole” redemption prices or amounts specified in the Indentures plus any accrued and unpaid interest to the date of redemption. | ||||||||||||
-3 | At any time prior to this date, the Company may redeem up to 35% of the principal amount of its 2022 Notes under certain circumstances with the net cash proceeds from one or more equity offerings at the redemption prices specified in the indenture for the 2022 Notes 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, 2014. Two of the Company’s subsidiaries, Banner Pipeline Company, L.L.C. and CLR Asset Holdings, LLC, which have no material assets or operations, fully and unconditionally guarantee the senior notes. The Company’s other subsidiaries, the value of whose assets and operations are minor, do not guarantee the senior notes. | |||||||||||||
Note payable | |||||||||||||
In February 2012, 20 Broadway Associates LLC, a 100% owned subsidiary of the Company, borrowed $22 million under a 10-year amortizing term loan secured by the Company’s corporate office building in Oklahoma City, Oklahoma. The loan bears interest at a fixed rate of 3.14% per annum. Principal and interest are payable monthly through the loan’s maturity date of February 26, 2022. Accordingly, approximately $2.1 million is reflected as a current liability under the caption “Current portion of long-term debt” in the consolidated balance sheets at December 31, 2014. |
Income_Taxes
Income Taxes | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Income Tax Disclosure [Abstract] | |||||||||||||
Income Taxes | Income Taxes | ||||||||||||
The items comprising the provision for income taxes are as follows for the periods presented: | |||||||||||||
Year ended December 31, | |||||||||||||
In thousands | 2014 | 2013 | 2012 | ||||||||||
Current income tax provision: | |||||||||||||
United States federal | $ | — | $ | 6,193 | $ | 9,191 | |||||||
Various states | 20 | 16 | 1,326 | ||||||||||
Total current income tax provision | 20 | 6,209 | 10,517 | ||||||||||
Deferred income tax provision: | |||||||||||||
United States federal | 527,315 | 403,002 | 383,157 | ||||||||||
Various states | 57,362 | 39,619 | 22,137 | ||||||||||
Total deferred income tax provision | 584,677 | 442,621 | 405,294 | ||||||||||
Total provision for income taxes | $ | 584,697 | $ | 448,830 | $ | 415,811 | |||||||
The provision for income taxes differs from the amount computed by applying the United States statutory federal income tax rate to income before income taxes. The sources and tax effects of the difference are as follows: | |||||||||||||
Year ended December 31, | |||||||||||||
In thousands | 2014 | 2013 | 2012 | ||||||||||
Expected income tax expense based on US statutory tax rate of 35% | $ | 546,713 | $ | 424,567 | $ | 404,319 | |||||||
State income taxes, net of federal benefit | 42,169 | 25,838 | 15,213 | ||||||||||
Canadian valuation allowance | 4,389 | — | — | ||||||||||
Effect of differing statutory tax rate in Canada | (1,900 | ) | — | — | |||||||||
Other, net | (6,674 | ) | (1,575 | ) | (3,721 | ) | |||||||
Provision for income taxes | $ | 584,697 | $ | 448,830 | $ | 415,811 | |||||||
The components of the Company’s deferred tax assets and liabilities as of December 31, 2014 and 2013 are as follows: | |||||||||||||
December 31, | |||||||||||||
In thousands | 2014 | 2013 | |||||||||||
Current: | |||||||||||||
Deferred tax assets (1) | |||||||||||||
Non-cash losses on derivatives | $ | — | $ | 33,029 | |||||||||
Other | 3,274 | 2,288 | |||||||||||
Total current deferred tax assets | 3,274 | 35,317 | |||||||||||
Deferred tax liabilities | |||||||||||||
Non-cash gains on derivatives | (19,293 | ) | — | ||||||||||
Gain on derivative liquidations | (128,198 | ) | — | ||||||||||
Other | (1,132 | ) | (645 | ) | |||||||||
Total current deferred tax liabilities | (148,623 | ) | (645 | ) | |||||||||
Net current deferred tax assets (liabilities) (2) | (145,349 | ) | 34,672 | ||||||||||
Noncurrent: | |||||||||||||
Deferred tax assets | |||||||||||||
Net operating loss carryforwards | 60,904 | 41,791 | |||||||||||
Non-cash losses on derivatives | — | 2,975 | |||||||||||
Alternative minimum tax carryforwards | 38,715 | 38,689 | |||||||||||
Equity compensation | 22,255 | 16,961 | |||||||||||
Other | 10,545 | 3,259 | |||||||||||
Total noncurrent deferred tax assets | 132,419 | 103,675 | |||||||||||
Canadian valuation allowance | (4,389 | ) | — | ||||||||||
Total noncurrent deferred tax assets, net of valuation allowance | 128,030 | 103,675 | |||||||||||
Deferred tax liabilities | |||||||||||||
Property and equipment | (2,254,343 | ) | (1,840,331 | ) | |||||||||
Non-cash gains on derivatives | (10,976 | ) | — | ||||||||||
Other | (4,158 | ) | (156 | ) | |||||||||
Total noncurrent deferred tax liabilities | (2,269,477 | ) | (1,840,487 | ) | |||||||||
Net noncurrent deferred tax liabilities | (2,141,447 | ) | (1,736,812 | ) | |||||||||
Net deferred tax liabilities | $ | (2,286,796 | ) | $ | (1,702,140 | ) | |||||||
-1 | Deferred and prepaid taxes on the consolidated balance sheets contain receivables of $63.3 million and $9.7 million for prepaid income taxes at December 31, 2014 and 2013, respectively. | ||||||||||||
-2 | The net liability balance at December 31, 2014 is included in the caption "Accrued liabilities and other" in the consolidated balance sheets. The net asset balance at December 31, 2013 is included in the caption "Deferred and prepaid taxes" in the consolidated balance sheets. | ||||||||||||
As of December 31, 2014, the Company had federal and state net operating loss carryforwards of $19 million and $1.39 billion, respectively. The federal net operating loss carryforward will begin expiring in 2033. The Oklahoma net operating loss carryforward of $1.37 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 $39 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 2011. | |||||||||||||
We recorded a $4.4 million valuation allowance for deferred tax assets at December 31, 2014. Our Canadian subsidiary 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, 2014 | |||||
Leases [Abstract] | |||||
Lease Commitments | Lease Commitments | ||||
The Company’s operating lease obligations primarily represent leases for office equipment, communication towers, and tanks for storage of hydraulic fracturing fluids. Lease payments associated with operating leases for the years ended December 31, 2014, 2013 and 2012 were $8.0 million, $3.0 million and $2.2 million, respectively, a portion of which was capitalized and/or billed to other interest owners. At December 31, 2014, the minimum future rental commitments under operating leases having lease terms in excess of one year are as follows: | |||||
In thousands | Total amount | ||||
2015 | $ | 4,953 | |||
2016 | 3,256 | ||||
2017 | 1,234 | ||||
2018 | 856 | ||||
2019 | 300 | ||||
Thereafter | 3,468 | ||||
Total obligations | $ | 14,067 | |||
Commitments_and_Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2014 | |
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, 2014. The commitments under these arrangements are not recorded in the accompanying consolidated balance sheets. | |
Drilling commitments – As of December 31, 2014, the Company had drilling rig contracts with various terms extending through July 2018. These contracts were entered into in the ordinary course of business to ensure rig availability to allow the Company to execute its business objectives in its strategic plays. Future commitments as of December 31, 2014 total approximately $610 million, of which $246 million is expected to be incurred in 2015, $212 million in 2016, $123 million in 2017, and $29 million in 2018. | |
Pipeline transportation commitments – The Company has entered into firm transportation commitments to guarantee pipeline access capacity on operational crude oil and natural gas pipelines in order to reduce the impact of possible production curtailments that may arise due to limited transportation capacity. The commitments, which have varying terms extending as far as 2025, require the Company to pay per-unit transportation charges regardless of the amount of pipeline capacity used. Future commitments remaining as of December 31, 2014 under the operational pipeline transportation arrangements amount to approximately $969 million, of which $182 million is expected to be incurred in 2015, $187 million in 2016, $181 million in 2017, $176 million in 2018, $140 million in 2019, and $103 million thereafter. Included in these amounts is approximately $96 million of commitments associated with a 5-year joint tariff arrangement between an unaffiliated party and an affiliate controlled by the Company's principal shareholder up through February 13, 2015 as discussed in Note 11. Related Party Transactions. | |
Further, the Company is a party to an additional 5-year firm transportation commitment 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. Future commitments under the non-operational arrangement total approximately $260 million at December 31, 2014. This commitment represents aggregate transportation charges expected to be incurred over the 5-year term beginning when the proposed pipeline project is completed and becomes operational. The exact timing of the commencement of pipeline operations is not known due to uncertainties involving matters such as regulatory approvals, resolution of legal and environmental disputes, construction progress, and the ultimate probability of pipeline completion. Accordingly, the timing of the Company’s obligations under this non-operational arrangement cannot be predicted with certainty and may not be incurred on a ratable basis over a calendar year or may not be incurred at all. | |
The Company’s pipeline commitments are for production primarily in the North region where the Company allocates a significant portion of its capital expenditures. The Company is not committed under these contracts to deliver fixed and determinable quantities of crude oil or natural gas in the future. | |
Fuel purchase commitment – The Company has entered into a forward purchase contract with a third party to purchase specified quantities of diesel fuel at specified prices each month over the period from January 2015 through June 2016 for use in the normal course of drilling operations. Over the contract term, the Company has committed to purchase a total of approximately 31 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, 2014 total approximately $96 million, of which $64 million is expected to be incurred in 2015 and $32 million is expected to be incurred in 2016. | |
Litigation – In November 2010, an alleged class action was filed against the Company alleging the Company improperly deducted post-production costs from royalties paid to plaintiffs and other royalty interest owners as categorized in the petition from crude oil and natural gas wells located in Oklahoma. The plaintiffs have 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 alleged class. The Company has responded to the petition, denied the allegations and raised a number of affirmative defenses. Discovery is ongoing and information and documents continue to be exchanged. 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. The class has not been certified. The class certification hearing is currently scheduled for May 25, 2015. Plaintiffs have indicated that if the class is certified they may seek damages in excess of $165 million 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 is involved in various other legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims and other matters. While the outcome of these legal matters cannot be predicted with certainty, the Company does not expect them to have a material effect on its financial condition, results of operations or cash flows. As of December 31, 2014 and 2013, the Company has recorded a liability on the consolidated balance sheets under the caption “Other noncurrent liabilities” of $2.9 million and $1.7 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, 2014 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Related Party Transactions |
The Company sells a portion of its natural gas production to affiliates. For the years ended December 31, 2014, 2013, and 2012, these sales amounted to $95.1 million, $100.4 million, and $57.0 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. At December 31, 2014 and 2013, $13.1 million and $12.7 million, respectively, was due to the Company from these affiliates, which is included in the caption “Receivables—Affiliated parties” in the consolidated balance sheets. At December 31, 2014 and 2013, $0.3 million and $0.2 million was due from the Company to affiliates for transportation and processing costs associated with these transactions, which is included in the caption “Payables to affiliated parties” in the consolidated balance sheets. | |
The Company engages in crude oil trades with an affiliate from time to time to obtain space on pipeline systems in the Company's operating areas. For the year ended December 31, 2012, crude oil sales to the affiliate totaled 21,000 barrels generating sales proceeds of $1.9 million, which is included in the caption “Crude oil and natural gas sales to affiliates” in the consolidated statements of comprehensive income. There were no crude oil sales to the affiliate in 2014 or 2013. In 2013 and 2012, the Company purchased 30,000 barrels and 2,000 barrels, respectively, from the affiliate for $3.0 million and $0.2 million, respectively. | |
The Company incurs affiliate costs associated with field services such as compression and drilling rig services, purchases of residue fuel gas and reclaimed crude oil, and reimbursements of generator rentals and fuel. The Company capitalized costs of $5.9 million, $5.7 million and $5.0 million in 2014, 2013, and 2012, respectively, associated with drilling rig services provided by an affiliate. Production and other expenses attributable to these affiliate transactions were $5.1 million, $1.4 million and $2.0 million for the years ended December 31, 2014, 2013, and 2012, respectively. The total amount paid to these affiliates, a portion of which was billed to other interest owners, was $58.2 million, $48.5 million and $32.7 million for the years ended December 31, 2014, 2013, and 2012, respectively. At December 31, 2014 and 2013, $5.6 million and $5.1 million, respectively, was due to these affiliates related to these transactions, which is included in the caption “Payables to affiliated parties” in the consolidated balance sheets. | |
The Company is a party to 5-year firm transportation commitments under a joint tariff arrangement to guarantee pipeline access capacity totaling 10,000 barrels of crude oil per day on pipelines operated by an unaffiliated party and an affiliated party controlled by the Company's principal shareholder. The commitments require the Company to pay joint tariff transportation charges totaling $5.25 per barrel regardless of the amount of pipeline capacity used, which will be allocated between the affiliated party and unaffiliated party. Future commitments under the joint tariff arrangement, a portion of which will be allocated to the affiliate, total approximately $96 million at December 31, 2014, representing aggregate joint tariff transportation charges expected to be incurred over the 5-year term. The Company expects to begin satisfying its commitments under the arrangement beginning in the first quarter of 2015. The Company expects it will receive invoices from, and submit payments to, the unaffiliated party for fees owed under the arrangement, with the unaffiliated party being responsible for allocating a portion of such fees to the affiliated party. | |
The affiliate transactions described above, with the exception of drilling rig services, represent transactions between the Company and Hiland Partners, LP and its subsidiaries ("Hiland"). Hiland was controlled by the Company's principal shareholder up through February 13, 2015, at which time it was sold to an unaffiliated third party. After February 13, 2015, the transactions above, to the extent they continue with the acquirer of Hiland, will no longer be considered related party transactions. | |
Certain officers and other key employees 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 $1.7 million, $2.3 million, and $38.3 million and received payments from these affiliates of $0.8 million, $1.3 million, and $38.5 million during the years ended December 31, 2014, 2013, and 2012, respectively, relating to the operations of the respective properties. The Company also paid to these affiliates $0.3 million in 2012 for their share of proceeds from undeveloped leasehold sales, with no such payments in 2013 or 2014. At December 31, 2014 and 2013, $0.2 million and $0.4 million was due from these affiliates and approximately $0.1 million and $0.2 million was due to these affiliates, respectively, relating to these transactions. | |
Prior to July 2012, the Company leased office space under an operating lease from an entity owned by the Company’s principal shareholder. Rents paid associated with the leases totaled approximately $0.7 million for the year ended December 31, 2012. | |
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 2014, 2013, and 2012, the Company charged affiliates approximately $51,000, $55,000, and $112,000, respectively, for use of its corporate aircraft, crews, fuel, utilities and reimbursement of expenses and received $39,000 and $379,000 from affiliates in 2014 and 2013, respectively. The Company was charged $97,000, $51,000, and $102,000, respectively, by affiliates for use of their aircraft, crews, and reimbursement of expenses during 2014, 2013, and 2012 and paid $34,000 and $238,000 to the affiliates in 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. The total amount invoiced and capitalized for the second half of 2014 associated with the projects was $1.8 million. The total amount paid, a portion of which was billed to other interest owners, was $1.9 million for the second half of 2014 and approximately $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. | |
In August 2012, the Company acquired the assets of Wheatland Oil Inc. ("Wheatland") through the issuance of shares of the Company’s common stock. Wheatland is owned 75% by the Harold G. Hamm Trust (formerly the Revocable Inter Vivos Trust of Harold G. Hamm), a trust of which Harold G. Hamm, the Company’s Chief Executive Officer, Chairman of the Board and principal shareholder is the trustee and sole beneficiary, and 25% by the Company’s Vice Chairman of Strategic Growth Initiatives, Jeffrey B. Hume. As consideration for the acquisition, the Company issued approximately 7.8 million shares of its common stock, par value $0.01 per share, to the shareholders of Wheatland in accordance with the terms of the arrangement. The fair value of the consideration transferred by the Company at closing was approximately $279 million. In 2013, Wheatland paid the Company approximately $0.5 million upon final settlement of purchase price adjustments under the terms of the arrangement. For accounting purposes, the Wheatland acquisition represented a transaction between entities under common control as Mr. Hamm is the controlling shareholder of both the Company and Wheatland. Accordingly, the Company recorded the assets acquired and liabilities assumed at Wheatland’s carrying amount. The net book basis of Wheatland’s assets was approximately $82 million, primarily representing $177 million for acquired crude oil and natural gas properties partially offset by $38 million of joint interest obligations assumed, $0.6 million of asset retirement obligations assumed and $57 million of deferred income tax liabilities recognized. |
StockBased_Compensation
Stock-Based Compensation | 12 Months Ended | ||||||||||||||
Dec. 31, 2014 | |||||||||||||||
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||||||||||||||
Stock-Based Compensation | Stock-Based Compensation | ||||||||||||||
The Company has granted stock options to employees pursuant to the Continental Resources, Inc. 2000 Stock Option Plan (“2000 Plan”) and 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, is reflected in the table below for the periods presented. | |||||||||||||||
Year ended December 31, | |||||||||||||||
In thousands | 2014 | 2013 | 2012 | ||||||||||||
Non-cash equity compensation | $ | 54,353 | $ | 39,890 | $ | 29,057 | |||||||||
Restricted stock | |||||||||||||||
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, 2014, the Company had a maximum of 18,104,686 shares of restricted stock available to grant to officers, directors and select employees under the 2013 Plan. | |||||||||||||||
Restricted stock is awarded in the name of the recipient and constitutes issued and outstanding shares of the Company’s common stock for all corporate purposes during the period of restriction and, except as otherwise provided under the 2013 Plan or agreement relevant to a given award, includes the right to vote the restricted stock or to receive dividends, subject to forfeiture. Restricted stock grants generally vest over periods ranging from one to three years. | |||||||||||||||
A summary of changes in non-vested restricted shares from December 31, 2011 to December 31, 2014 is presented below. | |||||||||||||||
Number of | Weighted | ||||||||||||||
non-vested | average | ||||||||||||||
shares | grant-date | ||||||||||||||
fair value | |||||||||||||||
Non-vested restricted shares at December 31, 2011 | 2,396,688 | $ | 24.33 | ||||||||||||
Granted | 1,832,056 | 36.73 | |||||||||||||
Vested | (889,446 | ) | 22.63 | ||||||||||||
Forfeited | (80,374 | ) | 29.53 | ||||||||||||
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 | $ | 37.5 | ||||||||||||
Granted | 1,424,764 | 61.11 | |||||||||||||
Vested | (1,007,166 | ) | 35.91 | ||||||||||||
Forfeited | (453,146 | ) | 44.9 | ||||||||||||
Non-vested restricted shares at December 31, 2014 | 2,678,764 | $ | 49.4 | ||||||||||||
The grant date fair value of restricted stock represents the closing market price of the Company’s common stock on the date of grant. Compensation expense for a restricted stock grant is a fixed amount determined at the grant date fair value and is recognized ratably over the vesting period as services are rendered by employees and directors. The expected life of restricted stock is based on the non-vested period that remains subsequent to the date of grant. There are no post-vesting restrictions related to the Company’s restricted stock. The fair value of restricted stock that vested during 2014, 2013 and 2012 at the vesting date was $58.2 million, $49.4 million and $33.0 million, respectively. As of December 31, 2014, there was approximately $72 million of unrecognized compensation expense related to non-vested restricted stock. This expense is expected to be recognized ratably over a weighted average period of 1.4 years. | |||||||||||||||
Stock options | |||||||||||||||
Effective October 1, 2000, the Company adopted the 2000 Plan and granted stock options to certain eligible employees. On November 10, 2005, the 2000 Plan was terminated. As of March 31, 2012, all options issued under the 2000 Plan had been exercised or expired. The following table summarizes stock option activity under the 2000 Plan for the periods presented: | |||||||||||||||
Outstanding | Exercisable | ||||||||||||||
Number of | Weighted | Number of | Weighted | ||||||||||||
options | average | options | average | ||||||||||||
exercise | exercise | ||||||||||||||
price | price | ||||||||||||||
Outstanding at December 31, 2011 | 173,000 | $ | 0.36 | 173,000 | $ | 0.36 | |||||||||
Exercised | (173,000 | ) | $ | 0.36 | |||||||||||
Outstanding at December 31, 2012 | — | — | — | — | |||||||||||
The intrinsic value of a stock option is the amount by which the value of the underlying stock exceeds the exercise price of the option at its exercise date. The total intrinsic value of options exercised during the year ended December 31, 2012 was $7.6 million. |
Property_Acquisitions_and_Disp
Property Acquisitions and Dispositions | 12 Months Ended |
Dec. 31, 2014 | |
Extractive Industries [Abstract] | |
Property Acquisitions and Dispositions | Property Acquisitions and Dispositions |
2012 Acquisitions | |
In December 2012, the Company acquired certain producing and undeveloped properties in the Bakken play of North Dakota from a third party for $663.3 million, of which $477.1 million was allocated to producing properties. In the transaction, the Company acquired interests in approximately 119,000 net acres as well as producing properties with production of approximately 6,500 net barrels of oil equivalent per day. | |
In August 2012, the Company acquired the assets of Wheatland Oil Inc. through the issuance of shares of the Company’s common stock. See Note 11. Related Party Transactions for further discussion. | |
In February 2012, the Company acquired certain producing and undeveloped properties in the Bakken play of North Dakota from a third party for $276 million, of which $51.7 million was allocated to producing properties. In the transaction, the Company acquired interests in approximately 23,100 net acres as well as producing properties with production of approximately 1,000 net barrels of oil equivalent per day. | |
2012 Dispositions | |
In December 2012, the Company sold its producing crude oil and natural gas properties and supporting assets in its East region to a third party for $126.4 million. In connection with the transaction, the Company recognized a pre-tax gain of $68.0 million, which included the effect of removing $8.3 million of asset retirement obligations for the disposed properties previously recognized by the Company that were assumed by the buyer. The disposed properties represented an immaterial portion of the Company’s total proved reserves, production, and revenues. | |
In June 2012, the Company assigned certain non-strategic leaseholds and producing properties located in Oklahoma to a third party for $15.9 million and recognized a pre-tax gain on the transaction of $15.9 million, which included the effect of removing $0.6 million of asset retirement obligations for the disposed properties previously recognized by the Company that were assumed by the buyer. The disposed properties represented an immaterial portion of the Company’s total proved reserves, production, and revenues. | |
In February 2012, the Company assigned certain non-strategic leaseholds and producing properties located in Wyoming to a third party for $84.4 million. In connection with the transaction, the Company recognized a pre-tax gain of $50.1 million, which included the effect of removing $11.1 million of asset retirement obligations for the disposed properties previously recognized by the Company that were assumed by the buyer. The disposed properties represented an immaterial portion of the Company’s total proved reserves, production, and revenues. | |
2014 Disposition and Related Joint Development Agreement | |
In September 2014, the Company entered into an agreement with a U.S. subsidiary of SK E&S Co. Ltd (“SK”) of South Korea to jointly develop a significant portion of the Company’s Northwest Cana natural gas properties. Under the agreement, Continental sold a 49.9% interest in approximately 44,000 net acres in the Northwest Cana area of the Anadarko Woodford Shale play, along with interests in 37 producing wells. Continental received approximately $90 million in cash at closing and SK has committed to pay Continental an additional $270 million to fund, or carry, 50% of Continental's remaining share of future drilling and completion costs over a period of approximately five years extending into 2019. The disposed properties represented an immaterial portion of the Company’s total proved reserves, production, and revenues and the transaction did not have a material impact on results of operations for the year ended December 31, 2014. | |
The gains on the dispositions described above are included in the caption “Gain on sale of assets, net” in the consolidated statements of comprehensive income. |
Crude_Oil_and_Natural_Gas_Prop
Crude Oil and Natural Gas Property Information | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
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, 2014, 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, 2014, 2013 and 2012. | |||||||||||||
Year ended December 31, | |||||||||||||
In thousands | 2014 | 2013 | 2012 | ||||||||||
Crude oil and natural gas sales (1) | $ | 4,203,022 | $ | 3,573,431 | $ | 2,349,500 | |||||||
Production expenses | (352,472 | ) | (282,197 | ) | (195,440 | ) | |||||||
Production taxes and other expenses (1) | (349,760 | ) | (298,787 | ) | (198,505 | ) | |||||||
Exploration expenses | (50,067 | ) | (34,947 | ) | (23,507 | ) | |||||||
Depreciation, depletion, amortization and accretion | (1,338,351 | ) | (953,796 | ) | (683,207 | ) | |||||||
Property impairments | (616,888 | ) | (220,508 | ) | (122,274 | ) | |||||||
Income taxes | (559,311 | ) | (659,783 | ) | (428,095 | ) | |||||||
Results from crude oil and natural gas producing activities | $ | 936,173 | $ | 1,123,413 | $ | 698,472 | |||||||
-1 | Natural gas transportation and processing charges totaling $33.3 million and $29.9 million for the years ended December 31, 2013 and 2012, respectively, have been reclassified from "Production taxes and other expenses" to "Crude oil and natural gas sales" to conform to the current year presentation as discussed in Note 1. Organization and Summary of Significant Accounting Policies. | ||||||||||||
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, 2014, 2013 and 2012 are presented below: | |||||||||||||
Year ended December 31, | |||||||||||||
In thousands | 2014 | 2013 | 2012 | ||||||||||
Property Acquisition Costs: | |||||||||||||
Proved | $ | 48,917 | $ | 16,604 | $ | 738,415 | |||||||
Unproved | 409,529 | 546,881 | 745,601 | ||||||||||
Total property acquisition costs | 458,446 | 563,485 | 1,484,016 | ||||||||||
Exploration Costs | 863,606 | 687,767 | 857,681 | ||||||||||
Development Costs | 3,670,448 | 2,549,203 | 1,975,660 | ||||||||||
Total | $ | 4,992,500 | $ | 3,800,455 | $ | 4,317,357 | |||||||
Exploration costs above include asset retirement costs of $1.2 million, $1.8 million and $3.3 million and development costs above include asset retirement costs of $19.1 million, $6.0 million and $1.0 million for the years ended December 31, 2014, 2013 and 2012, 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, 2014 and 2013 are as follows: | |||||||||||||
December 31, | |||||||||||||
In thousands | 2014 | 2013 | |||||||||||
Proved crude oil and natural gas properties | $ | 17,045,967 | $ | 12,423,878 | |||||||||
Unproved crude oil and natural gas properties | 966,080 | 1,181,268 | |||||||||||
Total | 18,012,047 | 13,605,146 | |||||||||||
Less accumulated depreciation, depletion and amortization | (4,601,864 | ) | (3,083,180 | ) | |||||||||
Net capitalized costs | $ | 13,410,183 | $ | 10,521,966 | |||||||||
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 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 | 2014 | 2013 | 2012 | ||||||||||
Balance at January 1 | $ | 152,775 | $ | 92,699 | $ | 128,123 | |||||||
Additions to capitalized exploratory well costs pending determination of proved reserves | 627,853 | 548,933 | 485,530 | ||||||||||
Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves | (671,618 | ) | (479,507 | ) | (520,187 | ) | |||||||
Capitalized exploratory well costs charged to expense | (15,589 | ) | (9,350 | ) | (767 | ) | |||||||
Balance at December 31 | $ | 93,421 | $ | 152,775 | $ | 92,699 | |||||||
Number of gross wells | 119 | 67 | 46 | ||||||||||
As of December 31, 2014, exploratory drilling costs of $4.5 million, representing one well, were suspended one year beyond the completion of drilling and is expected to be fully evaluated in 2015. Of the suspended costs, $0.5 million was incurred in 2014 and $4.0 million was incurred in 2013. |
Supplemental_Crude_Oil_and_Nat
Supplemental Crude Oil and Natural Gas Information (Unaudited) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
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, 2014, 2013, and 2012, respectively. Properties comprising 99% of proved crude oil reserves and 95% of proved natural gas reserves were evaluated by Ryder Scott as of December 31, 2014. 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, 2014. | |||||||||||||
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, 2014, 2013 and 2012 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, 2014, 2013 and 2012 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 | |||||||||||
(MBbls) | (MMcf) | (MBoe) | |||||||||||
Proved reserves as of December 31, 2011 | 326,133 | 1,093,832 | 508,438 | ||||||||||
Revisions of previous estimates | 33,272 | (174,736 | ) | 4,149 | |||||||||
Extensions, discoveries and other additions | 166,844 | 400,848 | 233,652 | ||||||||||
Production | (25,070 | ) | (63,875 | ) | (35,716 | ) | |||||||
Sales of minerals in place | (7,165 | ) | (4,046 | ) | (7,838 | ) | |||||||
Purchases of minerals in place | 67,149 | 89,061 | 81,992 | ||||||||||
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. 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. | |||||||||||||
Upward revisions to crude oil reserves in 2012 resulted from better than anticipated production performance. Downward revisions to natural gas reserves in 2012 resulted from the removal of proved undeveloped ("PUD") reserves for certain dry gas properties not expected to be developed given the pricing environment for natural gas. | |||||||||||||
Downward revisions to crude oil and natural gas 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 crude oil and natural gas 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. The drilling program was refined to concentrate efforts in core areas of the Bakken and SCOOP that provide the opportunity to improve recoveries and rates of return. 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 the opportunity for improved well productivity and economics. The combination of these and other factors resulted in the removal of 53 MMBo and 315 Bcf (105 MMBoe) of PUD reserves in 2014. | |||||||||||||
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 the Bakken field. Proved reserve additions in the Bakken totaled 184 MMBo and 231 Bcf (222 MMBoe) for the year ended December 31, 2014. Additionally, 2014 extensions and discoveries were significantly impacted by successful drilling results in the SCOOP play, resulting in 55 MMBo and 921 Bcf (208 MMBoe) of proved reserve additions during the year. Significant progress continued to be made in 2014 in developing and expanding the Company's Bakken and SCOOP assets, both laterally and vertically, through strategic exploration, development, planning and technology. | |||||||||||||
Sales of minerals in place. These are reductions to proved reserves resulting from the disposition of properties during a period. See Note 13. Property Acquisitions and 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. See Note 13. Property Acquisitions and Dispositions for further discussion of notable acquisitions. | |||||||||||||
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, 2014, 2013 and 2012: | |||||||||||||
December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Proved Developed Reserves | |||||||||||||
Crude oil (MBbl) | 342,137 | 278,630 | 226,870 | ||||||||||
Natural Gas (MMcf) | 962,051 | 768,969 | 545,499 | ||||||||||
Total (MBoe) | 502,479 | 406,792 | 317,786 | ||||||||||
Proved Undeveloped Reserves | |||||||||||||
Crude oil (MBbl) | 524,223 | 459,158 | 334,293 | ||||||||||
Natural Gas (MMcf) | 1,946,335 | 1,309,051 | 795,585 | ||||||||||
Total (MBoe) | 848,612 | 677,333 | 466,891 | ||||||||||
Total Proved Reserves | |||||||||||||
Crude oil (MBbl) | 866,360 | 737,788 | 561,163 | ||||||||||
Natural Gas (MMcf) | 2,908,386 | 2,078,020 | 1,341,084 | ||||||||||
Total (MBoe) | 1,351,091 | 1,084,125 | 784,677 | ||||||||||
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 incremental 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, 2014, 2013 and 2012. | |||||||||||||
December 31, | |||||||||||||
In thousands | 2014 | 2013 | 2012 | ||||||||||
Future cash inflows | $ | 90,867,459 | $ | 78,646,274 | $ | 54,362,574 | |||||||
Future production costs | (25,799,221 | ) | (21,333,460 | ) | (13,103,469 | ) | |||||||
Future development and abandonment costs | (12,842,174 | ) | (10,250,789 | ) | (8,295,130 | ) | |||||||
Future income taxes | (13,800,737 | ) | (12,447,127 | ) | (8,500,766 | ) | |||||||
Future net cash flows | 38,425,327 | 34,614,898 | 24,463,209 | ||||||||||
10% annual discount for estimated timing of cash flows | (19,992,293 | ) | (18,319,131 | ) | (13,282,852 | ) | |||||||
Standardized measure of discounted future net cash flows | $ | 18,433,034 | $ | 16,295,767 | $ | 11,180,357 | |||||||
The weighted average crude oil price (adjusted for location and quality differentials) utilized in the computation of future cash inflows was $84.54, $91.50, and $86.56 per barrel at December 31, 2014, 2013 and 2012, respectively. The weighted average natural gas price (adjusted for location and quality differentials) utilized in the computation of future cash inflows was $6.06, $5.36, and $4.31 per Mcf at December 31, 2014, 2013 and 2012, 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 | 2014 | 2013 | 2012 | ||||||||||
Standardized measure of discounted future net cash flows at January 1 | $ | 16,295,767 | $ | 11,180,357 | $ | 7,505,356 | |||||||
Extensions, discoveries and improved recoveries, less related costs | 5,516,528 | 6,613,665 | 3,724,136 | ||||||||||
Revisions of previous quantity estimates | (1,755,366 | ) | (1,765,300 | ) | 254,493 | ||||||||
Changes in estimated future development and abandonment costs | 476,665 | 1,942,585 | (298,148 | ) | |||||||||
Purchases (sales) of minerals in place, net | (3,196 | ) | 12,012 | 1,171,047 | |||||||||
Net change in prices and production costs | (1,925,349 | ) | 263,541 | (530,515 | ) | ||||||||
Accretion of discount | 1,629,576 | 1,118,036 | 750,536 | ||||||||||
Sales of crude oil and natural gas produced, net of production costs | (3,500,790 | ) | (2,992,447 | ) | (1,955,555 | ) | |||||||
Development costs incurred during the period | 2,466,748 | 1,210,223 | 1,095,156 | ||||||||||
Change in timing of estimated future production and other | (309,902 | ) | 464,111 | (102,519 | ) | ||||||||
Change in income taxes | (457,647 | ) | (1,751,016 | ) | (433,630 | ) | |||||||
Net change | 2,137,267 | 5,115,410 | 3,675,001 | ||||||||||
Standardized measure of discounted future net cash flows at December 31 | $ | 18,433,034 | $ | 16,295,767 | $ | 11,180,357 | |||||||
Quarterly_Financial_Data_Unaud
Quarterly Financial Data (Unaudited) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Quarterly Financial Information Disclosure [Abstract] | |||||||||||||||||
Quarterly Financial Data (Unaudited) | Quarterly Financial Data (Unaudited) | ||||||||||||||||
The Company’s unaudited quarterly financial data for 2014 and 2013 is summarized below. | |||||||||||||||||
Quarter ended | |||||||||||||||||
In thousands, except per share data | March 31 | June 30 | September 30 | December 31 | |||||||||||||
2014 | -2 | ||||||||||||||||
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 | |||||||
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 | |||||||||
2013 | |||||||||||||||||
Total revenues (1)(3) | $ | 702,643 | $ | 1,093,057 | $ | 814,887 | $ | 811,220 | |||||||||
Gain (loss) on derivative instruments, net (1) | $ | (84,831 | ) | $ | 199,056 | $ | (203,774 | ) | $ | (102,202 | ) | ||||||
Income from operations | $ | 270,146 | $ | 573,872 | $ | 328,043 | $ | 273,706 | |||||||||
Net income | $ | 140,627 | $ | 323,270 | $ | 167,498 | $ | 132,824 | |||||||||
Net income per share: | |||||||||||||||||
Basic | $ | 0.38 | $ | 0.88 | $ | 0.45 | $ | 0.36 | |||||||||
Diluted | $ | 0.38 | $ | 0.87 | $ | 0.45 | $ | 0.36 | |||||||||
-1 | Gains and losses on mark-to-market derivative instruments are reflected in “Total revenues” on both the consolidated statements of comprehensive income 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 as discussed in Note 5. Derivative Instruments. The 2014 fourth quarter also includes $340 million of pre-tax non-cash impairment charges ($214 million after tax, or $0.58 per basic and diluted share) as discussed in Note 6. Fair Value Measurements. | ||||||||||||||||
-3 | Total revenues for the quarterly periods of 2013 have been adjusted to conform to the current year presentation of natural gas transportation and processing charges as discussed in Note 1. Organization and Summary of Significant Accounting Policies. Reclassified amounts total $7.6 million, $7.7 million, $8.9 million and $9.1 million for the first, second, third and fourth quarters of 2013, respectively. |
Organization_and_Summary_of_Si1
Organization and Summary of Significant Accounting Policies (Policies) | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
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 in the North, South, and East regions of the United States. The North region consists of properties north of Kansas and west of the Mississippi River and includes North Dakota Bakken, Montana Bakken, and the Red River units. The South region includes Kansas and all properties south of Kansas and west of the Mississippi River including various plays in the South Central Oklahoma Oil Province (“SCOOP”), Northwest Cana and Arkoma areas of Oklahoma. The East region is comprised of undeveloped leasehold acreage east of the Mississippi River with no current drilling or production operations. | |||||||||
The Company’s operations are geographically concentrated in the North region, with that region comprising approximately 74% of the Company’s crude oil and natural gas production and approximately 83% of its crude oil and natural gas revenues for the year ended December 31, 2014. 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, 2014, approximately 69% of the Company’s estimated proved reserves were located in the North region. In 2012 and 2013, the Company significantly expanded its activity in the South region with its discovery and announcement of the SCOOP play in Oklahoma. The South region now comprises 26% of the Company's crude oil and natural gas production and 31% of its estimated proved reserves as of December 31, 2014. | |||||||||
The Company has focused its operations on the exploration and development of crude oil since the 1980s. For the year ended December 31, 2014, crude oil accounted for approximately 70% of the Company’s total production and approximately 85% of its crude oil and natural gas revenues. Crude oil represents approximately 64% of the Company's estimated proved reserves as of December 31, 2014. | |||||||||
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. | |||||||||
Stock Split | Stock split | ||||||||
On August 18, 2014, the Company's Board of Directors declared a 2-for-1 stock split of the Company's common stock to be effected in the form of a stock dividend. The stock dividend was distributed on September 10, 2014 to shareholders of record as of September 3, 2014. All previously reported common stock and earnings per share amounts have been retroactively adjusted in the accompanying financial statements and related notes to reflect the stock split. | |||||||||
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. In the opinion of management, all adjustments (consisting only of normal recurring adjustments) necessary for a fair presentation in accordance with U.S. GAAP have been included in these consolidated financial statements. | |||||||||
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, 2014 and 2013 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, 2014, the Company had cash deposits in excess of federally insured amounts of approximately $22.6 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, 2014, sales to the Company’s two largest purchasers accounted for approximately 14% and 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 2014. 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 the Company’s operating regions. | |||||||||
Inventories | Inventories | ||||||||
Inventories are stated at the lower of cost or market and consist of the following: | |||||||||
December 31, | |||||||||
In thousands | 2014 | 2013 | |||||||
Tubular goods and equipment | $ | 15,659 | $ | 11,139 | |||||
Crude oil | 86,520 | 43,301 | |||||||
Total | $ | 102,179 | $ | 54,440 | |||||
Crude oil inventories are valued at the lower of cost or market using the first-in, first-out inventory method. Crude oil inventories consist of the following volumes: | |||||||||
December 31, | |||||||||
MBbls | 2014 | 2013 | |||||||
Crude oil line fill and tank requirements | 1,323 | 370 | |||||||
Temporarily stored crude oil | 596 | 344 | |||||||
Total | 1,919 | 714 | |||||||
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 furniture and fixtures, automobiles, machinery and equipment, office equipment, computer equipment and software, 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 | |||||||||
Furniture and fixtures | 10 | ||||||||
Automobiles | 6-May | ||||||||
Machinery and equipment | 20-Oct | ||||||||
Office equipment, computer equipment and software | 10-Mar | ||||||||
Enterprise resource planning software | 25 | ||||||||
Buildings and improvements | Oct-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, or when events and circumstances indicate a possible decline in the recoverability of the carrying value of such field. 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. Individually significant non-producing properties, if any, are assessed for impairment on a property-by-property basis and, if the assessment indicates an impairment, a loss is recognized by providing a valuation allowance consistent with the level at which impairment was assessed. For individually insignificant non-producing properties, impairment losses 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 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 credit facility and amendments thereto are capitalized and amortized over the term of the facility 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 anticipated 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 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, 2014 and 2013. | |||||||||
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. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized. The Company’s policy is to recognize penalties and interest related to unrecognized tax benefits, if any, in income tax expense. | |||||||||
Earnings Per Share | Earnings per share | ||||||||
Basic net income per share is computed by dividing net income by the weighted-average number of shares outstanding for the period. Diluted net income per share reflects the potential dilution of non-vested restricted stock awards and stock options, which are calculated using the treasury stock method. | |||||||||
Foreign Currency Transactions and Translations Policy | 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. |
Organization_and_Summary_of_Si2
Organization and Summary of Significant Accounting Policies (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||||||||||||
Components of Inventories | Inventories are stated at the lower of cost or market and consist of the following: | ||||||||||||
December 31, | |||||||||||||
In thousands | 2014 | 2013 | |||||||||||
Tubular goods and equipment | $ | 15,659 | $ | 11,139 | |||||||||
Crude oil | 86,520 | 43,301 | |||||||||||
Total | $ | 102,179 | $ | 54,440 | |||||||||
Components of Crude Oil Inventories Volumes | Crude oil inventories consist of the following volumes: | ||||||||||||
December 31, | |||||||||||||
MBbls | 2014 | 2013 | |||||||||||
Crude oil line fill and tank requirements | 1,323 | 370 | |||||||||||
Temporarily stored crude oil | 596 | 344 | |||||||||||
Total | 1,919 | 714 | |||||||||||
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 | |||||||||||||
Furniture and fixtures | 10 | ||||||||||||
Automobiles | 6-May | ||||||||||||
Machinery and equipment | 20-Oct | ||||||||||||
Office equipment, computer equipment and software | 10-Mar | ||||||||||||
Enterprise resource planning software | 25 | ||||||||||||
Buildings and improvements | Oct-40 | ||||||||||||
Summary of Changes in Future Abandonment Liabilities | The following table summarizes the changes in the Company’s future abandonment liabilities from January 1, 2012 through December 31, 2014: | ||||||||||||
In thousands | 2014 | 2013 | 2012 | ||||||||||
Asset retirement obligations at January 1 | $ | 55,787 | $ | 47,171 | $ | 62,625 | |||||||
Accretion expense | 3,366 | 2,767 | 3,105 | ||||||||||
Revisions | 9,916 | 2,826 | (2,871 | ) | |||||||||
Plus: Additions for new assets | 9,022 | 6,009 | 6,679 | ||||||||||
Less: Plugging costs and sold assets (1) | (1,383 | ) | (2,986 | ) | (22,367 | ) | |||||||
Total asset retirement obligations at December 31 | $ | 76,708 | $ | 55,787 | $ | 47,171 | |||||||
Less: Current portion of asset retirement obligations at December 31 (2) | 1,246 | 1,434 | 2,227 | ||||||||||
Non-current portion of asset retirement obligations at December 31 | $ | 75,462 | $ | 54,353 | $ | 44,944 | |||||||
-1 | As a result of asset dispositions during the year ended December 31, 2012, the Company removed $20.0 million of its previously recognized asset retirement obligations that were assumed by the buyers. See Note 13. Property Acquisitions and Dispositions for further discussion. | ||||||||||||
-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 | The following table presents the calculation of basic and diluted weighted average shares outstanding and net income per share for the years ended December 31, 2014, 2013 and 2012. All stock options issued by the Company in prior periods had been exercised or had expired as of March 31, 2012. Weighted average shares and net income per share amounts for 2012 and 2013 have been retroactively adjusted to reflect the Company's 2-for-1 stock split occurring in September 2014. | ||||||||||||
Year ended December 31, | |||||||||||||
In thousands, except per share data | 2014 | 2013 | 2012 | ||||||||||
Income (numerator): | |||||||||||||
Net income - basic and diluted | $ | 977,341 | $ | 764,219 | $ | 739,385 | |||||||
Weighted average shares (denominator): | |||||||||||||
Weighted average shares - basic | 368,829 | 368,150 | 362,680 | ||||||||||
Non-vested restricted stock | 1,929 | 1,548 | 980 | ||||||||||
Stock options | — | — | 32 | ||||||||||
Weighted average shares - diluted | 370,758 | 369,698 | 363,692 | ||||||||||
Net income per share: | |||||||||||||
Basic | $ | 2.65 | $ | 2.08 | $ | 2.04 | |||||||
Diluted | $ | 2.64 | $ | 2.07 | $ | 2.03 | |||||||
Supplemental_Cash_Flow_Informa1
Supplemental Cash Flow Information (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
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 taxes. 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 | 2014 | 2013 | 2012 | ||||||||||
Supplemental cash flow information: | |||||||||||||
Cash paid for interest | $ | 267,384 | $ | 209,815 | $ | 102,043 | |||||||
Cash paid for income taxes | 53,457 | 29,017 | 829 | ||||||||||
Cash received for income tax refunds | 7 | 174 | 13,866 | ||||||||||
Non-cash investing activities: | |||||||||||||
Increase in accrued capital expenditures | 290,782 | 89,482 | 49,039 | ||||||||||
Acquisition of assets through issuance of common stock (Note 11) | — | — | 176,563 | ||||||||||
Asset retirement obligation additions and revisions, net | 18,938 | 8,835 | 3,808 | ||||||||||
Net_Property_and_Equipment_Tab
Net Property and Equipment (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Property, Plant and Equipment, Net [Abstract] | |||||||||
Schedule of Net Property and Equipment | Net property and equipment includes the following at December 31, 2014 and 2013: | ||||||||
December 31, | |||||||||
In thousands | 2014 | 2013 | |||||||
Proved crude oil and natural gas properties | $ | 17,045,967 | $ | 12,423,878 | |||||
Unproved crude oil and natural gas properties | 966,080 | 1,181,268 | |||||||
Service properties, equipment and other | 274,584 | 236,233 | |||||||
Total property and equipment | 18,286,631 | 13,841,379 | |||||||
Accumulated depreciation, depletion and amortization | (4,650,779 | ) | (3,120,107 | ) | |||||
Net property and equipment | $ | 13,635,852 | $ | 10,721,272 | |||||
Accrued_Liabilities_and_Other_
Accrued Liabilities and Other (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Accrued Liabilities and Other Liabilities [Abstract] | |||||||||
Schedule of Accrued Liabilities and Other | Accrued liabilities and other includes the following at December 31, 2014 and 2013: | ||||||||
December 31, | |||||||||
In thousands | 2014 | 2013 | |||||||
Prepaid advances from joint interest owners | $ | 115,687 | $ | 57,196 | |||||
Accrued compensation | 39,848 | 41,757 | |||||||
Accrued production taxes, ad valorem taxes and other non-income taxes | 36,550 | 35,900 | |||||||
Deferred tax liabilities | 145,349 | — | |||||||
Accrued interest | 60,861 | 61,216 | |||||||
Current portion of asset retirement obligations | 1,246 | 1,434 | |||||||
Other | 4,965 | 610 | |||||||
Accrued liabilities and other | $ | 404,506 | $ | 198,113 | |||||
Derivative_Instruments_Tables
Derivative Instruments (Tables) | 12 Months Ended | |||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||
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 2015 - December 2015 | ||||||||||||||||||||
Swaps - Henry Hub | 24,500,000 | $ | 4.27 | |||||||||||||||||
Collars - Henry Hub | 29,200,000 | $3.50 - $3.75 | $ | 3.69 | $4.89 - $5.48 | $ | 5.04 | |||||||||||||
January 2016 - December 2016 | ||||||||||||||||||||
Swaps - Henry Hub | 63,110,000 | $ | 3.98 | |||||||||||||||||
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 | 2014 | 2013 | 2012 | |||||||||||||||||
Cash received (paid) on derivatives: | ||||||||||||||||||||
Crude oil fixed price swaps (1) | $ | 331,591 | $ | (54,289 | ) | $ | (40,238 | ) | ||||||||||||
Crude oil collars (1) | 65,310 | (16,867 | ) | (15,341 | ) | |||||||||||||||
Natural gas fixed price swaps | (11,551 | ) | 9,601 | 9,858 | ||||||||||||||||
Cash received (paid) on derivatives, net | 385,350 | (61,555 | ) | (45,721 | ) | |||||||||||||||
Non-cash gain (loss) on derivatives: | ||||||||||||||||||||
Crude oil fixed price swaps | 84,792 | (117,580 | ) | 142,567 | ||||||||||||||||
Crude oil collars | 1,121 | (8,587 | ) | 59,911 | ||||||||||||||||
Crude oil written call options | 3,981 | — | — | |||||||||||||||||
Natural gas fixed price swaps | 62,699 | (4,029 | ) | (2,741 | ) | |||||||||||||||
Natural gas collars | 21,816 | — | — | |||||||||||||||||
Non-cash gain (loss) on derivatives, net | 174,409 | (130,196 | ) | 199,737 | ||||||||||||||||
Gain (loss) on derivative instruments, net | $ | 559,759 | $ | (191,751 | ) | $ | 154,016 | |||||||||||||
-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. The proceeds include $85 million for contracts with original maturities in November and December of 2014, $337 million for contracts with original maturities in 2015, and $11 million for contracts with original maturities in 2016. Of the proceeds, $373 million relates to crude oil swap liquidations and $60 million relates to crude oil collar liquidations. | |||||||||||||||||||
Balance sheet offsetting of derivative assets and liabilities | The following tables 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 | 2014 | 2013 | ||||||||||||||||||
Commodity derivative assets: | ||||||||||||||||||||
Gross amounts of recognized assets | $ | 84,415 | $ | 4,213 | ||||||||||||||||
Gross amounts offset on balance sheet | — | (597 | ) | |||||||||||||||||
Net amounts of assets on balance sheet | 84,415 | 3,616 | ||||||||||||||||||
Commodity derivative liabilities: | ||||||||||||||||||||
Gross amounts of recognized liabilities | (4,770 | ) | (125,709 | ) | ||||||||||||||||
Gross amounts offset on balance sheet | 16 | 27,345 | ||||||||||||||||||
Net amounts of liabilities on balance sheet | $ | (4,754 | ) | $ | (98,364 | ) | ||||||||||||||
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 | 2014 | 2013 | ||||||||||||||||||
Derivative assets | $ | 52,423 | $ | 3,616 | ||||||||||||||||
Noncurrent derivative assets | 31,992 | — | ||||||||||||||||||
Net amounts of assets on balance sheet | 84,415 | 3,616 | ||||||||||||||||||
Derivative liabilities | (1,645 | ) | (90,535 | ) | ||||||||||||||||
Noncurrent derivative liabilities | (3,109 | ) | (7,829 | ) | ||||||||||||||||
Net amounts of liabilities on balance sheet | (4,754 | ) | (98,364 | ) | ||||||||||||||||
Total derivative assets (liabilities), net | $ | 79,661 | $ | (94,748 | ) | |||||||||||||||
Nymex West Texas Intermediate [Member] | ||||||||||||||||||||
Derivative [Line Items] | ||||||||||||||||||||
Summary of Outstanding Contracts with Respect to Crude Oil | At December 31, 2014, the Company had outstanding derivative contracts with respect to future production as set forth in the tables below. | |||||||||||||||||||
Crude Oil - NYMEX WTI | Ceilings | |||||||||||||||||||
Weighted Average | ||||||||||||||||||||
Period and Type of Contract | Bbls | Range | Price | |||||||||||||||||
July 2015 - December 2015 | ||||||||||||||||||||
Written call options - WTI (1) | 2,208,000 | $95.85 - $103.75 | $ | 98.36 | ||||||||||||||||
ICE Brent [Member] | ||||||||||||||||||||
Derivative [Line Items] | ||||||||||||||||||||
Summary of Outstanding Contracts with Respect to Crude Oil | ||||||||||||||||||||
Crude Oil - ICE Brent | Ceilings | |||||||||||||||||||
Weighted Average | ||||||||||||||||||||
Period and Type of Contract | Bbls | Range | Price | |||||||||||||||||
July 2015 - December 2015 | ||||||||||||||||||||
Written call options - ICE Brent (1) | 368,000 | $ | 107.4 | $ | 107.4 | |||||||||||||||
January 2016 - December 2016 | ||||||||||||||||||||
Written call options - ICE Brent (1) | 1,464,000 | $ | 107.7 | $ | 107.7 | |||||||||||||||
Fair_Value_Measurements_Tables
Fair Value Measurements (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
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, 2014 and 2013. | ||||||||||||||||
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 | |||||||||
Fair value measurements at December 31, 2013 using: | |||||||||||||||||
In thousands | Level 1 | Level 2 | Level 3 | Total | |||||||||||||
Derivative assets (liabilities): | |||||||||||||||||
Fixed price swaps | $ | — | $ | (84,893 | ) | $ | — | $ | (84,893 | ) | |||||||
Collars | — | (9,855 | ) | — | (9,855 | ) | |||||||||||
Total | $ | — | $ | (94,748 | ) | $ | — | $ | (94,748 | ) | |||||||
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 2019 (adjusted for differentials), escalating 3% per year thereafter | ||||||||||||||||
Operating and development costs | Estimated costs for the current year, escalating 3% per year thereafter | ||||||||||||||||
Productive life of field | Ranging from 0 to 50 years | ||||||||||||||||
Discount rate | 10% | ||||||||||||||||
Unobservable inputs to the fair value assessment are reviewed quarterly and are revised as warranted based on a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Fair value measurements of proved properties are reviewed and approved by certain members of the Company’s management. | |||||||||||||||||
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. | ||||||||||||||||
Year ended December 31, | |||||||||||||||||
In thousands | 2014 | 2013 | 2012 | ||||||||||||||
Proved property impairments | $ | 324,302 | $ | 51,805 | $ | 4,332 | |||||||||||
Unproved property impairments | 292,586 | 168,703 | 117,942 | ||||||||||||||
Total | $ | 616,888 | $ | 220,508 | $ | 122,274 | |||||||||||
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, 2014 | December 31, 2013 | ||||||||||||||||
In thousands | Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||
Debt: | |||||||||||||||||
Credit facility | $ | 165,000 | $ | 165,000 | $ | 275,000 | $ | 275,000 | |||||||||
Note payable | 16,457 | 14,900 | 18,470 | 16,500 | |||||||||||||
8.25% Senior Notes due 2019 (1) | — | — | 298,305 | 327,800 | |||||||||||||
7.375% Senior Notes due 2020 | 198,850 | 213,000 | 198,695 | 223,700 | |||||||||||||
7.125% Senior Notes due 2021 | 400,000 | 421,000 | 400,000 | 450,300 | |||||||||||||
5% Senior Notes due 2022 | 2,022,949 | 1,857,900 | 2,025,362 | 2,063,300 | |||||||||||||
4.5% Senior Notes due 2023 | 1,500,000 | 1,372,800 | 1,500,000 | 1,519,400 | |||||||||||||
3.8% Senior Notes due 2024 | 996,622 | 868,700 | — | — | |||||||||||||
4.9% Senior Notes due 2044 | 698,037 | 572,400 | — | — | |||||||||||||
Total debt | $ | 5,997,915 | $ | 5,485,700 | $ | 4,715,832 | $ | 4,876,000 | |||||||||
(1) These senior notes were redeemed in July 2014. See Note 7. Long-Term Debt for further discussion. |
LongTerm_Debt_Tables
Long-Term Debt (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Debt Disclosure [Abstract] | |||||||||||||
Long-Term Debt | Long-term debt consists of the following at December 31, 2014 and 2013: | ||||||||||||
December 31, | |||||||||||||
In thousands | 2014 | 2013 | |||||||||||
Credit facility | $ | 165,000 | $ | 275,000 | |||||||||
Note payable | 16,457 | 18,470 | |||||||||||
8.25% Senior Notes due 2019 (1) | — | 298,305 | |||||||||||
7.375% Senior Notes due 2020 (2) | 198,850 | 198,695 | |||||||||||
7.125% Senior Notes due 2021 (3) | 400,000 | 400,000 | |||||||||||
5% Senior Notes due 2022 (4) | 2,022,949 | 2,025,362 | |||||||||||
4.5% Senior Notes due 2023 (3) | 1,500,000 | 1,500,000 | |||||||||||
3.8% Senior Notes due 2024 (5) | 996,622 | — | |||||||||||
4.9% Senior Notes due 2044 (6) | 698,037 | — | |||||||||||
Total debt | 5,997,915 | 4,715,832 | |||||||||||
Less: Current portion of long-term debt | 2,078 | 2,011 | |||||||||||
Long-term debt, net of current portion | $ | 5,995,837 | $ | 4,713,821 | |||||||||
-1 | The carrying amount is net of an unamortized discount of $1.7 million at December 31, 2013. The 2019 Notes were redeemed in July 2014 as discussed further below. | ||||||||||||
-2 | The carrying amount is net of unamortized discounts of $1.2 million and $1.3 million at December 31, 2014 and 2013, respectively. | ||||||||||||
-3 | These notes were sold at par and are recorded at 100% of face value. | ||||||||||||
-4 | The carrying amount includes an unamortized premium of $22.9 million and $25.4 million at December 31, 2014 and 2013, respectively. | ||||||||||||
-5 | The carrying amount is net of an unamortized discount of $3.4 million at December 31, 2014. | ||||||||||||
-6 | The carrying amount is net of an unamortized discount of $2.0 million at December 31, 2014. | ||||||||||||
Summary of Maturity Dates, Semi-Annual Interest Payment Dates, and Optional Redemption Periods of Outstanding Senior Note Obligations | The following table summarizes the maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding senior note obligations. | ||||||||||||
2020 Notes | 2021 Notes | 2022 Notes | 2023 Notes | 2024 Notes | 2044 Notes | ||||||||
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, Sept. 15 | April 15, Oct. 15 | June 1, Dec. 1 | June 1, Dec. 1 | |||||||
Call premium redemption period (1) | 1-Oct-15 | April 1, 2016 | 15-Mar-17 | — | — | — | |||||||
Make-whole redemption period (2) | 1-Oct-15 | April 1, 2016 | 15-Mar-17 | Jan 15, 2023 | Mar 1, 2024 | Dec 1, 2043 | |||||||
Equity offering redemption period (3) | — | — | 15-Mar-15 | — | — | — | |||||||
-1 | On or after these dates, the Company has the option to redeem all or a portion of its senior notes 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 at the “make-whole” redemption prices or amounts specified in the Indentures plus any accrued and unpaid interest to the date of redemption. | ||||||||||||
-3 | At any time prior to this date, the Company may redeem up to 35% of the principal amount of its 2022 Notes under certain circumstances with the net cash proceeds from one or more equity offerings at the redemption prices specified in the indenture for the 2022 Notes plus any accrued and unpaid interest to the date of redemption. |
Income_Taxes_Tables
Income Taxes (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Income Tax Disclosure [Abstract] | |||||||||||||
Provision for Income Taxes | The items comprising the provision for income taxes are as follows for the periods presented: | ||||||||||||
Year ended December 31, | |||||||||||||
In thousands | 2014 | 2013 | 2012 | ||||||||||
Current income tax provision: | |||||||||||||
United States federal | $ | — | $ | 6,193 | $ | 9,191 | |||||||
Various states | 20 | 16 | 1,326 | ||||||||||
Total current income tax provision | 20 | 6,209 | 10,517 | ||||||||||
Deferred income tax provision: | |||||||||||||
United States federal | 527,315 | 403,002 | 383,157 | ||||||||||
Various states | 57,362 | 39,619 | 22,137 | ||||||||||
Total deferred income tax provision | 584,677 | 442,621 | 405,294 | ||||||||||
Total provision for income taxes | $ | 584,697 | $ | 448,830 | $ | 415,811 | |||||||
Schedule of Provision for Income Taxes with Income Tax at Federal Statutory Rate | |||||||||||||
Year ended December 31, | |||||||||||||
In thousands | 2014 | 2013 | 2012 | ||||||||||
Expected income tax expense based on US statutory tax rate of 35% | $ | 546,713 | $ | 424,567 | $ | 404,319 | |||||||
State income taxes, net of federal benefit | 42,169 | 25,838 | 15,213 | ||||||||||
Canadian valuation allowance | 4,389 | — | — | ||||||||||
Effect of differing statutory tax rate in Canada | (1,900 | ) | — | — | |||||||||
Other, net | (6,674 | ) | (1,575 | ) | (3,721 | ) | |||||||
Provision for income taxes | $ | 584,697 | $ | 448,830 | $ | 415,811 | |||||||
Components of Deferred Tax Assets and Liabilities | The components of the Company’s deferred tax assets and liabilities as of December 31, 2014 and 2013 are as follows: | ||||||||||||
December 31, | |||||||||||||
In thousands | 2014 | 2013 | |||||||||||
Current: | |||||||||||||
Deferred tax assets (1) | |||||||||||||
Non-cash losses on derivatives | $ | — | $ | 33,029 | |||||||||
Other | 3,274 | 2,288 | |||||||||||
Total current deferred tax assets | 3,274 | 35,317 | |||||||||||
Deferred tax liabilities | |||||||||||||
Non-cash gains on derivatives | (19,293 | ) | — | ||||||||||
Gain on derivative liquidations | (128,198 | ) | — | ||||||||||
Other | (1,132 | ) | (645 | ) | |||||||||
Total current deferred tax liabilities | (148,623 | ) | (645 | ) | |||||||||
Net current deferred tax assets (liabilities) (2) | (145,349 | ) | 34,672 | ||||||||||
Noncurrent: | |||||||||||||
Deferred tax assets | |||||||||||||
Net operating loss carryforwards | 60,904 | 41,791 | |||||||||||
Non-cash losses on derivatives | — | 2,975 | |||||||||||
Alternative minimum tax carryforwards | 38,715 | 38,689 | |||||||||||
Equity compensation | 22,255 | 16,961 | |||||||||||
Other | 10,545 | 3,259 | |||||||||||
Total noncurrent deferred tax assets | 132,419 | 103,675 | |||||||||||
Canadian valuation allowance | (4,389 | ) | — | ||||||||||
Total noncurrent deferred tax assets, net of valuation allowance | 128,030 | 103,675 | |||||||||||
Deferred tax liabilities | |||||||||||||
Property and equipment | (2,254,343 | ) | (1,840,331 | ) | |||||||||
Non-cash gains on derivatives | (10,976 | ) | — | ||||||||||
Other | (4,158 | ) | (156 | ) | |||||||||
Total noncurrent deferred tax liabilities | (2,269,477 | ) | (1,840,487 | ) | |||||||||
Net noncurrent deferred tax liabilities | (2,141,447 | ) | (1,736,812 | ) | |||||||||
Net deferred tax liabilities | $ | (2,286,796 | ) | $ | (1,702,140 | ) | |||||||
-1 | Deferred and prepaid taxes on the consolidated balance sheets contain receivables of $63.3 million and $9.7 million for prepaid income taxes at December 31, 2014 and 2013, respectively. | ||||||||||||
-2 | The net liability balance at December 31, 2014 is included in the caption "Accrued liabilities and other" in the consolidated balance sheets. The net asset balance at December 31, 2013 is included in the caption "Deferred and prepaid taxes" in the consolidated balance sheets. |
Lease_Commitments_Tables
Lease Commitments (Tables) | 12 Months Ended | ||||
Dec. 31, 2014 | |||||
Leases [Abstract] | |||||
Schedule of Minimum Future Rental Commitments Under Operating Leases | At December 31, 2014, the minimum future rental commitments under operating leases having lease terms in excess of one year are as follows: | ||||
In thousands | Total amount | ||||
2015 | $ | 4,953 | |||
2016 | 3,256 | ||||
2017 | 1,234 | ||||
2018 | 856 | ||||
2019 | 300 | ||||
Thereafter | 3,468 | ||||
Total obligations | $ | 14,067 | |||
StockBased_Compensation_Tables
Stock-Based Compensation (Tables) | 12 Months Ended | ||||||||||||||
Dec. 31, 2014 | |||||||||||||||
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, is reflected in the table below for the periods presented. | ||||||||||||||
Year ended December 31, | |||||||||||||||
In thousands | 2014 | 2013 | 2012 | ||||||||||||
Non-cash equity compensation | $ | 54,353 | $ | 39,890 | $ | 29,057 | |||||||||
Schedule of Stock Option Activity | The following table summarizes stock option activity under the 2000 Plan for the periods presented: | ||||||||||||||
Outstanding | Exercisable | ||||||||||||||
Number of | Weighted | Number of | Weighted | ||||||||||||
options | average | options | average | ||||||||||||
exercise | exercise | ||||||||||||||
price | price | ||||||||||||||
Outstanding at December 31, 2011 | 173,000 | $ | 0.36 | 173,000 | $ | 0.36 | |||||||||
Exercised | (173,000 | ) | $ | 0.36 | |||||||||||
Outstanding at December 31, 2012 | — | — | — | — | |||||||||||
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, 2011 to December 31, 2014 is presented below. | ||||||||||||||
Number of | Weighted | ||||||||||||||
non-vested | average | ||||||||||||||
shares | grant-date | ||||||||||||||
fair value | |||||||||||||||
Non-vested restricted shares at December 31, 2011 | 2,396,688 | $ | 24.33 | ||||||||||||
Granted | 1,832,056 | 36.73 | |||||||||||||
Vested | (889,446 | ) | 22.63 | ||||||||||||
Forfeited | (80,374 | ) | 29.53 | ||||||||||||
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 | $ | 37.5 | ||||||||||||
Granted | 1,424,764 | 61.11 | |||||||||||||
Vested | (1,007,166 | ) | 35.91 | ||||||||||||
Forfeited | (453,146 | ) | 44.9 | ||||||||||||
Non-vested restricted shares at December 31, 2014 | 2,678,764 | $ | 49.4 | ||||||||||||
Crude_Oil_and_Natural_Gas_Prop1
Crude Oil and Natural Gas Property Information (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
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, 2014, 2013 and 2012. | ||||||||||||
Year ended December 31, | |||||||||||||
In thousands | 2014 | 2013 | 2012 | ||||||||||
Crude oil and natural gas sales (1) | $ | 4,203,022 | $ | 3,573,431 | $ | 2,349,500 | |||||||
Production expenses | (352,472 | ) | (282,197 | ) | (195,440 | ) | |||||||
Production taxes and other expenses (1) | (349,760 | ) | (298,787 | ) | (198,505 | ) | |||||||
Exploration expenses | (50,067 | ) | (34,947 | ) | (23,507 | ) | |||||||
Depreciation, depletion, amortization and accretion | (1,338,351 | ) | (953,796 | ) | (683,207 | ) | |||||||
Property impairments | (616,888 | ) | (220,508 | ) | (122,274 | ) | |||||||
Income taxes | (559,311 | ) | (659,783 | ) | (428,095 | ) | |||||||
Results from crude oil and natural gas producing activities | $ | 936,173 | $ | 1,123,413 | $ | 698,472 | |||||||
-1 | Natural gas transportation and processing charges totaling $33.3 million and $29.9 million for the years ended December 31, 2013 and 2012, respectively, have been reclassified from "Production taxes and other expenses" to "Crude oil and natural gas sales" to conform to the current year presentation as discussed in Note 1. Organization and Summary of Significant Accounting Policies. | ||||||||||||
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, 2014, 2013 and 2012 are presented below: | ||||||||||||
Year ended December 31, | |||||||||||||
In thousands | 2014 | 2013 | 2012 | ||||||||||
Property Acquisition Costs: | |||||||||||||
Proved | $ | 48,917 | $ | 16,604 | $ | 738,415 | |||||||
Unproved | 409,529 | 546,881 | 745,601 | ||||||||||
Total property acquisition costs | 458,446 | 563,485 | 1,484,016 | ||||||||||
Exploration Costs | 863,606 | 687,767 | 857,681 | ||||||||||
Development Costs | 3,670,448 | 2,549,203 | 1,975,660 | ||||||||||
Total | $ | 4,992,500 | $ | 3,800,455 | $ | 4,317,357 | |||||||
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, 2014 and 2013 are as follows: | ||||||||||||
December 31, | |||||||||||||
In thousands | 2014 | 2013 | |||||||||||
Proved crude oil and natural gas properties | $ | 17,045,967 | $ | 12,423,878 | |||||||||
Unproved crude oil and natural gas properties | 966,080 | 1,181,268 | |||||||||||
Total | 18,012,047 | 13,605,146 | |||||||||||
Less accumulated depreciation, depletion and amortization | (4,601,864 | ) | (3,083,180 | ) | |||||||||
Net capitalized costs | $ | 13,410,183 | $ | 10,521,966 | |||||||||
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 | 2014 | 2013 | 2012 | ||||||||||
Balance at January 1 | $ | 152,775 | $ | 92,699 | $ | 128,123 | |||||||
Additions to capitalized exploratory well costs pending determination of proved reserves | 627,853 | 548,933 | 485,530 | ||||||||||
Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves | (671,618 | ) | (479,507 | ) | (520,187 | ) | |||||||
Capitalized exploratory well costs charged to expense | (15,589 | ) | (9,350 | ) | (767 | ) | |||||||
Balance at December 31 | $ | 93,421 | $ | 152,775 | $ | 92,699 | |||||||
Number of gross wells | 119 | 67 | 46 | ||||||||||
Supplemental_Crude_Oil_and_Nat1
Supplemental Crude Oil and Natural Gas Information (Unaudited) (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
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 | |||||||||||
(MBbls) | (MMcf) | (MBoe) | |||||||||||
Proved reserves as of December 31, 2011 | 326,133 | 1,093,832 | 508,438 | ||||||||||
Revisions of previous estimates | 33,272 | (174,736 | ) | 4,149 | |||||||||
Extensions, discoveries and other additions | 166,844 | 400,848 | 233,652 | ||||||||||
Production | (25,070 | ) | (63,875 | ) | (35,716 | ) | |||||||
Sales of minerals in place | (7,165 | ) | (4,046 | ) | (7,838 | ) | |||||||
Purchases of minerals in place | 67,149 | 89,061 | 81,992 | ||||||||||
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 | ||||||||||
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, 2014, 2013 and 2012: | ||||||||||||
December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Proved Developed Reserves | |||||||||||||
Crude oil (MBbl) | 342,137 | 278,630 | 226,870 | ||||||||||
Natural Gas (MMcf) | 962,051 | 768,969 | 545,499 | ||||||||||
Total (MBoe) | 502,479 | 406,792 | 317,786 | ||||||||||
Proved Undeveloped Reserves | |||||||||||||
Crude oil (MBbl) | 524,223 | 459,158 | 334,293 | ||||||||||
Natural Gas (MMcf) | 1,946,335 | 1,309,051 | 795,585 | ||||||||||
Total (MBoe) | 848,612 | 677,333 | 466,891 | ||||||||||
Total Proved Reserves | |||||||||||||
Crude oil (MBbl) | 866,360 | 737,788 | 561,163 | ||||||||||
Natural Gas (MMcf) | 2,908,386 | 2,078,020 | 1,341,084 | ||||||||||
Total (MBoe) | 1,351,091 | 1,084,125 | 784,677 | ||||||||||
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, 2014, 2013 and 2012. | ||||||||||||
December 31, | |||||||||||||
In thousands | 2014 | 2013 | 2012 | ||||||||||
Future cash inflows | $ | 90,867,459 | $ | 78,646,274 | $ | 54,362,574 | |||||||
Future production costs | (25,799,221 | ) | (21,333,460 | ) | (13,103,469 | ) | |||||||
Future development and abandonment costs | (12,842,174 | ) | (10,250,789 | ) | (8,295,130 | ) | |||||||
Future income taxes | (13,800,737 | ) | (12,447,127 | ) | (8,500,766 | ) | |||||||
Future net cash flows | 38,425,327 | 34,614,898 | 24,463,209 | ||||||||||
10% annual discount for estimated timing of cash flows | (19,992,293 | ) | (18,319,131 | ) | (13,282,852 | ) | |||||||
Standardized measure of discounted future net cash flows | $ | 18,433,034 | $ | 16,295,767 | $ | 11,180,357 | |||||||
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 | 2014 | 2013 | 2012 | ||||||||||
Standardized measure of discounted future net cash flows at January 1 | $ | 16,295,767 | $ | 11,180,357 | $ | 7,505,356 | |||||||
Extensions, discoveries and improved recoveries, less related costs | 5,516,528 | 6,613,665 | 3,724,136 | ||||||||||
Revisions of previous quantity estimates | (1,755,366 | ) | (1,765,300 | ) | 254,493 | ||||||||
Changes in estimated future development and abandonment costs | 476,665 | 1,942,585 | (298,148 | ) | |||||||||
Purchases (sales) of minerals in place, net | (3,196 | ) | 12,012 | 1,171,047 | |||||||||
Net change in prices and production costs | (1,925,349 | ) | 263,541 | (530,515 | ) | ||||||||
Accretion of discount | 1,629,576 | 1,118,036 | 750,536 | ||||||||||
Sales of crude oil and natural gas produced, net of production costs | (3,500,790 | ) | (2,992,447 | ) | (1,955,555 | ) | |||||||
Development costs incurred during the period | 2,466,748 | 1,210,223 | 1,095,156 | ||||||||||
Change in timing of estimated future production and other | (309,902 | ) | 464,111 | (102,519 | ) | ||||||||
Change in income taxes | (457,647 | ) | (1,751,016 | ) | (433,630 | ) | |||||||
Net change | 2,137,267 | 5,115,410 | 3,675,001 | ||||||||||
Standardized measure of discounted future net cash flows at December 31 | $ | 18,433,034 | $ | 16,295,767 | $ | 11,180,357 | |||||||
Quarterly_Financial_Data_Unaud1
Quarterly Financial Data (Unaudited) (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Quarterly Financial Information Disclosure [Abstract] | |||||||||||||||||
Schedule Of Quarterly Financial Data | The Company’s unaudited quarterly financial data for 2014 and 2013 is summarized below. | ||||||||||||||||
Quarter ended | |||||||||||||||||
In thousands, except per share data | March 31 | June 30 | September 30 | December 31 | |||||||||||||
2014 | -2 | ||||||||||||||||
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 | |||||||
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 | |||||||||
2013 | |||||||||||||||||
Total revenues (1)(3) | $ | 702,643 | $ | 1,093,057 | $ | 814,887 | $ | 811,220 | |||||||||
Gain (loss) on derivative instruments, net (1) | $ | (84,831 | ) | $ | 199,056 | $ | (203,774 | ) | $ | (102,202 | ) | ||||||
Income from operations | $ | 270,146 | $ | 573,872 | $ | 328,043 | $ | 273,706 | |||||||||
Net income | $ | 140,627 | $ | 323,270 | $ | 167,498 | $ | 132,824 | |||||||||
Net income per share: | |||||||||||||||||
Basic | $ | 0.38 | $ | 0.88 | $ | 0.45 | $ | 0.36 | |||||||||
Diluted | $ | 0.38 | $ | 0.87 | $ | 0.45 | $ | 0.36 | |||||||||
-1 | Gains and losses on mark-to-market derivative instruments are reflected in “Total revenues” on both the consolidated statements of comprehensive income 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 as discussed in Note 5. Derivative Instruments. The 2014 fourth quarter also includes $340 million of pre-tax non-cash impairment charges ($214 million after tax, or $0.58 per basic and diluted share) as discussed in Note 6. Fair Value Measurements. | ||||||||||||||||
-3 | Total revenues for the quarterly periods of 2013 have been adjusted to conform to the current year presentation of natural gas transportation and processing charges as discussed in Note 1. Organization and Summary of Significant Accounting Policies. Reclassified amounts total $7.6 million, $7.7 million, $8.9 million and $9.1 million for the first, second, third and fourth quarters of 2013, respectively. |
Organization_and_Summary_of_Si3
Organization and Summary of Significant Accounting Policies - Additional Information (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |||||
In Millions, unless otherwise specified | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Organization And Summary Of Significant Accounting Policies [Line Items] | |||||||
Reclassified Gas Transportation Charges | $9.10 | $8.90 | $7.70 | $7.60 | $33.30 | $29.90 | |
Percentage of operations concentrated in geographically areas | 74.00% | ||||||
Percentage Of Revenues Concentrated In Geographically Areas | 83.00% | ||||||
Percentage of estimated proved reserves in north region | 69.00% | ||||||
Percentage of crude oil and natural gas production concentrated in south region | 26.00% | ||||||
Percentage of estimated proved reserves in south region | 31.00% | ||||||
Percentage Of Crude Oil And Natural Gas Production Concentrated In Crude Oil | 70.00% | ||||||
Percentage Of Crude Oil and Natural Gas Revenue Concentrated in Crude Oil | 85.00% | ||||||
Cash deposits in excess of federally insured amounts | 22.6 | ||||||
Net asset retirement costs | 44.4 | 64.7 | 44.4 | ||||
Capitalized debt issue costs, relating to long-term debt | 69.5 | 76.1 | 69.5 | ||||
Accumulated amortization, relating to capitalized debt issue costs | 28.8 | 38.1 | 28.8 | ||||
Amortization expense related to capitalized debt issuance costs | 9.3 | 8.6 | 5.6 | ||||
Percentage Of Estimated Proved Reserves Concentrated In Crude Oil | 64.00% | ||||||
8 1/4% Senior Notes due 2019 [Member] | |||||||
Organization And Summary Of Significant Accounting Policies [Line Items] | |||||||
Debt instrument interest percentage | 8.25% | ||||||
7 3/8% Senior Notes due 2020 [Member] | |||||||
Organization And Summary Of Significant Accounting Policies [Line Items] | |||||||
Debt instrument interest percentage | 7.38% | ||||||
7 1/8% Senior Notes due 2021 [Member] | |||||||
Organization And Summary Of Significant Accounting Policies [Line Items] | |||||||
Debt instrument interest percentage | 7.13% | ||||||
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 | 14.00% | ||||||
Second 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% | ||||||
Affiliated Entity [Member] | |||||||
Organization And Summary Of Significant Accounting Policies [Line Items] | |||||||
Reclassified Gas Transportation Charges | $4.70 | $4.70 |
Organization_and_Summary_of_Si4
Organization and Summary of Significant Accounting Policies - Components of Inventories (Detail) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Tubular goods and equipment | $15,659 | $11,139 |
Crude oil | 86,520 | 43,301 |
Total | $102,179 | $54,440 |
Organization_and_Summary_of_Si5
Organization and Summary of Significant Accounting Policies - Components of Crude Oil Inventories Volumes (Detail) | Dec. 31, 2014 | Dec. 31, 2013 |
MBbls | MBbls | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Crude oil line fill requirements, in thousands of barrels | 1,323 | 370 |
Temporarily stored crude oil, in thousands of barrels | 596 | 344 |
Total, in thousands of barrels | 1,919 | 714 |
Organization_and_Summary_of_Si6
Organization and Summary of Significant Accounting Policies - Schedule of Estimated Useful Lives of Service Property and Equipment (Detail) | 12 Months Ended |
Dec. 31, 2014 | |
Furniture and Fixtures [Member] | |
Property, Plant and Equipment [Line Items] | |
Estimated useful lives (in years) | 10 years |
Enterprise Resource Planning Software [Member] | |
Property, Plant and Equipment [Line Items] | |
Estimated useful lives (in years) | 25 years |
Minimum [Member] | Automobiles [Member] | |
Property, Plant and Equipment [Line Items] | |
Estimated useful lives (in years) | 5 years |
Minimum [Member] | Machinery and Equipment [Member] | |
Property, Plant and Equipment [Line Items] | |
Estimated useful lives (in years) | 10 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 [Member] | |
Property, Plant and Equipment [Line Items] | |
Estimated useful lives (in years) | 6 years |
Maximum [Member] | Machinery and Equipment [Member] | |
Property, Plant and Equipment [Line Items] | |
Estimated useful lives (in years) | 20 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_Si7
Organization and Summary of Significant Accounting Policies - Summary Of Changes In Future Abandonment Liabilities (Detail) (USD $) | 12 Months Ended | |||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||||
Asset retirement obligations at January 1 | $55,787,000 | $47,171,000 | $62,625,000 | |||
Accretion expense | 3,366,000 | 2,767,000 | 3,105,000 | |||
Revisions | 9,916,000 | 2,826,000 | -2,871,000 | |||
Plus: Additions for new assets | 9,022,000 | 6,009,000 | 6,679,000 | |||
Less: Plugging costs and sold assets | -1,383,000 | [1] | -2,986,000 | [1] | -22,367,000 | [1] |
Total asset retirement obligations at December 31 | 76,708,000 | 55,787,000 | 47,171,000 | |||
Less: Current portion of asset retirement obligations at December 31 | 1,246,000 | 1,434,000 | 2,227,000 | |||
Non-current portion of asset retirement obligations at December 31 | 75,462,000 | 54,353,000 | 44,944,000 | |||
Asset retirement obligation disposed of | $20,000,000 | |||||
[1] | As a result of asset dispositions during the year ended December 31, 2012, the Company removed $20.0 million of its previously recognized asset retirement obligations that were assumed by the buyers. See Note 13. Property Acquisitions and Dispositions for further discussion. |
Organization_and_Summary_of_Si8
Organization and Summary of Significant Accounting Policies - Earnings Per Share (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Income (numerator): | |||||||||||
Net income - basic and diluted | $114,048 | $533,521 | $103,538 | $226,234 | $132,824 | $167,498 | $323,270 | $140,627 | $977,341 | $764,219 | $739,385 |
Weighted average shares - basic | 368,829 | 368,150 | 362,680 | ||||||||
Non-vested restricted stock | 1,929 | 1,548 | 980 | ||||||||
Stock options | 0 | 0 | 32 | ||||||||
Weighted average shares - diluted | 370,758 | 369,698 | 363,692 | ||||||||
Net income per share: | |||||||||||
Basic (in dollars per share) | $0.31 | $1.45 | $0.28 | $0.61 | $0.36 | $0.45 | $0.88 | $0.38 | $2.65 | $2.08 | $2.04 |
Diluted (in dollars per share) | $0.31 | $1.44 | $0.28 | $0.61 | $0.36 | $0.45 | $0.87 | $0.38 | $2.64 | $2.07 | $2.03 |
Supplemental_Cash_Flow_Informa2
Supplemental Cash Flow Information - Summary of Supplemental Cash Flow Information (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Supplemental cash flow information: | |||
Cash paid for interest | $267,384 | $209,815 | $102,043 |
Cash paid for income taxes | 53,457 | 29,017 | 829 |
Cash received for income tax refunds | 7 | 174 | 13,866 |
Non-cash investing activities: | |||
Increase in accrued capital expenditures | 290,782 | 89,482 | 49,039 |
Acquisition of assets through issuance of common stock (Note 11) | 0 | 0 | 176,563 |
Asset retirement obligation additions and revisions, net | $18,938 | $8,835 | $3,808 |
Net_Property_and_Equipment_Sch
Net Property and Equipment - Schedule of Net Property and Equipment (Detail) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Property, Plant and Equipment, Net [Abstract] | ||
Proved crude oil and natural gas properties | $17,045,967 | $12,423,878 |
Unproved crude oil and natural gas properties | 966,080 | 1,181,268 |
Service properties, equipment and other | 274,584 | 236,233 |
Total property and equipment | 18,286,631 | 13,841,379 |
Accumulated depreciation, depletion and amortization | -4,650,779 | -3,120,107 |
Net property and equipment | $13,635,852 | $10,721,272 |
Accrued_Liabilities_and_Other_1
Accrued Liabilities and Other - Schedule of Accrued Liabilities and Other (Detail) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | |||
Accrued Liabilities and Other Liabilities [Abstract] | |||
Prepaid advances from joint interest owners | $115,687 | $57,196 | |
Accrued compensation | 39,848 | 41,757 | |
Accrued production taxes, ad valorem taxes and other non-income taxes | 36,550 | 35,900 | |
Deferred tax liabilities | 145,349 | 0 | |
Accrued interest | 60,861 | 61,216 | |
Current portion of asset retirement obligations | 1,246 | 1,434 | 2,227 |
Other | 4,965 | 610 | |
Accrued liabilities and other | $404,506 | $198,113 |
Derivative_Instruments_Summary
Derivative Instruments - Summary of Outstanding Contracts with Respect to Crude Oil (Detail) | 12 Months Ended |
Dec. 31, 2014 | |
bbl | |
ICE Brent [Member] | Call Option July 2015 to December 2015 [Member] | |
Derivative [Line Items] | |
Volume (Bbls) | 368,000 |
Derivative, Average Price Risk Option Strike Price | 107.4 |
ICE Brent [Member] | Call Option January 2016 to December 2016 [Member] | |
Derivative [Line Items] | |
Volume (Bbls) | 1,464,000 |
Derivative, Average Price Risk Option Strike Price | 107.7 |
Nymex West Texas Intermediate [Member] | Call Option July 2015 to December 2015 [Member] | |
Derivative [Line Items] | |
Volume (Bbls) | 2,208,000 |
Derivative, Average Price Risk Option Strike Price | 98.36 |
Nymex West Texas Intermediate [Member] | Minimum [Member] | Call Option July 2015 to December 2015 [Member] | |
Derivative [Line Items] | |
Derivative, Price Risk Option Strike Price | 95.85 |
Nymex West Texas Intermediate [Member] | Maximum [Member] | Call Option July 2015 to December 2015 [Member] | |
Derivative [Line Items] | |
Derivative, Price Risk Option Strike Price | 103.75 |
Derivative_Instruments_Summary1
Derivative Instruments - Summary of Outstanding Contracts with Respect to Natural Gas (Detail) (Natural Gas [Member]) | 12 Months Ended |
Dec. 31, 2014 | |
MMBTU | |
January 2015 to December 2015 Swaps [Member] | |
Derivative [Line Items] | |
Natural Gas Production Derivative Volume, MMBtus | 24,500,000 |
Swaps Weighted Average Price | 4.27 |
January 2015 to December 2015 Collars [Member] | |
Derivative [Line Items] | |
Derivative, Average Cap Price | 5.04 |
Natural Gas Production Derivative Volume, MMBtus | 29,200,000 |
Derivative, Average Floor Price | 3.69 |
January 2016 to December 2016 Swaps [Member] | |
Derivative [Line Items] | |
Natural Gas Production Derivative Volume, MMBtus | 63,110,000 |
Swaps Weighted Average Price | 3.98 |
Maximum [Member] | January 2015 to December 2015 Collars [Member] | |
Derivative [Line Items] | |
Derivative, Floor Price | 3.75 |
Derivative, Cap Price | 5.48 |
Minimum [Member] | January 2015 to December 2015 Collars [Member] | |
Derivative [Line Items] | |
Derivative, Floor Price | 3.5 |
Derivative, Cap Price | 4.89 |
Derivative_Instruments_Realize
Derivative Instruments - Realized and Unrealized Gains and Losses on Derivative Instruments (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||||||||||
Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||||||||
Derivatives, Fair Value [Line Items] | |||||||||||||||||||
Cash Proceeds from Liquidated Derivatives | $433,000,000 | ||||||||||||||||||
Cash received (paid) on derivatives: | |||||||||||||||||||
Cash received (paid) on derivatives, net | 385,350,000 | -61,555,000 | -45,721,000 | ||||||||||||||||
Non-cash gain (loss) on derivatives: | |||||||||||||||||||
Non-cash gain (loss) on derivatives, net | 174,409,000 | -130,196,000 | 199,737,000 | ||||||||||||||||
Gain (loss) on derivative instruments, net | 387,958,000 | [1] | 473,999,000 | [1] | -262,524,000 | [1] | -39,674,000 | [1] | -102,202,000 | [1] | -203,774,000 | [1] | 199,056,000 | [1] | -84,831,000 | [1] | 559,759,000 | -191,751,000 | 154,016,000 |
November 2014 to December 2014 Swaps [Member] | |||||||||||||||||||
Derivatives, Fair Value [Line Items] | |||||||||||||||||||
Cash Proceeds from Liquidated Derivatives | 85,000,000 | ||||||||||||||||||
January 2015 to December 2015 Swaps [Member] | |||||||||||||||||||
Derivatives, Fair Value [Line Items] | |||||||||||||||||||
Cash Proceeds from Liquidated Derivatives | 337,000,000 | ||||||||||||||||||
January 2016 to December 2016 Collars [Member] | |||||||||||||||||||
Derivatives, Fair Value [Line Items] | |||||||||||||||||||
Cash Proceeds from Liquidated Derivatives | 11,000,000 | ||||||||||||||||||
Fixed Price Swaps [Member] | Crude Oil [Member] | |||||||||||||||||||
Derivatives, Fair Value [Line Items] | |||||||||||||||||||
Cash Proceeds from Liquidated Derivatives | 373,000,000 | ||||||||||||||||||
Cash received (paid) on derivatives: | |||||||||||||||||||
Cash received (paid) on derivatives, net | 331,591,000 | -54,289,000 | -40,238,000 | ||||||||||||||||
Non-cash gain (loss) on derivatives: | |||||||||||||||||||
Non-cash gain (loss) on derivatives, net | 84,792,000 | -117,580,000 | 142,567,000 | ||||||||||||||||
Fixed Price Swaps [Member] | Natural Gas [Member] | |||||||||||||||||||
Cash received (paid) on derivatives: | |||||||||||||||||||
Cash received (paid) on derivatives, net | -11,551,000 | 9,601,000 | 9,858,000 | ||||||||||||||||
Non-cash gain (loss) on derivatives: | |||||||||||||||||||
Non-cash gain (loss) on derivatives, net | 62,699,000 | -4,029,000 | -2,741,000 | ||||||||||||||||
Collars [Member] | Crude Oil [Member] | |||||||||||||||||||
Derivatives, Fair Value [Line Items] | |||||||||||||||||||
Cash Proceeds from Liquidated Derivatives | 60,000,000 | ||||||||||||||||||
Cash received (paid) on derivatives: | |||||||||||||||||||
Cash received (paid) on derivatives, net | 65,310,000 | -16,867,000 | -15,341,000 | ||||||||||||||||
Non-cash gain (loss) on derivatives: | |||||||||||||||||||
Non-cash gain (loss) on derivatives, net | 1,121,000 | -8,587,000 | 59,911,000 | ||||||||||||||||
Collars [Member] | Natural Gas [Member] | |||||||||||||||||||
Non-cash gain (loss) on derivatives: | |||||||||||||||||||
Non-cash gain (loss) on derivatives, net | 21,816,000 | ||||||||||||||||||
Call Option [Member] | Crude Oil [Member] | |||||||||||||||||||
Non-cash gain (loss) on derivatives: | |||||||||||||||||||
Non-cash gain (loss) on derivatives, net | $3,981,000 | ||||||||||||||||||
[1] | Gains and losses on mark-to-market derivative instruments are reflected in “Total revenues†on both the consolidated statements of comprehensive income 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 as discussed in Note 5. Derivative Instruments. The 2014 fourth quarter also includes $340 million of pre-tax non-cash impairment charges ($214 million after tax, or $0.58 per basic and diluted share) as discussed in Note 6. Fair Value Measurements.(3)Total revenues for the quarterly periods of 2013 have been adjusted to conform to the current year presentation of natural gas transportation and processing charges as discussed in Note 1. Organization and Summary of Significant Accounting Policies. Reclassified amounts total $7.6 million, $7.7 million, $8.9 million and $9.1 million for the first, second, third and fourth quarters of 2013, respectively. |
Derivative_Instruments_Derivat
Derivative Instruments Derivative Instruments - Gross Amounts of Recognized Derivative Assets and Liabilities (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Derivative [Line Items] | ||
Commodity derivative assets, Gross amounts of recognized assets | $84,415 | $4,213 |
Commodity derivative assets, Gross amounts offset on balance sheet | 0 | -597 |
Derivative assets, Net amounts of assets on balance sheet | 84,415 | 3,616 |
Commodity derivative liability, Gross amounts of recognized liabilities | -4,770 | -125,709 |
Commodity derivative liability, Gross amounts offset on balance sheet | 16 | 27,345 |
Derivative liability, Net amounts of liabilities on balance sheet | ($4,754) | ($98,364) |
Derivative_Instruments_Derivat1
Derivative Instruments Derivative Instruments - Reconciles Net Amounts Derivative Assets and Liabilities (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Derivative assets | $52,423 | $3,616 |
Noncurrent derivative assets | 31,992 | 0 |
Derivative assets, Net amounts of assets on balance sheet | 84,415 | 3,616 |
Derivative liabilities | -1,645 | -90,535 |
Noncurrent derivative liabilities | -3,109 | -7,829 |
Derivative liability, Net amounts of liabilities on balance sheet | -4,754 | -98,364 |
Total derivative assets (liabilities), net | $79,661 | ($94,748) |
Fair_Value_Measurements_Valuat
Fair Value Measurements - Valuation of Financial Instruments by Pricing Levels (Detail) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | $79,661 | ($94,748) |
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 2 [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | 79,661 | -94,748 |
Fair Value, Inputs, Level 2 [Member] | Fixed Price Swaps [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | 62,599 | -84,893 |
Fair Value, Inputs, Level 2 [Member] | Collars [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | 21,816 | -9,855 |
Fair Value, Inputs, Level 2 [Member] | Call Option [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | -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 [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | 79,661 | -94,748 |
Fair Value [Member] | Fixed Price Swaps [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | 62,599 | -84,893 |
Fair Value [Member] | Collars [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | 21,816 | -9,855 |
Fair Value [Member] | Call Option [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | ($4,754) |
Fair_Value_Measurements_Additi
Fair Value Measurements - Additional Information (Detail) (USD $) | 3 Months Ended | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
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 | $255,000,000 | $324,302,000 | $51,805,000 | $4,332,000 |
Estimated fair value of proved properties | 101,000,000 | 101,000,000 | ||
Unproved Oil And Gas Property Fair Value After Impairment | 14,200,000 | 14,200,000 | ||
Impairment of significant unproved property | $84,600,000 | $92,400,000 | ||
Minimum [Member] | ||||
Fair Value Measurements [Line Items] | ||||
Productive life of field (in years) | 0 years | |||
Maximum [Member] | ||||
Fair Value Measurements [Line Items] | ||||
Productive life of field (in years) | 50 years | |||
Forward Commodity Prices [Member] | ||||
Fair Value Measurements [Line Items] | ||||
Forward commodity price escalation assumption used in impairment assessment | 3.00% | 3.00% |
Fair_Value_Measurements_Proper
Fair Value Measurements - Property Impairments (Detail) (USD $) | 3 Months Ended | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Inventory Adjustments | $18,200,000 | $18,200,000 | ||
Proved property impairments | 255,000,000 | 324,302,000 | 51,805,000 | 4,332,000 |
Unproved property impairments | 292,586,000 | 168,703,000 | 117,942,000 | |
Total | 616,888,000 | 220,508,000 | 122,274,000 | |
Buffalo Red River Units [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Proved property impairments | 96,900,000 | |||
Medicine Pole Hill Units [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Proved property impairments | 75,900,000 | |||
South Region [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Proved property impairments | 39,700,000 | |||
Non-Bakken North Region [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Proved property impairments | 18,400,000 | |||
Emerging Areas [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Proved property impairments | $75,200,000 |
Fair_Value_Measurements_Fair_V
Fair Value Measurements - Fair Values of Financial Instruments not Recorded at Fair Value (Detail) (USD $) | 12 Months Ended | |||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Feb. 17, 2015 | 19-May-14 | Dec. 31, 2013 | ||
8 1/4% Senior Notes due 2019 [Member] | ||||||
Fair Value Measurements [Line Items] | ||||||
Debt instrument, maturity date | 2019 | |||||
Debt instrument, stated interest rate | 8.25% | |||||
7 3/8% Senior Notes due 2020 [Member] | ||||||
Fair Value Measurements [Line Items] | ||||||
Debt instrument, maturity date | 2020 | |||||
Debt instrument, stated interest rate | 7.38% | |||||
7 1/8% Senior Notes due 2021 [Member] | ||||||
Fair Value Measurements [Line Items] | ||||||
Debt instrument, maturity date | 2021 | |||||
Debt instrument, stated interest rate | 7.13% | |||||
5% Senior Notes due 2022 [Member] | ||||||
Fair Value Measurements [Line Items] | ||||||
Debt instrument, maturity date | 2022 | |||||
Debt instrument, stated interest rate | 5.00% | |||||
4 1/2% Senior Notes due 2023 [Member] | ||||||
Fair Value Measurements [Line Items] | ||||||
Debt instrument, maturity date | 2023 | |||||
Debt instrument, stated interest rate | 4.50% | |||||
3.8% Senior Notes due 2024 [Member] | ||||||
Fair Value Measurements [Line Items] | ||||||
Debt instrument, maturity date | 2024 | |||||
Debt instrument, stated interest rate | 3.80% | |||||
Senior notes | 1,000,000 | |||||
4.9% Senior Notes due 2044 [Member] | ||||||
Fair Value Measurements [Line Items] | ||||||
Debt instrument, maturity date | 2044 | |||||
Debt instrument, stated interest rate | 4.90% | |||||
Senior notes | 700,000 | |||||
Carrying Amount [Member] | ||||||
Fair Value Measurements [Line Items] | ||||||
Revolving credit facility | 165,000 | 605,000 | 1,010,000 | 275,000 | ||
Note payable | 16,457 | 18,470 | ||||
Total debt | 5,997,915 | 4,715,832 | ||||
Carrying Amount [Member] | 8 1/4% Senior Notes due 2019 [Member] | ||||||
Fair Value Measurements [Line Items] | ||||||
Senior notes | 0 | [1] | 298,305 | [1] | ||
Carrying Amount [Member] | 7 3/8% Senior Notes due 2020 [Member] | ||||||
Fair Value Measurements [Line Items] | ||||||
Senior notes | 198,850 | [2] | 198,695 | [2] | ||
Carrying Amount [Member] | 7 1/8% Senior Notes due 2021 [Member] | ||||||
Fair Value Measurements [Line Items] | ||||||
Senior notes | 400,000 | [3] | 400,000 | [3] | ||
Carrying Amount [Member] | 5% Senior Notes due 2022 [Member] | ||||||
Fair Value Measurements [Line Items] | ||||||
Senior notes | 2,022,949 | [4] | 2,025,362 | [4] | ||
Carrying Amount [Member] | 4 1/2% Senior Notes due 2023 [Member] | ||||||
Fair Value Measurements [Line Items] | ||||||
Senior notes | 1,500,000 | [3] | 1,500,000 | [3] | ||
Carrying Amount [Member] | 3.8% Senior Notes due 2024 [Member] | ||||||
Fair Value Measurements [Line Items] | ||||||
Senior notes | 996,622 | [5] | ||||
Carrying Amount [Member] | 4.9% Senior Notes due 2044 [Member] | ||||||
Fair Value Measurements [Line Items] | ||||||
Senior notes | 698,037 | [6] | ||||
Fair Value [Member] | ||||||
Fair Value Measurements [Line Items] | ||||||
Revolving credit facility | 165,000 | 275,000 | ||||
Note payable | 14,900 | 16,500 | ||||
Total debt | 5,485,700 | 4,876,000 | ||||
Fair Value [Member] | 8 1/4% Senior Notes due 2019 [Member] | ||||||
Fair Value Measurements [Line Items] | ||||||
Senior notes | 0 | 327,800 | ||||
Fair Value [Member] | 7 3/8% Senior Notes due 2020 [Member] | ||||||
Fair Value Measurements [Line Items] | ||||||
Senior notes | 213,000 | 223,700 | ||||
Fair Value [Member] | 7 1/8% Senior Notes due 2021 [Member] | ||||||
Fair Value Measurements [Line Items] | ||||||
Senior notes | 421,000 | 450,300 | ||||
Fair Value [Member] | 5% Senior Notes due 2022 [Member] | ||||||
Fair Value Measurements [Line Items] | ||||||
Senior notes | 1,857,900 | 2,063,300 | ||||
Fair Value [Member] | 4 1/2% Senior Notes due 2023 [Member] | ||||||
Fair Value Measurements [Line Items] | ||||||
Senior notes | 1,372,800 | 1,519,400 | ||||
Fair Value [Member] | 3.8% Senior Notes due 2024 [Member] | ||||||
Fair Value Measurements [Line Items] | ||||||
Senior notes | 868,700 | |||||
Fair Value [Member] | 4.9% Senior Notes due 2044 [Member] | ||||||
Fair Value Measurements [Line Items] | ||||||
Senior notes | 572,400 | |||||
[1] | The carrying amount is net of an unamortized discount of $1.7 million at December 31, 2013. | |||||
[2] | The carrying amount is net of unamortized discounts of $1.2 million and $1.3 million at December 31, 2014 and 2013, respectively. | |||||
[3] | These notes were sold at par and are recorded at 100% of face value. | |||||
[4] | The carrying amount includes an unamortized premium of $22.9 million and $25.4 million at December 31, 2014 and 2013, respectively. | |||||
[5] | The carrying amount is net of an unamortized discount of $3.4 million at December 31, 2014. | |||||
[6] | The carrying amount is net of an unamortized discount of $2.0 million at December 31, 2014. |
LongTerm_Debt_LongTerm_Debt_De
Long-Term Debt - Long-Term Debt (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |||||||
Dec. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Feb. 17, 2015 | 19-May-14 | ||||
Debt Instrument [Line Items] | |||||||||
Less: Current portion of long-term debt | ($2,078,000) | ($2,078,000) | ($2,011,000) | ||||||
Long-term debt, net of current portion | 5,995,837,000 | 5,995,837,000 | 4,713,821,000 | ||||||
Proceeds from Debt, Net of Issuance Costs | 1,680,000,000 | ||||||||
Loss on extinguishment of debt | -24,517,000 | 0 | 0 | ||||||
8 1/4% Senior Notes due 2019 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Total Redemption Amount | 317,500,000 | 317,500,000 | |||||||
Debt instrument, stated interest rate | 8.25% | 8.25% | |||||||
Discounts | 1,700,000 | ||||||||
Loss on extinguishment of debt | 24,517,000 | ||||||||
7 3/8% Senior Notes due 2020 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument, stated interest rate | 7.38% | 7.38% | |||||||
Discounts | 1,200,000 | 1,200,000 | 1,300,000 | ||||||
7 1/8% Senior Notes due 2021 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument, stated interest rate | 7.13% | 7.13% | |||||||
5% Senior Notes due 2022 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument, stated interest rate | 5.00% | 5.00% | |||||||
Premium | 22,900,000 | 22,900,000 | 25,400,000 | ||||||
4.5% Senior Notes due 2023 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt instrument, stated interest rate | 4.50% | 4.50% | |||||||
3.8% Senior Notes due 2024 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Senior notes | 1,000,000,000 | 1,000,000,000 | |||||||
Debt instrument, stated interest rate | 3.80% | 3.80% | |||||||
Discounts | 3,400,000 | 3,400,000 | |||||||
4.9% Senior Notes due 2044 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Senior notes | 700,000,000 | 700,000,000 | |||||||
Debt instrument, stated interest rate | 4.90% | 4.90% | |||||||
Discounts | 2,000,000 | 2,000,000 | |||||||
Senior Notes [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Senior notes recorded as percentage of face value | 100.00% | 100.00% | |||||||
Carrying Amount [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Revolving credit facility | 165,000,000 | 165,000,000 | 275,000,000 | 605,000,000 | 1,010,000,000 | ||||
Note payable | 16,457,000 | 16,457,000 | 18,470,000 | ||||||
Total debt | 5,997,915,000 | 5,997,915,000 | 4,715,832,000 | ||||||
Carrying Amount [Member] | 8 1/4% Senior Notes due 2019 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Senior notes | 0 | [1] | 0 | [1] | 298,305,000 | [1] | |||
Carrying Amount [Member] | 7 3/8% Senior Notes due 2020 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Senior notes | 198,850,000 | [2] | 198,850,000 | [2] | 198,695,000 | [2] | |||
Carrying Amount [Member] | 7 1/8% Senior Notes due 2021 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Senior notes | 400,000,000 | [3] | 400,000,000 | [3] | 400,000,000 | [3] | |||
Carrying Amount [Member] | 5% Senior Notes due 2022 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Senior notes | 2,022,949,000 | [4] | 2,022,949,000 | [4] | 2,025,362,000 | [4] | |||
Carrying Amount [Member] | 4.5% Senior Notes due 2023 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Senior notes | 1,500,000,000 | [3] | 1,500,000,000 | [3] | 1,500,000,000 | [3] | |||
Carrying Amount [Member] | 3.8% Senior Notes due 2024 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Senior notes | 996,622,000 | [5] | 996,622,000 | [5] | |||||
Carrying Amount [Member] | 4.9% Senior Notes due 2044 [Member] | |||||||||
Debt Instrument [Line Items] | |||||||||
Senior notes | $698,037,000 | [6] | $698,037,000 | [6] | |||||
[1] | The carrying amount is net of an unamortized discount of $1.7 million at December 31, 2013. | ||||||||
[2] | The carrying amount is net of unamortized discounts of $1.2 million and $1.3 million at December 31, 2014 and 2013, respectively. | ||||||||
[3] | These notes were sold at par and are recorded at 100% of face value. | ||||||||
[4] | The carrying amount includes an unamortized premium of $22.9 million and $25.4 million at December 31, 2014 and 2013, respectively. | ||||||||
[5] | The carrying amount is net of an unamortized discount of $3.4 million at December 31, 2014. | ||||||||
[6] | The carrying amount is net of an unamortized discount of $2.0 million at December 31, 2014. |
LongTerm_Debt_Additional_Infor
Long-Term Debt - Additional Information (Detail) (USD $) | 12 Months Ended | ||||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Feb. 17, 2015 | 19-May-14 | |||
Debt Instrument [Line Items] | |||||||
Aggregate amount of lender commitments on credit facility | $1,750,000,000 | ||||||
Maximum borrowing capacity | 4,000,000,000 | ||||||
Line of credit facility, commitment fee percentage, per annum | 0.23% | ||||||
Line of Credit Facility, Covenant Terms | 0.65 | ||||||
Proceeds from issuance of Senior Notes | 1,681,834,000 | 1,479,375,000 | 1,999,000,000 | ||||
Repayments of Lines of Credit | 1,805,000,000 | 1,290,000,000 | 1,882,000,000 | ||||
Debt Instrument Percentage Redeemable | 35.00% | ||||||
Current portion of long-term debt | 2,078,000 | 2,011,000 | |||||
Revolving Credit Facility [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Line of credit facility, unused commitments | 1,900,000,000 | ||||||
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 | 26-Feb-22 | ||||||
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 | 15-Apr-23 | ||||||
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 | 1,000,000,000 | ||||||
Debt instrument, stated interest rate | 3.80% | ||||||
4.9% Senior Notes due 2044 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Senior notes | 700,000,000 | ||||||
Debt instrument, stated interest rate | 4.90% | ||||||
Carrying Amount [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Line of credit facility, amount outstanding | 165,000,000 | 275,000,000 | 605,000,000 | 1,010,000,000 | |||
Notes Payable | 16,457,000 | 18,470,000 | |||||
Carrying Amount [Member] | 5% Senior Notes due 2022 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Senior notes | 2,022,949,000 | [1] | 2,025,362,000 | [1] | |||
Carrying Amount [Member] | 4.5% Senior Notes due 2023 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Senior notes | 1,500,000,000 | [2] | 1,500,000,000 | [2] | |||
Carrying Amount [Member] | 3.8% Senior Notes due 2024 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Senior notes | 996,622,000 | [3] | |||||
Carrying Amount [Member] | 4.9% Senior Notes due 2044 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Senior notes | $698,037,000 | [4] | |||||
[1] | The carrying amount includes an unamortized premium of $22.9 million and $25.4 million at December 31, 2014 and 2013, respectively. | ||||||
[2] | These notes were sold at par and are recorded at 100% of face value. | ||||||
[3] | The carrying amount is net of an unamortized discount of $3.4 million at December 31, 2014. | ||||||
[4] | The carrying amount is net of an unamortized discount of $2.0 million at December 31, 2014. |
LongTerm_Debt_Summary_of_Matur
Long-Term Debt - Summary of Maturity Dates, Semi-Annual Interest Payment Dates, and Optional Redemption Periods Of Outstanding Senior Note Obligations (Detail) | 12 Months Ended | |
Dec. 31, 2014 | ||
2020 Notes [Member] | ||
Debt Instrument [Line Items] | ||
Maturity date | 1-Oct-20 | |
Interest Payment Dates | April 1,Oct. 1 | |
Decreasing call premium redemption period | 1-Oct-15 | [1] |
Make-whole redemption period | 1-Oct-15 | [2] |
2021 Notes [Member] | ||
Debt Instrument [Line Items] | ||
Maturity date | 1-Apr-21 | |
Interest Payment Dates | April 1, Oct. 1 | |
Decreasing call premium redemption period | 1-Apr-16 | [1] |
Make-whole redemption period | 1-Apr-16 | [2] |
2022 Notes [Member] | ||
Debt Instrument [Line Items] | ||
Maturity date | 15-Sep-22 | |
Interest Payment Dates | March 15, Sept. 15 | |
Decreasing call premium redemption period | 15-Mar-17 | [1] |
Make-whole redemption period | 15-Mar-17 | [2] |
Redemption using equity offering proceeds | 15-Mar-15 | [3] |
Senior Notes Due 2023 [Member] | ||
Debt Instrument [Line Items] | ||
Maturity date | 15-Apr-23 | |
Interest Payment Dates | April 15, Oct. 15 | |
Make-whole redemption period | 15-Jan-23 | [2] |
Senior Notes due 2024 [Member] | ||
Debt Instrument [Line Items] | ||
Maturity date | 1-Jun-24 | |
Interest Payment Dates | June 1, Dec. 1 | |
Make-whole redemption period | 1-Mar-24 | [2] |
Senior Notes due 2044 [Member] | ||
Debt Instrument [Line Items] | ||
Maturity date | 1-Jun-44 | |
Interest Payment Dates | June 1, Dec. 1 | |
Make-whole redemption period | 1-Dec-43 | [2] |
[1] | On or after these dates, the Company has the option to redeem all or a portion of its senior notes at the decreasing redemption prices specified in the respective senior note indentures (together, the “Indenturesâ€) 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 at the “make-whole†redemption prices or amounts specified in the Indentures plus any accrued and unpaid interest to the date of redemption. | |
[3] | At any time prior to this date, the Company may redeem up to 35% of the principal amount of its 2022 Notes under certain circumstances with the net cash proceeds from one or more equity offerings at the redemption prices specified in the indenture for the 2022 Notes plus any accrued and unpaid interest to the date of redemption. |
Income_Taxes_Provision_for_Inc
Income Taxes - Provision for Income Taxes (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Income Tax Disclosure [Abstract] | |||
Current tax provision, Federal | $0 | $6,193 | $9,191 |
Current tax provision, State | 20 | 16 | 1,326 |
Total current income tax provision | 20 | 6,209 | 10,517 |
Deferred tax provision, Federal | 527,315 | 403,002 | 383,157 |
Deferred tax provision, State | 57,362 | 39,619 | 22,137 |
Total deferred income tax provision | 584,677 | 442,621 | 405,294 |
Provision for income taxes | $584,697 | $448,830 | $415,811 |
Income_Taxes_Schedule_of_Provi
Income Taxes - Schedule of Provision for Income Taxes with Income Tax at Federal Statutory Rate (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Income Tax Disclosure [Abstract] | |||
Expected income tax expense based on US statutory tax rate of 35% | $546,713 | $424,567 | $404,319 |
State income taxes, net of federal benefit | 42,169 | 25,838 | 15,213 |
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount | 4,389 | ||
Deferred Tax Assets, Valuation Allowance | 4,389 | 0 | 0 |
Effect of differing statutory tax rate in Canada | -1,900 | 0 | 0 |
Other, net | -6,674 | -1,575 | -3,721 |
Provision for income taxes | $584,697 | $448,830 | $415,811 |
Federal statutory income tax rate | 35.00% |
Income_Taxes_Components_of_Def
Income Taxes - Components of Deferred Tax Assets and Liabilities (Detail) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | ||
Income Tax Disclosure [Abstract] | ||||
Deferred tax assets, Non-cash losses on derivatives, Current | $0 | [1] | $33,029,000 | [1] |
Deferred tax assets, Other, Current | 3,274,000 | [1] | 2,288,000 | [1] |
Total current deferred tax assets | 3,274,000 | 35,317,000 | ||
Deferred Tax Liabilities, Derivatives | -19,293,000 | |||
Deferred Tax Liabilities, Gain on Liquidation of Derivatives | -128,198,000 | |||
Deferred tax liabilities, Non-cash gains on derivatives, Current | -1,132,000 | -645,000 | ||
Deferred Tax Liabilities, Gross, Current | -148,623,000 | -645,000 | ||
Total current deferred tax liabilities | -145,349,000 | 34,672,000 | ||
Deferred tax assets, Net operating loss carryforwards, Noncurrent | 60,904,000 | 41,791,000 | ||
Deferred tax assets, Non-cash losses on derivatives, Noncurrent | 0 | 2,975,000 | ||
Deferred tax assets, Alternative minimum tax carryforwards, Noncurrent | 38,715,000 | 38,689,000 | ||
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Share-based Compensation Cost | 22,255,000 | 16,961,000 | ||
Deferred tax assets, Other, Noncurrent | 10,545,000 | 3,259,000 | ||
Total noncurrent deferred tax assets | 132,419,000 | 103,675,000 | ||
Deferred Tax Assets, Valuation Allowance, Noncurrent | -4,389,000 | |||
Deferred Tax Assets, Net, Noncurrent | 128,030,000 | 103,675,000 | ||
Deferred tax liabilities, Property and equipment, Noncurrent | -2,254,343,000 | -1,840,331,000 | ||
Deferred Tax Liabilities Unrealized Gains on Derivatives, noncurrent | -10,976,000 | |||
Deferred tax liabilities, Non-cash gains on derivatives, Noncurrent | -4,158,000 | -156,000 | ||
Total noncurrent deferred tax liabilities | -2,269,477,000 | -1,840,487,000 | ||
Net noncurrent deferred tax liabilities | -2,141,447,000 | -1,736,812,000 | ||
Net deferred tax liabilities | -2,286,796,000 | -1,702,140,000 | ||
Income Taxes Receivable | $63,300,000 | $9,700,000 | ||
[1] | Deferred and prepaid taxes on the consolidated balance sheets contain receivables of $63.3 million and $9.7 million for prepaid income taxes at December 31, 2014 and 2013, respectively. |
Income_Taxes_Additional_Inform
Income Taxes - Additional Information (Detail) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Operating Loss Carryforwards [Line Items] | |||
Federal Operating Loss Carryforwards | $19,000,000 | ||
Net operating loss carryforwards, State | 1,390,000,000 | ||
Alternative minimum tax credit carryforward | 0 | ||
Deferred Tax Assets, Valuation Allowance | 4,389,000 | 0 | 0 |
Oklahoma [Member] | |||
Operating Loss Carryforwards [Line Items] | |||
Net operating loss carryforwards, State | $1,370,000,000 |
Lease_Commitments_Lease_Commit
Lease Commitments - Lease Commitments (Detail) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Leases [Abstract] | |||
Lease expenses associated with operating leases | $8,000,000 | $3,000,000 | $2,200,000 |
2014 | 4,953,000 | ||
2015 | 3,256,000 | ||
2016 | 1,234,000 | ||
2017 | 856,000 | ||
2018 | 300,000 | ||
Thereafter | 3,468,000 | ||
Total obligations | $14,067,000 |
Commitments_and_Contingencies_
Commitments and Contingencies - Additional Information (Detail) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Long-term Purchase Commitment [Line Items] | ||
Total future drilling commitments at balance sheet date | $610 | |
Drilling commitments 2015 | 246 | |
Drilling commitments 2016 | 212 | |
Drilling commitments 2017 | 123 | |
Drilling commitments 2018 | 29 | |
Damages claimed related to contingency matter | 165 | |
Legal proceedings recorded as a liability under other noncurrent liabilities | 2.9 | 1.7 |
Future Drilling Commitments End Date | 2018-07 | |
Pipeline Transportation Commitments [Member] | ||
Long-term Purchase Commitment [Line Items] | ||
Future commitment, end date | 2025 | |
Future commitment, total | 969 | |
Future commitment, due in 2015 | 182 | |
Future commitment, due in 2016 | 187 | |
Future commitment, due in 2017 | 181 | |
Future commitment, due in 2018 | 176 | |
Future commitment, due in 2019 | 140 | |
Future commitments, thereafter | 103 | |
Non-operational Pipeline Transportation Commitments[Member] | ||
Long-term Purchase Commitment [Line Items] | ||
Future commitment, in years | 5 years | |
Future commitment, total | 260 | |
Fuel [Member] | ||
Long-term Purchase Commitment [Line Items] | ||
Future commitment, total | 96 | |
Future commitment, due in 2015 | 64 | |
Future commitment, due in 2016 | 32 | |
Affiliated Entity [Member] | ||
Long-term Purchase Commitment [Line Items] | ||
Contractual Obligation | 96 | |
Affiliated Entity [Member] | Pipeline Transportation Commitments [Member] | ||
Long-term Purchase Commitment [Line Items] | ||
Future commitment, total | $96 |
Related_Party_Transactions_Add
Related Party Transactions - Additional Information (Detail) (USD $) | 3 Months Ended | 12 Months Ended | 1 Months Ended | |||
Share data in Millions, except Per Share data, unless otherwise specified | Dec. 31, 2012 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Aug. 31, 2012 |
Bbls | ||||||
Related Party Transaction [Line Items] | ||||||
Deferred Income Taxes Associated With Acquired Properties | $57,000,000 | |||||
Asset Retirement Obligations Assumed In Acquisition | 600,000 | |||||
Revenues from transactions with related party | 95,128,000 | 100,405,000 | 58,892,000 | |||
Due from affiliates | 13,100,000 | 12,700,000 | ||||
Due to Affiliate | 300,000 | 200,000 | ||||
Expenses from transactions with related party | 700,000 | |||||
Related party transaction, due to related party | 1,200,000 | |||||
Production expenses to affiliates | 5,123,000 | 1,408,000 | 1,974,000 | |||
Total amount paid to related party | 58,200,000 | 48,500,000 | 32,700,000 | |||
Due to affiliates | 5,600,000 | 5,100,000 | ||||
Amount charged to affiliate for aircraft use | 51,000 | 55,000 | 112,000 | |||
Amount charged to company by affiliate for aircraft use | 97,000 | 51,000 | 102,000 | |||
Issuance of common stock to acquire property, in shares | 7.8 | 7.8 | ||||
Common Stock, Par or Stated Value Per Share | $0.01 | $0.01 | $0.01 | $0.01 | ||
Consideration cost | 279,000,000 | |||||
Purchase price adjustment arising after closing date | 500,000 | |||||
Oil And Natural Gas [Member] | ||||||
Related Party Transaction [Line Items] | ||||||
Joint Interest Obligations Assumed In Acquisition | 38,000,000 | |||||
Net book value | 177,000,000 | |||||
Affiliated Entity [Member] | ||||||
Related Party Transaction [Line Items] | ||||||
Revenues from transactions with related party | 1,900,000 | |||||
Number of barrels sold to affiliate | 21,000 | |||||
Number of barrels purchased from affiliate | 30,000 | 2,000 | ||||
Purchases from transactions with related party | 3,000,000 | 200,000 | ||||
Expenses from transactions with related party | 1,800,000 | |||||
Capitalized costs | 5,000,000 | 5,900,000 | 5,700,000 | 5,000,000 | ||
Production expenses to affiliates | 5,100,000 | 1,400,000 | 2,000,000 | |||
Total amount paid to related party | 1,900,000 | |||||
Related Party Transaction Transportation Contract Period | 5 | |||||
Crude Oil Pipeline Capacity Per Day | 10,000 | |||||
Related Party Transaction Transportation Charges For Crude Oil Per Barrel | 5.25 | |||||
Contractual Obligation | 96,000,000 | |||||
Officers And Other Key Employees [Member] | ||||||
Related Party Transaction [Line Items] | ||||||
Revenues from transactions with related party | 800,000 | 1,300,000 | 38,500,000 | |||
Total amount paid to related party | 0 | 300,000 | ||||
Due to affiliates | 100,000 | 200,000 | ||||
Revenues paid to related party | 1,700,000 | 2,300,000 | 38,300,000 | |||
Due from affiliates | 200,000 | 400,000 | ||||
Other Affiliates [Member] | ||||||
Related Party Transaction [Line Items] | ||||||
Total amount paid to related party | 34,000 | 238,000 | ||||
Total amount received from related party | 39,000 | 379,000 | ||||
Wheatland Oil Inc. [Member] | Chief Executive Officer [Member] | ||||||
Related Party Transaction [Line Items] | ||||||
CEO ownership in related party | 75.00% | |||||
Wheatland Oil Inc. [Member] | Vice Chairman [Member] | ||||||
Related Party Transaction [Line Items] | ||||||
Vice Chairman ownership in related party | 25.00% | |||||
Wheatland [Member] | ||||||
Related Party Transaction [Line Items] | ||||||
Net book value | 82,000,000 | |||||
Affiliated Entity [Member] | ||||||
Related Party Transaction [Line Items] | ||||||
Revenues from transactions with related party | $100,400,000 | $57,000,000 |
Stock_Based_Compensation_Assoc
Stock Based Compensation - Associated Compensation Expense (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||
Non-cash equity compensation | $54,353 | $39,890 | $29,057 |
StockBased_Compensation_Additi
Stock-Based Compensation - Additional Information (Detail) (USD $) | 12 Months Ended | |||
In Millions, except Share data, unless otherwise specified | Dec. 31, 2012 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2011 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Total intrinsic value of options exercised | $7.60 | |||
Restricted stock [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Fair value at vesting date | 58.2 | 49.4 | 33 | |
Unrecognized compensation expense related to non-vested | $72 | |||
Unrecognized compensation expense related to non-vested, period for recognition, in years | 1 year 5 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 | 18,104,686 |
Stock_Based_Compensation_Sched
Stock Based Compensation - Schedule of Stock Option Activity (Detail) (USD $) | 12 Months Ended |
Dec. 31, 2012 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward] | |
Number of stock options, Outstanding, Beginning of period | 173,000 |
Number of stock options, Outstanding, Exercised | -173,000 |
Number of stock options, Outstanding, End of period | 0 |
Weighted average exercise price, Outstanding, Beginning of period | $0.36 |
Weighted average exercise price, Outstanding, Exercised | $0.36 |
Number of stock options, Exercisable, Beginning of period | 173,000 |
Number of stock options, Exercisable, End of period | 0 |
Weighted average exercise price, Exercisable, Beginning of period | $0.36 |
Stock_Based_Compensation_Summa
Stock Based Compensation - Summary of Changes in Non Vested Shares of Restricted Stock (Detail) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
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 | 2,714,312 | 3,258,924 | 2,396,688 |
Granted shares | 1,424,764 | 522,518 | 1,832,056 |
Vested shares | -1,007,166 | -929,618 | -889,446 |
Forfeited shares | -453,146 | -137,512 | -80,374 |
Non-vested shares, ending balance | 2,678,764 | 2,714,312 | 3,258,924 |
Non-vested, weighted average grant-date fair value, beginning of period | $37.50 | $31.64 | $24.33 |
Granted, weighted average grant-date fair value | $61.11 | $48.98 | $36.73 |
Vested, weighted average grant-date fair value | $35.91 | $23.65 | $22.63 |
Forfeited, weighted average grant-date fair value | $44.90 | $35.96 | $29.53 |
Non-vested, weighted average grant-date fair value, end of period | $49.40 | $37.50 | $31.64 |
Property_Acquisition_and_Dispo
Property Acquisition and Dispositions - Additional Information (Detail) (USD $) | 3 Months Ended | 12 Months Ended | 1 Months Ended | |||
Sep. 30, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Feb. 29, 2012 | |
acre | acre | |||||
Property Acquisition And Dispositions [Line Items] | ||||||
Acquired producing properties in cash | $458,446,000 | $563,485,000 | $1,484,016,000 | |||
Acquisitions and disposals proceeds | 90,000,000 | 126,400,000 | 126,400,000 | |||
Recognized pre-tax gain | 68,000,000 | 68,000,000 | ||||
Asset retirement obligations for disposed properties | 8,300,000 | 8,300,000 | ||||
Interest Sold | 49.90% | |||||
Net Acres Sold | 44,000 | |||||
Amount of capital to be funded by partner | 270,000,000 | |||||
Percent of capital funded by partner | 50.00% | |||||
NORTH DAKOTA | ||||||
Property Acquisition And Dispositions [Line Items] | ||||||
Acquired producing properties in cash | 663,300,000 | 276,000,000 | ||||
Acres acquired | 119,000 | 119,000 | 23,100 | |||
NORTH DAKOTA | Producing Properties [Member] | ||||||
Property Acquisition And Dispositions [Line Items] | ||||||
Daily production of acquired producing properties, barrels of oil per day | 6,500 | 6,500 | 1,000 | |||
NORTH DAKOTA | Producing properties [Member] | ||||||
Property Acquisition And Dispositions [Line Items] | ||||||
Acquired producing properties in cash | 477,100,000 | 51,700,000 | ||||
Wyoming [Member] | ||||||
Property Acquisition And Dispositions [Line Items] | ||||||
Acquisitions and disposals proceeds | 84,400,000 | |||||
Recognized pre-tax gain | 50,100,000 | |||||
Asset retirement obligations for disposed properties | 11,100,000 | |||||
Oklahoma [Member] | ||||||
Property Acquisition And Dispositions [Line Items] | ||||||
Acquisitions and disposals proceeds | 15,900,000 | 15,900,000 | ||||
Recognized pre-tax gain | 15,900,000 | 15,900,000 | ||||
Asset retirement obligations for disposed properties | $600,000 | $600,000 |
Property_Transaction_with_Rela
Property Transaction with Related Party - Additional Information (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |
In Millions, except Per Share data, unless otherwise specified | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2014 |
Related Party Transaction [Line Items] | |||
Issuance of common stock to acquire property, in shares | 7.8 | ||
Common Stock, Par or Stated Value Per Share | $0.01 | $0.01 | $0.01 |
Consideration cost | $279 | ||
Purchase price adjustment arising after closing date | 0.5 | ||
Asset Retirement Obligations Assumed In Acquisition | 0.6 | ||
Deferred Income Taxes Associated With Acquired Properties | 57 | ||
Wheatland [Member] | |||
Related Party Transaction [Line Items] | |||
Net book value | 82 | ||
Oil And Natural Gas [Member] | |||
Related Party Transaction [Line Items] | |||
Net book value | 177 | ||
Joint Interest Obligations Assumed In Acquisition | $38 |
Crude_Oil_and_Natural_Gas_Prop2
Crude Oil and Natural Gas Property Information - Schedule of Results of Operations from Crude Oil and Natural Gas Producing Activities (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |||
Crude oil and natural gas sales | $4,203,022 | $3,573,431 | $2,349,500 |
Production expenses | -352,472 | -282,197 | -195,440 |
Production taxes and other expenses (1) | -349,760 | -298,787 | -198,505 |
Exploration Expense | -50,067 | -34,947 | -23,507 |
Depreciation, depletion, amortization and accretion | -1,338,351 | -953,796 | -683,207 |
Property impairments | -616,888 | -220,508 | -122,274 |
Income taxes | -559,311 | -659,783 | -428,095 |
Results from crude oil and natural gas producing activities | $936,173 | $1,123,413 | $698,472 |
Crude_Oil_and_Natural_Gas_Prop3
Crude Oil and Natural Gas Property Information - Schedule of Costs Incurred in Oil and Gas Property Acquisition Exploration and Development Activities (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |||
Property Acquisition Costs - Proved | $48,917 | $16,604 | $738,415 |
Property Acquisition Costs - Unproved | 409,529 | 546,881 | 745,601 |
Total property acquisition costs | 458,446 | 563,485 | 1,484,016 |
Exploration Costs | 863,606 | 687,767 | 857,681 |
Development Costs | 3,670,448 | 2,549,203 | 1,975,660 |
Total | $4,992,500 | $3,800,455 | $4,317,357 |
Crude_Oil_and_Natural_Gas_Prop4
Crude Oil and Natural Gas Property Information - Additional Information (Detail) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |||
Exploration costs included in asset retirement costs | $1.20 | $1.80 | $3.30 |
Development costs included in asset retirement costs | $19.10 | $6 | $1 |
Crude_Oil_and_Natural_Gas_Prop5
Crude Oil and Natural Gas Property Information - Schedule of Aggregate Capitalized Costs Relates to Crude Oil and Natural Gas Producing Activities (Detail) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | ||
Proved crude oil and natural gas properties | $17,045,967 | $12,423,878 |
Unproved crude oil and natural gas properties | 966,080 | 1,181,268 |
Total | 18,012,047 | 13,605,146 |
Less accumulated depreciation, depletion and amortization | -4,601,864 | -3,083,180 |
Net capitalized costs | $13,410,183 | $10,521,966 |
Crude_Oil_and_Natural_Gas_Prop6
Crude Oil and Natural Gas Property Information - Schedule of Capitalized Exploratory Drilling Costs Pending Evaluation (Detail) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Well | Well | Well | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |||
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year | $4,500,000 | ||
Number Of Wells With Capitalized Exploratory Well Costs Suspended One Year Beyond Completion Of Drilling | 1 | ||
Suspended Well Costs Incurred | 500,000 | 4,000,000 | |
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward] | |||
Balance at January 1 | 152,775,000 | 92,699,000 | 128,123,000 |
Additions to capitalized exploratory well costs pending determination of proved reserves | 627,853,000 | 548,933,000 | 485,530,000 |
Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves | -671,618,000 | -479,507,000 | -520,187,000 |
Capitalized exploratory well costs charged to expense | -15,589,000 | -9,350,000 | -767,000 |
Balance at December 31 | $93,421,000 | $152,775,000 | $92,699,000 |
Number of wells | 119 | 67 | 46 |
Supplemental_Crude_Oil_and_Nat2
Supplemental Crude Oil and Natural Gas Information - Additional Information (Detail) | 12 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
MMcf | MMcf | MMcf | ||
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 | 95.00% | |||
Revisions of previous estimates | 53 | |||
Revisions of previous estimates | -107,949 | -96,054 | 4,149 | |
Extensions, discoveries and other additions | 440,621 | 444,654 | 233,652 | |
Discount factor utilized as standardized measure for future net cash flows | 10.00% | |||
Crude Oil [Member] | ||||
Reserve Quantities [Line Items] | ||||
Revisions of previous estimates | -67,151 | -55,783 | 33,272 | |
Extensions, discoveries and other additions | 239,526 | 267,009 | 166,844 | |
Weighted average price utilized in computation of future cash inflows | 84.54 | 91.5 | 86.56 | |
Natural Gas [Member] | ||||
Reserve Quantities [Line Items] | ||||
Revisions of previous estimates | -244,783 | -241,623 | -174,736 | |
Extensions, discoveries and other additions | 1,206,569 | 1,065,870 | 400,848 | |
Weighted average price utilized in computation of future cash inflows | 6.06 | 5.36 | 4.31 | |
Bakken [Member] | ||||
Reserve Quantities [Line Items] | ||||
Extensions, discoveries and other additions | 184,000 | |||
Extensions, discoveries and other additions | 222,000 | |||
SCOOP [Member] | ||||
Reserve Quantities [Line Items] | ||||
Extensions, discoveries and other additions | 55,000 | |||
Extensions, discoveries and other additions | 208,000 |
Supplemental_Crude_Oil_and_Nat3
Supplemental Crude Oil and Natural Gas Information - Schedule of Proved Crude Oil and Natural Gas Reserves (Detail) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
MMcf | MBoe | MBoe | |
MBoe | |||
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] | |||
Revisions of previous estimates | 315 | ||
Proved reserves at beginning of period, Total | 1,084,125 | 784,677 | 508,438 |
Revisions of previous estimates, Total | -107,949 | -96,054 | 4,149 |
Extensions, discoveries and other additions, Total | 440,621 | 444,654 | 233,652 |
Production, Total | -63,579 | -49,610 | -35,716 |
Sales of minerals in place, Total | -3,227 | 0 | -7,838 |
Purchases of minerals in place, Total | 1,100 | 458 | 81,992 |
Proved reserves at end of period, Total | 1,351,091 | 1,084,125 | 784,677 |
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 | 95.00% | ||
Natural Gas [Member] | |||
Changes in Proved Reserves [Roll Forward] | |||
Proved reserves at beginning of period | 2,078,020 | 1,341,084 | 1,093,832 |
Revisions of previous estimates | -244,783 | -241,623 | -174,736 |
Extensions, discoveries and other additions | 1,206,569 | 1,065,870 | 400,848 |
Production | -114,295 | -87,730 | -63,875 |
Sales of minerals in place | -18,623 | 0 | -4,046 |
Purchases of minerals in place | 1,498 | 419 | 89,061 |
Proved reserves at end of period | 2,908,386 | 2,078,020 | 1,341,084 |
Crude Oil [Member] | |||
Changes in Proved Reserves [Roll Forward] | |||
Proved reserves at beginning of period | 737,788 | 561,163 | 326,133 |
Revisions of previous estimates | -67,151 | -55,783 | 33,272 |
Extensions, discoveries and other additions | 239,526 | 267,009 | 166,844 |
Production | -44,530 | -34,989 | -25,070 |
Sales of minerals in place | -123 | 0 | -7,165 |
Purchases of minerals in place | 850 | 388 | 67,149 |
Proved reserves at end of period | 866,360 | 737,788 | 561,163 |
Supplemental_Crude_Oil_and_Nat4
Supplemental Crude Oil and Natural Gas Information - Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities (Detail) | 12 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
MBbls | MBbls | MBbls | MBbls | |
Reserve Quantities [Line Items] | ||||
Revisions of previous estimates | 53 | |||
Proved Developed Reserves (MBOE) | 502,479 | 406,792 | 317,786 | |
Proved Undeveloped Reserve (MBOE) | 848,612 | 677,333 | 466,891 | |
Total Proved Reserves (MBOE) | 1,351,091 | 1,084,125 | 784,677 | |
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy) | 105 | |||
Crude Oil [Member] | ||||
Reserve Quantities [Line Items] | ||||
Revisions of previous estimates | -67,151 | -55,783 | 33,272 | |
Proved Developed Reserves (Volume) | 342,137 | 278,630 | 226,870 | |
Proved Undeveloped Reserve (Volume) | 524,223 | 459,158 | 334,293 | |
Total Proved Reserves (Volume) | 866,360 | 737,788 | 561,163 | 326,133 |
Natural Gas [Member] | ||||
Reserve Quantities [Line Items] | ||||
Revisions of previous estimates | -244,783 | -241,623 | -174,736 | |
Proved Developed Reserves (Volume) | 962,051 | 768,969 | 545,499 | |
Proved Undeveloped Reserve (Volume) | 1,946,335 | 1,309,051 | 795,585 | |
Total Proved Reserves (Volume) | 2,908,386 | 2,078,020 | 1,341,084 | 1,093,832 |
Supplemental_Crude_Oil_and_Nat5
Supplemental Crude Oil and Natural Gas Information - Standardized Measure of Discounted Future Net Cash Flows (Detail) (USD $) | 12 Months Ended | |||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Supplemental Crude Oil and Natural Gas Information [Abstract] | ||||
Discount factor utilized as standardized measure for future net cash flows | 10.00% | |||
Future cash inflows | $90,867,459 | $78,646,274 | $54,362,574 | |
Future production costs | -25,799,221 | -21,333,460 | -13,103,469 | |
Future development and abandonment costs | -12,842,174 | -10,250,789 | -8,295,130 | |
Future income taxes | -13,800,737 | -12,447,127 | -8,500,766 | |
Future net cash flows | 38,425,327 | 34,614,898 | 24,463,209 | |
10% annual discount for estimated timing of cash flows | -19,992,293 | -18,319,131 | -13,282,852 | |
Standardized measure of discounted future net cash flows | $18,433,034 | $16,295,767 | $11,180,357 | $7,505,356 |
Supplemental_Crude_Oil_and_Nat6
Supplemental Crude Oil and Natural Gas Information - Changes in Standardized Measure of Discounted Future Net Cash Flows (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
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 | $16,295,767 | $11,180,357 | $7,505,356 |
Extensions, discoveries and improved recoveries, less related costs | 5,516,528 | 6,613,665 | 3,724,136 |
Revisions of previous quantity estimates | -1,755,366 | -1,765,300 | 254,493 |
Changes in estimated future development and abandonment costs | 476,665 | 1,942,585 | -298,148 |
Decrease Due to Sales of Minerals in Place | -3,196 | ||
Purchases (sales) of minerals in place | 12,012 | 1,171,047 | |
Net change in prices and production costs | -1,925,349 | 263,541 | -530,515 |
Accretion of discount | 1,629,576 | 1,118,036 | 750,536 |
Sales of crude oil and natural gas produced, net of production costs | -3,500,790 | -2,992,447 | -1,955,555 |
Development costs incurred during the period | 2,466,748 | 1,210,223 | 1,095,156 |
Change in timing of estimated future production and other | -309,902 | 464,111 | -102,519 |
Change in income taxes | -457,647 | -1,751,016 | -433,630 |
Net change | 2,137,267 | 5,115,410 | 3,675,001 |
Standardized measure of discounted future net cash flows at end of year | $18,433,034 | $16,295,767 | $11,180,357 |
Quarterly_Financial_Data_Sched
Quarterly Financial Data - Schedule Of Quarterly Financial Data (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||||||||||
Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||||||||
Quarterly Financial Information Disclosure [Abstract] | |||||||||||||||||||
Cash Proceeds from Liquidated Derivatives | $433,000,000 | ||||||||||||||||||
Cash Proceeds from Liquidated Derivatives, after tax | 273,000,000 | ||||||||||||||||||
Cash Proceeds from Liquidated Derivatives, per share | $0.74 | ||||||||||||||||||
Non-recurring Impairment Charges in the Fourth Quarter | 340,000,000 | ||||||||||||||||||
Non-recurring Impairment Charges, after tax | 214,000,000 | ||||||||||||||||||
Non-recurring Impairment Charges, per share | $0.58 | ||||||||||||||||||
Reclassified Gas Transportation Charges | 9,100,000 | 8,900,000 | 7,700,000 | 7,600,000 | 33,300,000 | 29,900,000 | |||||||||||||
Total revenues | 1,297,700,000 | [1] | 1,645,328,000 | [1] | 886,095,000 | [1] | 972,495,000 | [1] | 811,220,000 | [1] | 814,887,000 | [1] | 1,093,057,000 | [1] | 702,643,000 | [1] | 4,801,618,000 | 3,421,807,000 | 2,542,587,000 |
Gain (loss) on derivative instruments, net | 387,958,000 | [1] | 473,999,000 | [1] | -262,524,000 | [1] | -39,674,000 | [1] | -102,202,000 | [1] | -203,774,000 | [1] | 199,056,000 | [1] | -84,831,000 | [1] | 559,759,000 | -191,751,000 | 154,016,000 |
Income from operations | 265,228,000 | 944,897,000 | 236,394,000 | 421,317,000 | 273,706,000 | 328,043,000 | 573,872,000 | 270,146,000 | 1,867,836,000 | 1,445,767,000 | 1,292,807,000 | ||||||||
Net income | $114,048,000 | $533,521,000 | $103,538,000 | $226,234,000 | $132,824,000 | $167,498,000 | $323,270,000 | $140,627,000 | $977,341,000 | $764,219,000 | $739,385,000 | ||||||||
Net income per share: Basic | $0.31 | $1.45 | $0.28 | $0.61 | $0.36 | $0.45 | $0.88 | $0.38 | $2.65 | $2.08 | $2.04 | ||||||||
Net income per share: Diluted | $0.31 | $1.44 | $0.28 | $0.61 | $0.36 | $0.45 | $0.87 | $0.38 | $2.64 | $2.07 | $2.03 | ||||||||
[1] | Gains and losses on mark-to-market derivative instruments are reflected in “Total revenues†on both the consolidated statements of comprehensive income 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 as discussed in Note 5. Derivative Instruments. The 2014 fourth quarter also includes $340 million of pre-tax non-cash impairment charges ($214 million after tax, or $0.58 per basic and diluted share) as discussed in Note 6. Fair Value Measurements.(3)Total revenues for the quarterly periods of 2013 have been adjusted to conform to the current year presentation of natural gas transportation and processing charges as discussed in Note 1. Organization and Summary of Significant Accounting Policies. Reclassified amounts total $7.6 million, $7.7 million, $8.9 million and $9.1 million for the first, second, third and fourth quarters of 2013, respectively. |