Document_and_Entity_Informatio
Document and Entity Information (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Feb. 13, 2015 | Jun. 30, 2014 | |
Document and Entity Information [Abstract] | |||
Entity Registrant Name | WHITING PETROLEUM CORP | ||
Entity Central Index Key | 1255474 | ||
Document Type | 10-K | ||
Document Period End Date | 31-Dec-14 | ||
Amendment Flag | FALSE | ||
Current Fiscal Year End Date | -19 | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 167,041,054 | ||
Document Fiscal Year Focus | 2014 | ||
Document Fiscal Period Focus | FY | ||
Entity Public Float | $9,569,978,297 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No |
CONSOLIDATED_BALANCE_SHEETS
CONSOLIDATED BALANCE SHEETS (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Current assets: | ||
Cash and cash equivalents | $78,100 | $699,460 |
Accounts receivable trade, net | 543,172 | 341,177 |
Derivative assets | 135,577 | 1,274 |
Prepaid expenses and other | 86,150 | 27,707 |
Total current assets | 842,999 | 1,069,618 |
Property and equipment: | ||
Oil and gas properties, successful efforts method | 14,949,702 | 10,065,150 |
Other property and equipment | 276,582 | 206,385 |
Total property and equipment | 15,226,284 | 10,271,535 |
Less accumulated depreciation, depletion and amortization | -3,083,572 | -2,676,490 |
Total property and equipment, net | 12,142,712 | 7,595,045 |
Goodwill | 875,676 | |
Debt issuance costs | 53,274 | 48,530 |
Other long-term assets | 104,843 | 120,277 |
TOTAL ASSETS | 14,019,504 | 8,833,470 |
Current liabilities: | ||
Accounts payable trade | 62,664 | 107,692 |
Accrued capital expenditures | 429,970 | 158,739 |
Revenues and royalties payable | 254,018 | 198,558 |
Current portion of Production Participation Plan liability | 113,391 | 73,264 |
Accrued liabilities and other | 169,193 | 144,327 |
Taxes payable | 63,822 | 50,052 |
Accrued interest | 67,913 | 44,405 |
Deferred income taxes | 47,545 | 648 |
Total current liabilities | 1,208,516 | 777,685 |
Long-term debt | 5,628,782 | 2,653,834 |
Deferred income taxes | 1,230,630 | 1,278,030 |
Production Participation Plan liability | 87,503 | |
Asset retirement obligations | 167,741 | 116,442 |
Deferred gain on sale | 60,305 | 79,065 |
Other long-term liabilities | 20,486 | 4,212 |
Total liabilities | 8,316,460 | 4,996,771 |
Commitments and contingencies | ||
Equity: | ||
Common stock, $0.001 par value, 300,000,000 shares authorized; 168,346,020 issued and 166,889,152 outstanding as of December 31, 2014 and 120,101,555 issued and 118,657,245 outstanding as of December 31, 2013 | 168 | 120 |
Additional paid-in capital | 3,385,094 | 1,583,542 |
Retained earnings | 2,309,712 | 2,244,905 |
Total Whiting shareholders' equity | 5,694,974 | 3,828,567 |
Noncontrolling interest | 8,070 | 8,132 |
Total equity | 5,703,044 | 3,836,699 |
TOTAL LIABILITIES AND EQUITY | $14,019,504 | $8,833,470 |
CONSOLIDATED_BALANCE_SHEETS_Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
CONSOLIDATED BALANCE SHEETS [Abstract] | ||
Common stock, par value (in dollars per share) | $0.00 | $0.00 |
Common stock, shares authorized | 300,000,000 | 300,000,000 |
Common stock, shares issued | 168,346,020 | 120,101,555 |
Common stock, shares outstanding | 166,889,152 | 118,657,245 |
CONSOLIDATED_STATEMENTS_OF_INC
CONSOLIDATED STATEMENTS OF INCOME (USD $) | 12 Months Ended | ||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
REVENUES AND OTHER INCOME: | |||
Oil, NGL and natural gas sales | $3,024,617 | $2,666,549 | $2,137,714 |
Gain (loss) on hedging activities | -1,958 | 2,338 | |
Amortization of deferred gain on sale | 30,494 | 31,737 | 29,458 |
Gain on sale of properties | 27,657 | 128,648 | 3,423 |
Interest income and other | 2,329 | 3,409 | 519 |
Total revenues and other income | 3,085,097 | 2,828,385 | 2,173,452 |
COSTS AND EXPENSES: | |||
Lease operating | 496,925 | 430,221 | 376,424 |
Production taxes | 253,008 | 225,403 | 171,625 |
Depreciation, depletion and amortization | 1,089,545 | 891,516 | 684,724 |
Exploration and impairment | 854,430 | 453,210 | 166,972 |
General and administrative | 177,211 | 137,994 | 108,573 |
Interest expense | 170,642 | 112,936 | 75,210 |
Loss on early extinguishment of debt | 4,412 | ||
Change in Production Participation Plan liability | -6,980 | 13,824 | |
Commodity derivative (gain) loss, net | -100,579 | 7,802 | -85,911 |
Total costs and expenses | 2,941,182 | 2,256,514 | 1,511,441 |
INCOME BEFORE INCOME TAXES | 143,915 | 571,871 | 662,011 |
INCOME TAX EXPENSE (BENEFIT): | |||
Current | 2,625 | 986 | -669 |
Deferred | 76,545 | 204,882 | 248,581 |
Total income tax expense | 79,170 | 205,868 | 247,912 |
NET INCOME | 64,745 | 366,003 | 414,099 |
Net loss attributable to noncontrolling interests | 62 | 52 | 90 |
NET INCOME AVAILABLE TO SHAREHOLDERS | 64,807 | 366,055 | 414,189 |
Preferred stock dividends | -538 | -1,077 | |
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS | $64,807 | $365,517 | $413,112 |
EARNINGS PER COMMON SHARE: | |||
Basic (in dollars per share) | $0.53 | $3.09 | $3.51 |
Diluted (in dollars per share) | $0.53 | $3.06 | $3.48 |
WEIGHTED AVERAGE SHARES OUTSTANDING: | |||
Basic (in shares) | 122,138 | 118,260 | 117,601 |
Diluted (in shares) | 122,519 | 119,588 | 119,028 |
CONSOLIDATED_STATEMENTS_OF_COM
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) | 12 Months Ended | ||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME [Abstract] | |||||
NET INCOME | $64,745 | $366,003 | $414,099 | ||
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX: | |||||
OCI amortization on de-designated hedges | 1,236 | [1],[2] | -1,476 | [1],[2] | |
Total other comprehensive income (loss), net of tax | 1,236 | -1,476 | |||
COMPREHENSIVE INCOME | 64,745 | 367,239 | 412,623 | ||
Comprehensive loss attributable to noncontrolling interest | 62 | 52 | 90 | ||
COMPREHENSIVE INCOME ATTRIBUTABLE TO WHITING | $64,807 | $367,291 | $412,713 | ||
[1] | Presented net of income tax expense of $722 for the year ended December 31, 2013 and an income tax benefit of $862 for the year ended December 31, 2012. | ||||
[2] | These OCI amortization amounts on de-designated hedges are reclassified from accumulated other comprehensive income (bAOCIb) to gain (loss) on hedging activities in the consolidated statements of income. |
CONSOLIDATED_STATEMENTS_OF_COM1
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 |
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME [Abstract] | ||
OCI amortization on de-designated hedges, income tax expense | $722 | ($862) |
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 | $64,745 | $366,003 | $414,099 |
Adjustments to reconcile net income to net cash provided by operating activities: | |||
Depreciation, depletion and amortization | 1,089,545 | 891,516 | 684,724 |
Deferred income tax expense | 76,545 | 204,882 | 248,581 |
Amortization of debt issuance costs and debt premium | 11,984 | 12,405 | 9,518 |
Stock-based compensation | 23,258 | 22,436 | 18,190 |
Amortization of deferred gain on sale | -30,494 | -31,737 | -29,458 |
Gain on sale of properties | -27,657 | -128,648 | -3,423 |
Undeveloped leasehold and oil and gas property impairments | 767,627 | 358,455 | 107,855 |
Exploratory dry hole costs | 26,327 | 28,725 | 18,428 |
Loss on early extinguishment of debt | 4,412 | ||
Change in Production Participation Plan liability | -6,980 | 13,824 | |
Non-cash portion of derivative gains | -57,465 | -20,830 | -115,733 |
Other, net | -9,030 | -16,118 | -18,708 |
Changes in current assets and liabilities: | |||
Accounts receivable trade, net | 17,618 | -22,912 | -55,750 |
Prepaid expense and other | -50,352 | -15,981 | 2,535 |
Accounts payable trade and accrued liabilities | -86,480 | 33,360 | 58,647 |
Revenues and royalties payable | -1,963 | 48,988 | 45,798 |
Taxes payable | 1,094 | 16,769 | 2,088 |
Net cash provided by operating activities | 1,815,302 | 1,744,745 | 1,401,215 |
CASH FLOWS FROM INVESTING ACTIVITIES: | |||
Drilling and development capital expenditures | -2,842,837 | -2,349,819 | -2,050,029 |
Acquisition of oil and gas properties, net of cash acquired | -45,573 | -422,923 | -125,282 |
Other property and equipment | -79,955 | -45,304 | 3,852 |
Proceeds from sale of oil and gas properties | 107,848 | 968,606 | 69,190 |
Issuance of note receivable | -10,530 | -306 | |
Cash paid for investing derivatives | -44,900 | ||
Cash settlements received on investing derivatives | 2,371 | ||
Net cash used in investing activities | -2,860,517 | -1,902,499 | -1,780,318 |
CASH FLOWS FROM FINANCING ACTIVITIES: | |||
Redemption of 7% Senior Subordinated Notes due 2014 | -253,988 | ||
Borrowings under credit agreement | 2,150,000 | 1,860,000 | 2,340,000 |
Repayments of borrowings under credit agreement | -1,675,000 | -3,060,000 | -1,920,000 |
Repayment of tax sharing liability | -26,373 | -1,759 | -2,329 |
Debt issuance costs | -14,901 | -29,690 | -2,807 |
Restricted stock used for tax withholdings | -11,652 | -5,611 | -5,695 |
Proceeds from stock options exercised | 1,781 | ||
Preferred stock dividends paid | -538 | -1,077 | |
Net cash provided by financing activities | 423,855 | 812,414 | 408,092 |
NET CHANGE IN CASH AND CASH EQUIVALENTS | -621,360 | 654,660 | 28,989 |
CASH AND CASH EQUIVALENTS: | |||
Beginning of period | 699,460 | 44,800 | 15,811 |
End of period | 78,100 | 699,460 | 44,800 |
SUPPLEMENTAL CASH FLOW DISCLOSURES: | |||
Income taxes paid (refunded), net | 1,380 | 3,681 | -268 |
Interest paid, net of amounts capitalized | 135,150 | 66,541 | 68,005 |
NONCASH INVESTING AND FINANCING ACTIVITIES: | |||
Accrued capital expenditures related to property additions | 429,970 | 158,739 | 110,663 |
Fair value of equity issued and debt assumed in the Kodiak Acquisition | 4,289,088 | ||
Whiting USA Trust II Units [Member] | |||
CASH FLOWS FROM INVESTING ACTIVITIES: | |||
Proceeds from sale of oil and gas properties | 322,257 | ||
Senior Notes [Member] | 5% Senior Notes due 2019 [Member] | |||
CASH FLOWS FROM FINANCING ACTIVITIES: | |||
Issuance of Senior Notes | 1,100,000 | ||
Senior Notes [Member] | 5.75% Senior Notes due 2021 [Member] | |||
CASH FLOWS FROM FINANCING ACTIVITIES: | |||
Issuance of Senior Notes | $1,204,000 |
CONSOLIDATED_STATEMENTS_OF_CAS1
CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) | 12 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2012 | Dec. 31, 2013 | Sep. 30, 2013 | |
Senior Notes [Member] | 5% Senior Notes due 2019 [Member] | ||||
Interest Rate (as a percent) | 5.00% | 5.00% | 5.00% | |
Senior Notes [Member] | 5.75% Senior Notes due 2021 [Member] | ||||
Interest Rate (as a percent) | 5.75% | 5.75% | 5.75% | |
Senior Subordinated Notes [Member] | 7% Senior Subordinated Notes due 2014 [Member] | ||||
Interest Rate (as a percent) | 7.00% | |||
Whiting USA Trust II Units [Member] | ||||
Trust units sold to the public (in shares) | 18,400,000 | 18,400,000 |
CONSOLIDATED_STATEMENTS_OF_EQU
CONSOLIDATED STATEMENTS OF EQUITY (USD $) | Total Whiting Shareholders' Equity [Member] | Total Whiting Shareholders' Equity [Member] | Total Whiting Shareholders' Equity [Member] | Total Whiting Shareholders' Equity [Member] | Preferred Stock [Member] | Common Stock [Member] | Common Stock [Member] | Common Stock [Member] | Additional Paid-in Capital [Member] | Additional Paid-in Capital [Member] | Additional Paid-in Capital [Member] | Additional Paid-in Capital [Member] | Accumulated Other Comprehensive Income (Loss) [Member] | Retained Earnings [Member] | Noncontrolling Interest [Member] | Restricted Stock Units (RSUs) [Member] | Stock Option [Member] | Common Stock [Member] | Total |
In Thousands, except Share data, unless otherwise specified | Restricted Stock Units (RSUs) [Member] | Stock Option [Member] | Common Stock [Member] | USD ($) | Restricted Stock Units (RSUs) [Member] | USD ($) | USD ($) | Restricted Stock Units (RSUs) [Member] | Stock Option [Member] | Common Stock [Member] | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | |
USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | ||||||||||||||
BALANCES at Dec. 31, 2011 | $3,020,857 | $118 | $1,554,223 | $240 | $1,466,276 | $8,274 | $3,029,131 | ||||||||||||
BALANCES (in shares) at Dec. 31, 2011 | 172,000 | 118,105,000 | |||||||||||||||||
Increase (Decrease) in Shareholders' Equity | |||||||||||||||||||
Net income (loss) | 414,189 | 414,189 | -90 | 414,099 | |||||||||||||||
Other comprehensive income | -1,476 | -1,476 | -1,476 | ||||||||||||||||
Restricted stock issued | 1 | -1 | |||||||||||||||||
Restricted stock issued (in shares) | 592,000 | ||||||||||||||||||
Restricted stock forfeited (in shares) | -9,000 | ||||||||||||||||||
Restricted stock used for tax withholdings | -5,695 | -5,695 | -5,695 | ||||||||||||||||
Restricted stock used for tax withholdings (in shares) | -106,000 | ||||||||||||||||||
Stock-based compensation | 18,190 | 18,190 | 18,190 | ||||||||||||||||
Preferred dividends paid | -1,077 | -1,077 | -1,077 | ||||||||||||||||
BALANCES at Dec. 31, 2012 | 3,444,988 | 119 | 1,566,717 | -1,236 | 1,879,388 | 8,184 | 3,453,172 | ||||||||||||
BALANCES (in shares) at Dec. 31, 2012 | 172,000 | 118,582,000 | |||||||||||||||||
Increase (Decrease) in Shareholders' Equity | |||||||||||||||||||
Net income (loss) | 366,055 | 366,055 | -52 | 366,003 | |||||||||||||||
Other comprehensive income | 1,236 | 1,236 | 1,236 | ||||||||||||||||
Conversion of preferred stock to common | 1 | 1 | 1 | ||||||||||||||||
Conversion of preferred stock to common (in shares) | -172,000 | 794,000 | |||||||||||||||||
Restricted stock issued (in shares) | 941,000 | ||||||||||||||||||
Restricted stock forfeited (in shares) | -100,000 | ||||||||||||||||||
Restricted stock used for tax withholdings | -5,611 | -5,611 | -5,611 | ||||||||||||||||
Restricted stock used for tax withholdings (in shares) | -115,000 | ||||||||||||||||||
Stock-based compensation | 22,436 | 22,436 | 22,436 | ||||||||||||||||
Preferred dividends paid | -538 | -538 | -538 | ||||||||||||||||
BALANCES at Dec. 31, 2013 | 3,828,567 | 120 | 1,583,542 | 2,244,905 | 8,132 | 3,836,699 | |||||||||||||
BALANCES (in shares) at Dec. 31, 2013 | 120,102,000 | ||||||||||||||||||
Increase (Decrease) in Shareholders' Equity | |||||||||||||||||||
Net income (loss) | 64,807 | 64,807 | -62 | 64,745 | |||||||||||||||
Equity issued for Kodiak Acquisition | 9,596 | 7,523 | 1,771,094 | 48 | 9,596 | 7,523 | 1,771,046 | 9,596 | 7,523 | 1,771,094 | |||||||||
Equity issued for Kodiak Acquisition (in shares) | 258,000 | 47,546,000 | 673,235 | ||||||||||||||||
Exercise of stock options | 1,781 | 1,781 | 1,781 | ||||||||||||||||
Exercise of stock options (in shares) | 117,000 | 117,123 | |||||||||||||||||
Restricted stock issued (in shares) | 908,000 | ||||||||||||||||||
Restricted stock forfeited (in shares) | -386,000 | ||||||||||||||||||
Restricted stock used for tax withholdings | -11,652 | -11,652 | -11,652 | ||||||||||||||||
Restricted stock used for tax withholdings (in shares) | -199,000 | ||||||||||||||||||
Stock-based compensation | 23,258 | 23,258 | 23,258 | ||||||||||||||||
BALANCES at Dec. 31, 2014 | $5,694,974 | $168 | $3,385,094 | $2,309,712 | $8,070 | $5,703,044 | |||||||||||||
BALANCES (in shares) at Dec. 31, 2014 | 168,346,000 |
SUMMARY_OF_SIGNIFICANT_ACCOUNT
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended | ||||||
Dec. 31, 2014 | |||||||
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES [Abstract] | |||||||
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | WHITING PETROLEUM CORPORATION | ||||||
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS | |||||||
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | |||||||
Description of Operations—Whiting Petroleum Corporation, a Delaware corporation, is an independent oil and gas company that explores for, develops, acquires and produces crude oil, NGLs and natural gas primarily in the Rocky Mountains and Permian Basin regions of the United States. Unless otherwise specified or the context otherwise requires, all references in these notes to “Whiting” or the “Company” are to Whiting Petroleum Corporation and its consolidated subsidiaries. | |||||||
Basis of Presentation of Consolidated Financial Statements—The consolidated financial statements include the accounts of Whiting Petroleum Corporation, its consolidated subsidiaries and Whiting’s pro rata share of the accounts of Whiting USA Trust I (“Trust I”) pursuant to Whiting’s 15.8% ownership interest in Trust I. Investments in entities which give Whiting significant influence, but not control, over the investee are accounted for using the equity method. Under the equity method, investments are stated at cost plus the Company’s equity in undistributed earnings and losses. All intercompany balances and transactions have been eliminated upon consolidation. | |||||||
Use of Estimates—The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Items subject to such estimates and assumptions include (1) oil and natural gas reserves; (2) cash flow estimates used in impairment tests of long-lived assets; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations, including the determination of any resulting goodwill; (6) income taxes; (7) accrued liabilities; (8) valuation of derivative instruments; and (9) accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ from these estimates. | |||||||
Cash and Cash Equivalents—Cash equivalents consist of demand deposits and highly liquid investments which have an original maturity of three months or less. | |||||||
Accounts Receivable Trade—Whiting’s accounts receivable trade consist mainly of receivables from oil and gas purchasers and joint interest owners on properties the Company operates. For receivables from joint interest owners, Whiting typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Generally, the Company’s oil and gas receivables are collected within two months, and to date, the Company has had minimal bad debts. | |||||||
The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectability. At December 31, 2014 and 2013, the Company had an allowance for doubtful accounts of $9 million and $4 million, respectively. | |||||||
Inventories—Materials and supplies inventories consist primarily of tubular goods and production equipment, carried at weighted-average cost. Materials and supplies are included in other property and equipment. Crude oil in tanks inventory is carried at the lower of the estimated cost to produce or market value and is included in prepaid expenses and other. | |||||||
Oil and Gas Properties | |||||||
Proved. The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method of accounting, all property acquisition costs and development costs are capitalized when incurred and depleted on a units-of-production basis over the remaining life of proved reserves and proved developed reserves, respectively. Costs of drilling exploratory wells are initially capitalized but are charged to expense if the well is determined to be unsuccessful. | |||||||
The Company assesses its proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable. The impairment test compares undiscounted future net cash flows to the assets’ net book value. If the net capitalized costs exceed future net cash flows, then the cost of the property is written down to fair value. Fair value for oil and gas properties is generally determined based on discounted future net cash flows. Impairment expense for proved properties is reported in exploration and impairment expense. | |||||||
Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable property are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in income. Gains or losses from the disposal of complete units of depreciable property are recognized to earnings. | |||||||
Interest cost is capitalized as a component of property cost for development projects that require greater than six months to be readied for their intended use. During 2014, 2013 and 2012, the Company capitalized interest of $4 million, $2 million and $3 million, respectively. | |||||||
Unproved. Unproved properties consist of costs to acquire undeveloped leases as well as purchases of unproved reserves. Undeveloped lease costs and unproved reserve acquisitions are capitalized, and individually insignificant unproved properties are amortized on a composite basis, based on past success, past experience and average lease-term lives. The Company evaluates significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. When successful wells are drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit-of-production basis. Impairment expense for unproved properties is reported in exploration and impairment expense. | |||||||
Exploratory. Geological and geophysical costs, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage 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. Amounts of seismic costs capitalized are based on only those blocks of data used in determining development well locations. To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense. | |||||||
Costs of drilling exploratory wells are initially capitalized, pending determination of whether the well has found proved reserves. If an exploratory well has not found proved reserves, the costs of drilling the well and other associated costs are charged to expense. Cost incurred for exploratory wells that find reserves, which cannot yet be classified as proved, continue to be capitalized if (a) the well has found a sufficient quantity of reserves to justify completion as a producing well, and (b) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not met, or if the Company obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well costs, net of any salvage value, are expensed. | |||||||
Enhanced recovery activities. The Company carries out tertiary recovery methods on certain of its oil and gas properties in order to recover additional hydrocarbons that are not recoverable from primary or secondary recovery methods. Acquisition costs of tertiary injectants, such as purchased CO2, for EOR activities that are used during a project’s pilot phase, or prior to a project’s technical and economic viability (i.e. prior to the recognition of proved tertiary recovery reserves) are expensed as incurred. After a project has been determined to be technically feasible and economically viable, all acquisition costs of tertiary injectants are capitalized as development costs and depleted, as they are incurred solely for obtaining access to reserves not otherwise recoverable and have future economic benefits over the life of the project. As CO2 is recovered together with oil and gas production, it is extracted and re-injected, and all the associated CO2 recycling costs are expensed as incurred. Likewise costs incurred to maintain reservoir pressure are also expensed. | |||||||
Other Property and Equipment—Other property and equipment consists of (i) materials and supplies inventories, (ii) leasehold costs and development costs of our CO2 source properties and (iii) other property and equipment including, furniture and fixtures, buildings, leasehold improvements and automobiles, which are stated at cost and depreciated using the straight-line method over their estimated useful lives ranging from 4 to 30 years. | |||||||
Goodwill—Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in a business combination. Goodwill has an indefinite useful life and is not amortized, but rather is tested by the Company for impairment annually in the second quarter or when events or changes in circumstances indicate that the fair value of a reporting unit has been reduced below its carrying value. If the Company’s qualitative analysis indicates that it is more likely than not that the fair value of the reporting unit is less than its carrying value, the Company then performs a quantitative impairment test. If the carrying value of the reporting unit exceeds its fair value, goodwill is written down to its implied fair value with an offsetting charge to earnings. | |||||||
Debt Issuance Costs—Debt issuance costs related to the Company’s Senior Notes and Senior Subordinated Notes are amortized to interest expense using the effective interest method over the term of the related debt. Debt issuance costs related to the credit facility are amortized to interest expense on a straight-line basis over the borrowing term. | |||||||
Derivative Instruments—The Company enters into derivative contracts, primarily costless collars and swap contracts, to manage its exposure to commodity price risk. All derivative instruments, other than those that meet the “normal purchase normal sale” exclusion, are recorded on the balance sheet as either an asset or liability measured at fair value. Gains and losses from changes in the fair value of derivative instruments are recognized immediately in earnings, unless the derivative meets specific hedge accounting criteria, and the derivative has been designated as a hedge. Effective April 1, 2009, however, the Company elected to discontinue all hedge accounting prospectively, and as of December 31, 2013, all amounts related to de-designated cash flow hedges had been reclassified into earnings. | |||||||
Cash flows from derivatives used to manage commodity price risk are classified in operating activities along with the cash flows of the underlying hedged transactions. The Company does not enter into derivative instruments for speculative or trading purposes. | |||||||
Asset Retirement Obligations and Environmental Costs—Asset retirement obligations relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred (typically when a well is completed or acquired or an asset is installed at the production location), and the cost of such liability increases the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period through charges to depreciation, depletion and amortization expense, and the capitalized cost is depleted on a units-of-production basis over the proved developed reserves of the related asset. Revisions to estimated retirement obligations result in adjustments to the related capitalized asset and corresponding liability. | |||||||
Liabilities for environmental costs are recorded on an undiscounted basis when it is probable that obligations have been incurred and the amounts can be reasonably estimated. These liabilities are not reduced by possible recoveries from third parties. | |||||||
Deferred Gain on Sale—The deferred gain on sale relates to the sale of 11,677,500 Trust I units and 18,400,000 Whiting USA Trust II (“Trust II”) units, and is amortized to income based on the units-of-production method. | |||||||
Revenue Recognition—Oil and gas revenues are recognized when production volumes are sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, persuasive evidence of a sales arrangement exists and collectability of the revenue is probable. Revenues from the production of gas properties in which the Company has an interest with other producers are recognized on the basis of the Company’s net working interest (entitlement method). Net deliveries in excess of entitled amounts are recorded as liabilities, while net under deliveries are reflected as receivables. The Company’s aggregate imbalance positions as of December 31, 2014 and 2013 were not significant. | |||||||
Taxes collected and remitted to governmental agencies on behalf of customers are not included in revenues or costs and expenses. | |||||||
General and Administrative Expenses—General and administrative expenses are reported net of reimbursements of overhead costs that are allocated to working interest owners which participate in oil and gas properties operated by Whiting. | |||||||
Acquisition Costs—Acquisition related expenses, which consist of external costs directly related to the Company’s acquisitions, such as advisory, legal, accounting, valuation and other professional fees, are expensed as incurred. | |||||||
Maintenance and Repairs—Maintenance and repair costs which do not extend the useful lives of property and equipment are charged to expense as incurred. Major replacements, renewals and betterments are capitalized. | |||||||
Income Taxes—Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are accounted for using the liability method. Under this method, deferred tax assets and liabilities are determined by applying the enacted statutory tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the Company’s financial statements. 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 established when it is more likely than not that some portion of the benefit from deferred tax assets will not be realized. The Company’s uncertain tax positions must meet a more-likely-than-not realization threshold to be recognized, and any potential accrued interest and penalties related to unrecognized tax benefits are recognized within income tax expense. | |||||||
Earnings Per Share—Basic earnings per common share is calculated by dividing net income available to common shareholders by the weighted average number of common shares outstanding during each period. Diluted earnings per common share is calculated by dividing adjusted net income available to common shareholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the diluted earnings per share calculations consist of unvested restricted stock awards and outstanding stock options using the treasury method, as well as convertible perpetual preferred stock using the if-converted method. In the computation of diluted earnings per share, excess tax benefits that would be created upon the assumed vesting of unvested restricted shares or the assumed exercise of stock options (i.e. hypothetical excess tax benefits) are included in the assumed proceeds component of the treasury share method to the extent that such excess tax benefits are more likely than not to be realized. When a loss from continuing operations exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. | |||||||
Industry Segment and Geographic Information—The Company has evaluated how it is organized and managed and has identified only one operating segment, which is the exploration and production of crude oil, NGLs and natural gas. The Company considers its gathering, processing and marketing functions as ancillary to its oil and gas producing activities. All of the Company’s operations and assets are located in the United States, and substantially all of its revenues are attributable to United States customers. | |||||||
Concentration of Credit Risk—Whiting is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy related industries. The creditworthiness of customers and other counterparties is subject to continuing review. The following table presents the percentages by purchaser that accounted for 10% or more of the Company’s total oil, NGL and natural gas sales for the years ended December 31, 2014, 2013 and 2012: | |||||||
2014 | 2013 | 2012 | |||||
Plains Marketing LP | 17% | 21% | 20% | ||||
Shell Trading US | 10% | 14% | 14% | ||||
Bridger Trading LLC | 10% | 8% | 11% | ||||
Eighty Eight Oil Company | 6% | 11% | 11% | ||||
Commodity derivative contracts held by the Company are with seven counterparties, all of which are participants in Whiting’s credit facility as well, and all of which have investment-grade ratings from Moody’s and Standard & Poor. As of December 31, 2014, outstanding derivative contracts with Wells Fargo Bank, N.A., JP Morgan Chase Bank, N.A. and Canadian Imperial Bank of Commerce represented 34%, 28% and 13%, respectively, of total crude oil volumes hedged. | |||||||
Reclassifications—Certain prior period balances in the consolidated balance sheets have been reclassified to conform to the current year presentation. Such reclassifications had no impact on net income, cash flows or shareholders’ equity previously reported. | |||||||
Adopted and Recently Issued Accounting Pronouncements—In February 2013, the FASB issued Accounting Standards Update No. 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“ASU 2013-04”). The objective of ASU 2013-04 is to provide guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date. ASU 2013-04 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The Company adopted ASU 2013-04 effective January 1, 2014, which did not have an impact on the Company’s consolidated financial statements. | |||||||
In July 2013, the FASB issued Accounting Standards Update No. 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (“ASU 2013-11”). The objective of ASU 2013-11 is to provide guidance on financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. ASU 2013-11 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The Company adopted ASU 2013-11 effective January 1, 2014, which did not have an impact on the Company’s consolidated financial statements, other than insignificant balance sheet reclassifications. | |||||||
In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014‑09”). The objective of ASU 2014-09 is to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards. ASU 2014‑09 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. The Company is currently evaluating the impact of adopting ASU 2014‑09, but the standard is not expected to have a significant effect on its consolidated financial statements. | |||||||
In August 2014, the FASB issued Accounting Standards Update No. 2014-15, Presentation of Financial Statements – Going Concern (“ASU 2014-15”). The objective of ASU 2014-15 is to provide guidance on management’s responsibility to evaluate whether there is substantial doubt about a company’s ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for fiscal years ending after December 15, 2016, and annual and interim periods thereafter. This standard is not expected to have an impact on the Company’s consolidated financial statements. | |||||||
OIL_AND_GAS_PROPERTIES
OIL AND GAS PROPERTIES | 12 Months Ended | ||||||
Dec. 31, 2014 | |||||||
OIL AND GAS PROPERTIES [Abstract] | |||||||
OIL AND GAS PROPERTIES | 2. OIL AND GAS PROPERTIES | ||||||
Net capitalized costs related to the Company’s oil and gas producing activities at December 31, 2014 and 2013 are as follows (in thousands): | |||||||
December 31, | |||||||
2014 | 2013 | ||||||
Proved leasehold costs | $ | 3,637,026 | $ | 1,633,495 | |||
Unproved leasehold costs | 1,232,040 | 372,298 | |||||
Costs of completed wells and facilities | 9,319,808 | 7,563,350 | |||||
Wells and facilities in progress | 760,828 | 496,007 | |||||
Total oil and gas properties, successful efforts method | 14,949,702 | 10,065,150 | |||||
Accumulated depletion | -3,003,270 | -2,645,841 | |||||
Oil and gas properties, net | $ | 11,946,432 | $ | 7,419,309 | |||
ACQUISITIONS_AND_DIVESTITURES
ACQUISITIONS AND DIVESTITURES | 12 Months Ended | ||||||
Dec. 31, 2014 | |||||||
ACQUISITIONS AND DIVESTITURES [Abstract] | |||||||
ACQUISITIONS AND DIVESTITURES | 3. ACQUISITIONS AND DIVESTITURES | ||||||
2014 Acquisitions | |||||||
On December 8, 2014, the Company completed the acquisition of Kodiak Oil & Gas Corp. (now known as Whiting Canadian Holding Company ULC, “Kodiak”), whereby Whiting acquired all of the outstanding common stock of Kodiak (the “Kodiak Acquisition”). Pursuant to the terms of the Kodiak Acquisition agreement, Kodiak shareholders received 0.177 of a share of Whiting common stock in exchange for each share of Kodiak common stock they owned. Total consideration for the Kodiak Acquisition was $1.8 billion, consisting of 47,546,139 Whiting common shares issued at the market price of $37.25 per share on the date of issuance plus the fair value of Kodiak’s outstanding equity awards assumed by Whiting. The aggregate purchase price of the transaction was $4.3 billion, which includes the assumption of Kodiak’s outstanding debt of $2.5 billion as of December 8, 2014 and the net cash acquired of $19 million. | |||||||
Kodiak was an independent energy company focused on exploration and production of crude oil and natural gas reserves, primarily in the Williston Basin region of the United States. As a result of the Kodiak Acquisition, Whiting acquired approximately 327,000 gross (178,000 net) acres located primarily in North Dakota, including interests in 778 producing oil and gas wells and undeveloped acreage. Approximately 10,000 of the net acres acquired were located in Wyoming and Colorado. | |||||||
The acquisition significantly expanded the Company’s presence in the Williston Basin, adding undeveloped acreage, oil and natural gas reserves and production that were complementary to its existing asset base and operations in this area. As a result of this acquisition, Whiting became the largest Bakken/Three Forks producer in the Williston Basin as of the acquisition date. | |||||||
The Kodiak Acquisition was accounted for using the acquisition method of accounting for business combinations. The allocation of the preliminary estimated purchase price is based upon management’s estimates and assumptions related to the fair value of assets acquired and liabilities assumed on the acquisition date using currently available information. Transaction costs relating to the Kodiak Acquisition were expensed as incurred. The initial accounting for the Kodiak Acquisition is preliminary, and adjustments to provisional amounts (such as goodwill, certain accrued liabilities and their related deferred taxes), or recognition of additional assets acquired or liabilities assumed, may occur as additional information is obtained about facts and circumstances that existed as of the acquisition date. | |||||||
The preliminary consideration transferred, fair value of assets acquired and liabilities assumed, and the resulting goodwill as of the acquisition date are as follows (in thousands): | |||||||
Consideration: | |||||||
Fair value of Whiting’s common stock issued (1) | $ | 1,771,094 | |||||
Fair value of Kodiak restricted stock units assumed by Whiting (2) | 9,596 | ||||||
Fair value of Kodiak options assumed by Whiting | 7,523 | ||||||
Total consideration | $ | 1,788,213 | |||||
Fair value of liabilities assumed: | |||||||
Accounts payable trade | $ | 18,390 | |||||
Accrued capital expenditures | 104,509 | ||||||
Revenues and royalties payable | 57,423 | ||||||
Accrued liabilities and other | 45,695 | ||||||
Taxes payable | 12,676 | ||||||
Accrued interest | 18,070 | ||||||
Current deferred tax liability | 30,279 | ||||||
Long-term debt | 2,500,875 | ||||||
Asset retirement obligations | 8,646 | ||||||
Other long-term liabilities | 15,735 | ||||||
Amount attributable to liabilities assumed | $ | 2,812,298 | |||||
Fair value of assets acquired: | |||||||
Cash and cash equivalents | $ | 18,879 | |||||
Accounts receivable trade, net | 219,654 | ||||||
Derivative assets | 85,718 | ||||||
Prepaid expenses and other | 8,624 | ||||||
Oil and gas properties, successful efforts method: | |||||||
Proved properties | 2,266,607 | ||||||
Unproved properties | 1,000,396 | ||||||
Other property and equipment | 11,347 | ||||||
Long-term deferred tax asset | 107,497 | ||||||
Other long-term assets | 6,113 | ||||||
Amount attributable to assets acquired | $ | 3,724,835 | |||||
Goodwill | $ | 875,676 | |||||
_____________________ | |||||||
-1 | 47,546,139 shares of Whiting common stock at $37.25 per share (closing price as of December 5, 2014), based on Kodiak’s 268,622,497 common shares outstanding at closing. | ||||||
-2 | 257,601 shares of Whiting common stock issued at $37.25 per share (closing price as of December 5, 2014), based on Kodiak’s 1,455,409 restricted stock units held by employees as of December 8, 2014. | ||||||
Goodwill recognized as a result of the Kodiak Acquisition totaled $876 million, none of which is deductible for income tax purposes. Goodwill is primarily attributable to the operational and financial synergies expected to be realized from the acquisition, including employing optimized completion techniques on Kodiak's undrilled acreage which will improve hydrocarbon recovery, realized savings in drilling and well completion costs, the accelerated development of Kodiak’s asset base, and the acquisition of experienced oil and gas technical personnel. | |||||||
The results of operations of Kodiak from the December 8, 2014 closing date through December 31, 2014, representing approximately $46 million of revenue and $17 million of net income, have been included in Whiting’s consolidated statements of income for the year ended December 31, 2014. | |||||||
2014 Divestitures | |||||||
On March 27, 2014, the Company completed the sale of approximately 49,900 gross (41,000 net) acres in its Big Tex prospect, which consisted mainly of undeveloped acreage as well as its interests in certain producing oil and gas wells, located in the Delaware Basin of Texas for a cash purchase price of $76 million resulting in a pre-tax gain on sale of $12 million. | |||||||
2013 Acquisitions | |||||||
On September 20, 2013, the Company completed the acquisition of approximately 39,300 gross (17,300 net) acres in the Williston Basin, including interests in 121 producing oil and gas wells and undeveloped acreage, located in Williams and McKenzie counties of North Dakota and Roosevelt and Richland counties of Montana for an initial purchase price of $261 million. Revenue and earnings from these properties since the September 20, 2013 acquisition date are not material, and disclosures of pro forma revenues and net income for this acquisition of these wells are also not material and have not been presented accordingly. | |||||||
The acquisition was recorded using the purchase method of accounting. The initial purchase price has been adjusted for post-closing settlements that have occurred since the acquisition date totaling $6 million. The following table summarizes the allocation of the $256 million adjusted purchase price to the tangible assets acquired and liabilities assumed in this acquisition of oil and gas properties (in thousands): | |||||||
Purchase price | $ | 255,537 | |||||
Allocation of purchase price: | |||||||
Oil and gas properties, successful efforts method: | |||||||
Proved properties | $ | 229,002 | |||||
Unproved properties | 27,335 | ||||||
Oil in tank inventory | 522 | ||||||
Accounts receivable | 578 | ||||||
Asset retirement obligations | -1,900 | ||||||
Total | $ | 255,537 | |||||
2013 Divestitures | |||||||
On October 31, 2013, the Company completed the sale of approximately 45,000 gross (32,200 net) acres in its Big Tex prospect, which consisted mainly of undeveloped acreage as well as its interests in certain producing oil and gas wells, located in the Delaware Basin of Texas for a cash purchase price of $151 million, resulting in a pre-tax gain on sale of $11 million. Of the total net acres sold, approximately 30,800 net acres are located in Pecos County, Texas, and approximately 1,400 net acres are located in Reeves County, Texas. | |||||||
On July 15, 2013, the Company completed the sale of its interests in certain oil and gas producing properties located in its EOR projects in the Postle and Northeast Hardesty fields in Texas County, Oklahoma, including the related Dry Trail plant gathering and processing facility, oil delivery pipeline, its entire 60% interest in the Transpetco CO2 pipeline, crude oil swap contracts and certain other related assets and liabilities (collectively the “Postle Properties”) for a cash purchase price of $809 million after selling costs and post-closing adjustments. This divestiture resulted in a pre-tax gain on sale of $109 million. The Company used the net proceeds from this sale to repay a portion of the debt outstanding under its credit agreement. | |||||||
2012 Acquisitions | |||||||
There were no significant acquisitions during the year ended December 31, 2012. | |||||||
2012 Divestitures | |||||||
On May 18, 2012, the Company sold a 50% ownership interest in its Belfield gas processing plant, natural gas gathering system, oil gathering system and related facilities located in Stark County, North Dakota for total cash proceeds of $66 million. Whiting used the net proceeds from the sale to repay a portion of the debt outstanding under its credit agreement. | |||||||
On March 28, 2012, the Company completed an initial public offering of units of beneficial interest in Trust II, selling 18,400,000 Trust II units at $20.00 per unit, which generated net proceeds of $322 million after underwriters’ fees, offering expenses and post-close adjustments. The Company used the net offering proceeds to repay a portion of the debt outstanding under its credit agreement. The net proceeds from the sale of Trust II units to the public resulted in a deferred gain on sale of $128 million. Immediately prior to the closing of the offering, Whiting conveyed a term net profits interest in certain of its oil and gas properties to Trust II in exchange for 100% of the trust’s units issued, or 18,400,000 units. | |||||||
The net profits interest entitles Trust II to receive 90% of the net proceeds from the sale of oil and natural gas production from the underlying properties. The net profits interest will terminate on the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and sold. This is the equivalent of 10.61 MMBOE in respect of Trust II’s right to receive 90% of the net proceeds from such reserves pursuant to the net profits interest. | |||||||
Unaudited Pro Forma Operating Results | |||||||
The following unaudited pro forma combined results of operations for the years ended December 31, 2014 and 2013 are derived from the historical consolidated financial statements of Whiting and Kodiak and give effect to the Kodiak Acquisition as if it had occurred on January 1, 2013. | |||||||
December 31, | |||||||
2014 | 2013 | ||||||
(in thousands, except per share data) | |||||||
Total revenues | $ | 4,141,046 | $ | 3,774,137 | |||
Net income available to common shareholders | $ | 362,376 | $ | 576,450 | |||
Earnings per common share: | |||||||
Basic | $ | 2.18 | $ | 3.48 | |||
Diluted | $ | 2.17 | $ | 3.46 | |||
The unaudited pro forma combined results of operations reflect pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including (i) Whiting common stock and equity awards issued to convert Kodiak’s outstanding shares of common stock and equity awards as of the closing date of the transaction, (ii) adjustments to conform Kodiak’s historical policy of accounting for its oil and natural gas properties from the full cost method to the successful efforts method of accounting, (iii) depletion of Kodiak’s fair-valued proved oil and gas properties, (iv) adjustments to interest expense to reflect the assumption of Kodiak’s debt by Whiting, and (v) the estimated tax impacts of the pro forma adjustments. Additionally, pro forma earnings for the year ended December 31, 2014 were adjusted to exclude $86 million of acquisition-related costs incurred by Whiting and Kodiak, and the pro forma earnings for the year ended December 31, 2013 were adjusted to include these charges. | |||||||
The unaudited pro forma financial information has been prepared for informational purposes only and does not purport to represent what Whiting’s results of operations would have been had the transactions actually been consummated on the assumed dates nor are they indicative of future results of operations. The unaudited pro forma combined financial information does not reflect future events that may occur after the transactions including, but not limited to, the anticipated realization of ongoing savings from operating efficiencies from the Kodiak Acquisition. | |||||||
LONGTERM_DEBT
LONG-TERM DEBT | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
LONG-TERM DEBT [Abstract] | ||||||||||||||||
LONG-TERM DEBT | 4. LONG-TERM DEBT | |||||||||||||||
Long-term debt consisted of the following at December 31, 2014 and 2013 (in thousands): | ||||||||||||||||
December 31, | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Credit agreement | $ | 1,400,000 | $ | - | ||||||||||||
6.5% Senior Subordinated Notes due 2018 | 350,000 | 350,000 | ||||||||||||||
5% Senior Notes due 2019 | 1,100,000 | 1,100,000 | ||||||||||||||
8.125% Senior Notes due 2019, including unamortized debt premium of $23,742 | 823,742 | - | ||||||||||||||
5.75% Senior Notes due 2021, including unamortized debt premium of $3,180 and $3,834, respectively | 1,203,180 | 1,203,834 | ||||||||||||||
5.5% Senior Notes due 2021, including unamortized debt premium of $867 | 350,867 | - | ||||||||||||||
5.5% Senior Notes due 2022, including unamortized debt premium of $993 | 400,993 | - | ||||||||||||||
Total debt | $ | 5,628,782 | $ | 2,653,834 | ||||||||||||
The following table shows five succeeding fiscal years of scheduled maturities for the Company’s long-term debt as of December 31, 2014 (in thousands): | ||||||||||||||||
2015 | 2016 | 2017 | 2018 | 2019 | ||||||||||||
Long-term debt (1) | $ | - | $ | - | $ | - | $ | 350,000 | $ | 3,300,000 | ||||||
_____________________ | ||||||||||||||||
-1 | Refer to “Kodiak Senior Notes Repurchase Offer” below for more information. | |||||||||||||||
Credit Agreement—In August 2014, Whiting Oil and Gas Corporation (“Whiting Oil and Gas”), the Company’s wholly-owned subsidiary, entered into a Sixth Amended and Restated Credit Agreement with a syndicate of banks, which replaced its existing credit agreement upon closing of the Kodiak Acquisition on December 8, 2014. This amended credit agreement increased the borrowing base under Whiting Oil and Gas’ credit facility to $4.5 billion, with aggregate commitments of $3.5 billion. Subsequently in December 2014, the lenders under the credit agreement increased their aggregate commitments under this amended agreement from $3.5 billion to $4.5 billion, of which $3.5 billion relates to commitments to extend revolving credit and $1.0 billion relates to a senior secured delayed draw term loan facility (“Delayed Draw Facility”). The Delayed Draw Facility may be used to provide cash consideration for any repurchase or redemption of Kodiak’s outstanding senior notes in connection with the Kodiak Acquisition, to pay transaction costs and for other corporate purposes. Under the amended credit agreement, the revolving credit facility will mature on December 8, 2019, and the Delayed Draw Facility will mature on December 31, 2015. As of December 31, 2014, the Company had $3.1 billion of available borrowing capacity, which was net of $1.4 billion in borrowings and $3 million in letters of credit outstanding. | ||||||||||||||||
The borrowing base under the credit agreement is determined at the discretion of the lenders, based on the collateral value of the Company’s proved reserves that have been mortgaged to such lenders, and is subject to regular redeterminations on May 1 and November 1 of each year, as well as special redeterminations described in the credit agreement, in each case which may reduce the amount of the borrowing base. Upon a redetermination of our borrowing base, either on a periodic or special redetermination date, if borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to immediately repay a portion of our debt outstanding under the credit agreement. A portion of the revolving credit facility in an aggregate amount not to exceed $100 million may be used to issue letters of credit for the account of Whiting Oil and Gas or other designated subsidiaries of the Company. As of December 31, 2014, $97 million was available for additional letters of credit under the agreement. | ||||||||||||||||
The credit agreement provides for interest only payments until the expiration date of the agreement, when all outstanding borrowings are due. Interest under the revolving credit facility accrues at the Company’s option at either (i) a base rate for a base rate loan plus the margin in the table below, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.5% per annum, or an adjusted LIBOR rate plus 1.0% per annum, or (ii) an adjusted LIBOR rate for a Eurodollar loan plus the margin in the table below. Additionally, the Company also incurs commitment fees as set forth in the table below on the unused portion of the aggregate commitments of the lenders under the revolving credit facility, which are included as a component of interest expense. At December 31, 2014, the entire $1.4 billion outstanding principal balance under the credit agreement was under the revolving credit facility with a weighted average interest rate of 1.9%. | ||||||||||||||||
Applicable | Applicable | |||||||||||||||
Margin for Base | Margin for | Commitment | ||||||||||||||
Ratio of Outstanding Borrowings to Borrowing Base | Rate Loans | Eurodollar Loans | Fee | |||||||||||||
Less than 0.25 to 1.0 | 0.50% | 1.50% | 0.38% | |||||||||||||
Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0 | 0.75% | 1.75% | 0.38% | |||||||||||||
Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0 | 1.00% | 2.00% | 0.50% | |||||||||||||
Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0 | 1.25% | 2.25% | 0.50% | |||||||||||||
Greater than or equal to 0.90 to 1.0 | 1.50% | 2.50% | 0.50% | |||||||||||||
Interest under the Delayed Draw Facility accrues at the Company’s option at either (i) a base rate for a base rate loan plus (A) 1.00% per annum through March 8, 2015 and (B) 1.50% per annum from March 9, 2015 through the December 31, 2015 maturity date, or (ii) an adjusted LIBOR rate for a Eurodollar loan plus (A) 2.00% per annum through March 8, 2015 and (B) 2.50% per annum from March 9, 2015 through the December 31, 2015 maturity date. We also incur commitment fees of 0.25% on the unused portion of the aggregate commitments of the lenders under the Delayed Draw Facility. | ||||||||||||||||
The amended credit agreement contains restrictive covenants that may limit the Company’s ability to, among other things, incur additional indebtedness, sell assets, make loans to others, make investments, enter into mergers, enter into hedging contracts, incur liens and engage in certain other transactions without the prior consent of its lenders. Except for limited exceptions, the credit agreement also restricts the Company’s ability to make any dividend payments or distributions on its common stock. These restrictions apply to all of the net assets of the subsidiaries. As of December 31, 2014, total restricted net assets were $6.9 billion, and the amount of retained earnings free from restrictions was $24 million. The credit agreement requires the Company, as of the last day of any quarter, (i) to not exceed a total debt to the last four quarters’ EBITDAX ratio (as defined in the credit agreement) of 4.0 to 1.0 and (ii) to have a consolidated current assets to consolidated current liabilities ratio (as defined in the credit agreement and which includes an add back of the available borrowing capacity under the credit agreement) of not less than 1.0 to 1.0. The Company was in compliance with its covenants under the credit agreement as of December 31, 2014. | ||||||||||||||||
Under the terms of the credit agreement, at any time during which Whiting has an investment-grade debt rating from Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Group and Whiting has elected, at its discretion, to effect an investment-grade rating period, (i) certain security requirements, including the borrowing base requirement, and restrictive covenants will cease to apply, (ii) certain other restrictive covenants will become less restrictive, (iii) an additional financial covenant will be imposed, and (iv) the interest rate margin applicable to all revolving borrowings as well as the commitment fee with respect to the revolving facility will be based upon the Company’s debt rating rather than the ratio of outstanding borrowings to the borrowing base. | ||||||||||||||||
The obligations of Whiting Oil and Gas under the credit agreement are secured by a first lien on substantially all of Whiting Oil and Gas’ and Whiting Resource Corporation’s properties included in the borrowing base for the credit agreement. The Company has guaranteed the obligations of Whiting Oil and Gas under the credit agreement and has pledged the stock of its subsidiaries as security for its guarantee. | ||||||||||||||||
Senior Notes and Senior Subordinated Notes—In September 2010, the Company issued at par $350 million of 6.5% Senior Subordinated Notes due October 2018 (the “2018 Senior Subordinated Notes”). The estimated fair value of these notes was $345 million and $371 million as of December 31, 2014 and 2013, respectively, based on quoted market prices for these debt securities, and such fair value is therefore designated as Level 1 within the valuation hierarchy. | ||||||||||||||||
Issuance of Senior Notes. In September 2013, the Company issued at par $1.1 billion of 5% Senior Notes due March 2019 (the “2019 Senior Notes”) and $800 million of 5.75% Senior Notes due March 2021, and issued at 101% of par an additional $400 million of 5.75% Senior Notes due March 2021 (collectively, the “2021 Senior Notes” and together with the 2019 Senior Notes, the “Whiting Senior Notes”). The estimated fair value of the 2019 Senior Notes was $1.0 billion and $1.1 billion as of December 31, 2014 and 2013, respectively. The estimated fair value of the 2021 Senior Notes was $1.1 billion and $1.3 billion as of December 31, 2014 and 2013, respectively. These fair values are based on quoted market prices for these debt securities, and such fair values are therefore designated as Level 1 within the valuation hierarchy. | ||||||||||||||||
Redemption of Senior Subordinated Notes. In October 2013, the Company paid $254 million to redeem its entire $250 million aggregate principal amount of the 7% Senior Subordinated Notes due February 2014 (the “2014 Senior Subordinated Notes”) at a redemption price of 101.595%. Concurrent with this redemption, the Company paid all accrued and unpaid interest on the 2014 Senior Subordinated Notes up to but not including the redemption date. The Company financed the redemption of these notes with proceeds from the issuance of the Whiting Senior Notes, as discussed above. As a result of the redemption, Whiting recognized a $4 million loss on early extinguishment of debt, which primarily consisted of a cash charge of $4 million related to the redemption premium on the 2014 Senior Subordinated Notes. | ||||||||||||||||
Kodiak Senior Notes. In conjunction with the Kodiak Acquisition, Whiting US Holding Company, a wholly-owned subsidiary of the Company, became a co-issuer of Kodiak’s outstanding principal amount of $800 million of 8.125% Senior Notes due December 2019, $350 million of 5.5% Senior Notes due January 2021, and $400 million of 5.5% Senior Notes due February 2022 (the “Kodiak Notes”). The Kodiak Notes were recorded at their fair values of $824 million, $351 million and $401 million, respectively, on December 8, 2014, the closing date of the acquisition. The related premiums of $24 million, $1 million and $1 million, respectively, are being amortized to interest expense over the life of the related notes. As of December 31, 2014, the estimated fair value of the Kodiak Notes was $812 million, $351 million and $401 million, respectively, based on quoted market prices for these debt securities, and such fair value is therefore designated as Level 1 within the valuation hierarchy. | ||||||||||||||||
Upon closing of the Kodiak Acquisition, the indentures under which the Kodiak Notes were issued (the “Kodiak Indentures”) were amended to (i) modify certain covenants and restrictions, (ii) to provide for unconditional and irrevocable guarantees by Whiting Petroleum Corporation and Whiting Oil and Gas of the prompt payment, when due, of any amounts owed under the Kodiak Notes and the Kodiak Indentures, and (iii) to allow Whiting US Holding Company to become a co-issuer of the Kodiak Notes. Also in conjunction with the Kodiak Acquisition, in December 2014, each of the indentures governing the Company’s 2019 Senior Notes, 2021 Senior Notes and 2018 Senior Subordinated Notes were amended to include Whiting US Holding Company, Kodiak and Whiting Resources Corporation (formerly Kodiak Oil & Gas (USA) Inc.) as guarantors. Shortly after closing, the Kodiak Notes were deregistered in accordance with the Securities Exchange Act of 1934, and accordingly, the Company is exempt from the reporting requirements under Rule 3-10 of Regulation S-X of the SEC with respect to the Kodiak Notes. | ||||||||||||||||
Kodiak Senior Notes Repurchase Offer. On January 7, 2015, as required under the Kodiak Indentures upon a change in control of Kodiak, Whiting offered to repurchase at 101% of par all $1,550 million principal amount of Kodiak Notes outstanding. The repurchase offer expires on March 3, 2015. The Company expects to fund any payments due as a result of such repurchase offer with borrowings under its revolving credit facility. | ||||||||||||||||
The Whiting Senior Notes and Kodiak Notes are unsecured obligations of Whiting Petroleum Corporation and Whiting US Holding Company, respectively, and are subordinated to all of the Company’s secured indebtedness, which consists of Whiting Oil and Gas’ credit agreement. The 2018 Senior Subordinated Notes are also unsecured obligations of Whiting Petroleum Corporation and are subordinated to all of the Company’s senior debt, which currently consists of the Whiting Senior Notes, the Kodiak Notes and Whiting Oil and Gas’ credit agreement. | ||||||||||||||||
The Company’s obligations under the 2018 Senior Subordinated Notes and the Whiting Senior Notes are fully and unconditionally guaranteed by the Company’s wholly-owned subsidiaries, Whiting Oil and Gas, Whiting US Holding Company, Whiting Canadian Holding Company ULC and Whiting Resources Corporation (the “Guarantors”). Any subsidiaries other than these Guarantors are minor subsidiaries as defined by Rule 3-10(h)(6) of Regulation S‑X of the SEC. Whiting Petroleum Corporation has no assets or operations independent of this debt and its investments in its consolidated subsidiaries. | ||||||||||||||||
ASSET_RETIREMENT_OBLIGATIONS
ASSET RETIREMENT OBLIGATIONS | 12 Months Ended | ||||||
Dec. 31, 2014 | |||||||
ASSET RETIREMENT OBLIGATIONS [Abstract] | |||||||
ASSET RETIREMENT OBLIGATIONS | 5. ASSET RETIREMENT OBLIGATIONS | ||||||
The Company’s asset retirement obligations represent the present value of estimated future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage, and land restoration (including removal of certain onshore and offshore facilities in California) in accordance with applicable local, state and federal laws. The Company follows FASB ASC Topic 410, Asset Retirement and Environmental Obligations, to determine its asset retirement obligation amounts by calculating the present value of the estimated future cash outflows associated with its plug and abandonment obligations. The current portions at December 31, 2014 and 2013 were $12 million and $10 million, respectively, and have been included in accrued liabilities and other. Revisions to the liability typically occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells. The following table provides a reconciliation of the Company’s asset retirement obligations for the years ended December 31, 2014 and 2013 (in thousands): | |||||||
December 31, | |||||||
2014 | 2013 | ||||||
Asset retirement obligation at January 1 | $ | 126,148 | $ | 97,818 | |||
Additional liability incurred | 29,186 | 17,535 | |||||
Revisions in estimated cash flows (1) | 25,909 | 12,225 | |||||
Accretion expense | 13,548 | 10,608 | |||||
Obligations on sold properties | -7,237 | -3,630 | |||||
Liabilities settled | -7,623 | -8,408 | |||||
Asset retirement obligation at December 31 | $ | 179,931 | $ | 126,148 | |||
_____________________ | |||||||
-1 | Revisions in estimated cash flows during the year ended December 31, 2014 are primarily attributable to increased estimates of future costs for oilfield goods and services required to plug and abandon wells in certain fields in the Rocky Mountains and Permian Basin regions. Revisions in estimated cash flows during the year ended December 31, 2013 were primarily attributable to increased estimates of futures costs for oilfield goods and services required to plug and abandon wells in certain fields in the Rocky Mountains region. | ||||||
DERIVATIVE_FINANCIAL_INSTRUMEN
DERIVATIVE FINANCIAL INSTRUMENTS | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
DERIVATIVE FINANCIAL INSTRUMENTS [Abstract] | ||||||||||||
DERIVATIVE FINANCIAL INSTRUMENTS | 6. DERIVATIVE FINANCIAL INSTRUMENTS | |||||||||||
The Company is exposed to certain risks relating to its ongoing business operations, and Whiting uses derivative instruments to manage its commodity price risk. Whiting follows FASB ASC Topic 815, Derivatives and Hedging, to account for its derivative financial instruments. | ||||||||||||
Commodity Derivative Contracts—Historically, prices received for crude oil and natural gas production have been volatile because of seasonal weather patterns, supply and demand factors, worldwide political factors and general economic conditions. Whiting enters into derivative contracts, such as costless collars, swaps and fixed-differential contracts to achieve a more predictable cash flow by reducing its exposure to commodity price volatility. Commodity derivative contracts are thereby used to ensure adequate cash flow to fund the Company’s capital programs and to manage returns on acquisitions and drilling programs. The Company does not enter into derivative contracts for speculative or trading purposes. | ||||||||||||
Crude Oil Costless Collars and Swaps. Costless collars are designed to establish floor and ceiling prices on anticipated future oil or gas production, while swaps are designed to establish a fixed price for anticipated future oil or gas production. While the use of these derivative instruments limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. | ||||||||||||
The table below details the Company’s costless collar and swap derivatives entered into to hedge forecasted crude oil production revenues as of February 13, 2015, including certain oil collars and swaps assumed in the Kodiak Acquisition. | ||||||||||||
Whiting Petroleum Corporation | ||||||||||||
Derivative | Contracted Crude | Weighted Average NYMEX Price | ||||||||||
Instrument | Period | Oil Volumes (Bbl) | Collar Ranges for Crude Oil (per Bbl) | |||||||||
Three-way collars (1) | Jan - Dec 2015 | 3,600,000 | $50.83 - $62.50 - $83.81 | |||||||||
Jan - Dec 2016 | 6,600,000 | $43.18 - $53.18 - $76.26 | ||||||||||
Collars | Jan - Dec 2015 | 1,309,500 | $52.47 - $59.26 | |||||||||
Jan - Dec 2016 | 3,000,000 | $51.00 - $63.48 | ||||||||||
Jan - Dec 2017 | 3,000,000 | $53.00 - $70.44 | ||||||||||
Swaps | Jan - Dec 2015 | 3,556,560 | $86.05 | |||||||||
Total | 21,066,060 | |||||||||||
_____________________ | ||||||||||||
-1 | A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The sold call establishes a maximum price (ceiling) Whiting will receive for the volumes under contract. The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be NYMEX plus the difference between the purchased put and the sold put strike price. | |||||||||||
In March 2013, Whiting entered into certain crude oil swap contracts in order to achieve more predictable cash flows and manage returns on certain oil and gas properties that the Company was considering for monetization. Accordingly, the acquisition of these swap contracts and cash receipts from settlements of these swap positions have been reflected as an investing activity in the statement of cash flows. On July 15, 2013, upon closing of the sale of the Postle Properties discussed in the Acquisitions and Divestitures footnote, these crude oil swaps were novated to the buyer. Cash settlements that do not relate to investing derivatives or that do not have a significant financing element are reflected as operating activities in the statement of cash flows. | ||||||||||||
Fixed-differential Crude Oil Contracts. The Company has entered into two long-term crude oil sales and delivery contracts for oil volumes produced from its Redtail field in Colorado. Under the terms of these agreements, Whiting has committed to deliver certain fixed volumes of crude oil from 2015 through 2020 at a price equal to NYMEX less the fixed differentials specified in the agreements. As of December 31, 2014, the Company determined that it is no longer probable that future oil production from its Redtail field will be sufficient to meet the minimum volume requirements specified in these contracts, and accordingly, that the Company will not settle these contracts through physical delivery of crude oil volumes. As a result, Whiting has determined that these contracts no longer qualify for the “normal purchase normal sale” exclusion, and has therefore reflected them at fair value in the consolidated financial statements. As of December 31, 2014, the estimated fair value of these derivative contracts was an asset of $54 million. | ||||||||||||
Embedded Commodity Derivative Contract—In May 2011, Whiting entered into a long-term contract to purchase CO2 for use in its EOR project that is being carried out at its North Ward Estes field in Texas. This contract contained a price adjustment clause that was linked to changes in NYMEX crude oil prices. The Company had determined that the portion of this contract linked to NYMEX oil prices was not clearly and closely related to the host contract, and the Company therefore bifurcated this embedded pricing feature from its host contract and reflected it at fair value in the consolidated financial statements. The Company had terminated this contract, however, prior to the issuance date of these financial statements, and the fair value of this embedded derivative was therefore zero as of December 31, 2014. | ||||||||||||
Derivative Instrument Reporting—All derivative instruments are recorded in the consolidated financial statements at fair value, other than derivative instruments that meet the “normal purchase normal sale” exclusion. The following tables summarize the effects of commodity derivative instruments on the consolidated statements of income for the years ended December 31, 2014 and 2013 (in thousands): | ||||||||||||
Loss Reclassified from AOCI into | ||||||||||||
Income (Effective Portion) | ||||||||||||
ASC 815 Cash Flow | Year Ended December 31, | |||||||||||
Hedging Relationships (1) | Income Statement Classification | 2014 | 2013 | |||||||||
Commodity contracts | Gain (loss) on hedging activities | $ | - | $ | -1,958 | |||||||
_____________________ | ||||||||||||
-1 | Effective April 1, 2009, the Company de-designated all of its commodity derivative contracts that had been previously designated as cash flow hedges and elected to discontinue hedge accounting prospectively. As a result, such mark-to-market values at March 31, 2009 were frozen in AOCI as of the de-designation date and were reclassified into earnings as the original hedged transactions affected income. As of December 31, 2013, all amounts previously in AOCI had been reclassified into earnings. | |||||||||||
(Gain) Loss Recognized in Income | ||||||||||||
Not Designated as | Year Ended December 31, | |||||||||||
ASC 815 Hedges | Income Statement Classification | 2014 | 2013 | |||||||||
Commodity contracts | Commodity derivative (gain) loss, net | $ | -136,995 | $ | 20,503 | |||||||
Embedded commodity contracts | Commodity derivative (gain) loss, net | 36,416 | -12,701 | |||||||||
Total | $ | -100,579 | $ | 7,802 | ||||||||
Offsetting of Derivative Assets and Liabilities. With each individual financial derivative counterparty, the Company typically has numerous hedge positions that span a several-month time period and that typically result in both fair value asset and liability positions held with that counterparty, which positions are all offset to a single fair value asset or liability amount at the end of each reporting period. The Company nets its financial derivative instrument fair value amounts executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The following tables summarize the location and fair value amounts of all derivative instruments in the consolidated balance sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the consolidated balance sheets (in thousands): | ||||||||||||
December 31, 2014 (1) | ||||||||||||
Net | ||||||||||||
Gross | Recognized | |||||||||||
Recognized | Gross | Fair Value | ||||||||||
Not Designated as | Assets/ | Amounts | Assets/ | |||||||||
ASC 815 Hedges | Balance Sheet Classification | Liabilities | Offset | Liabilities | ||||||||
Derivative assets: | ||||||||||||
Commodity contracts | Derivative assets | $ | 154,329 | $ | -18,752 | $ | 135,577 | |||||
Commodity contracts | Other long-term assets | 45,459 | - | 45,459 | ||||||||
Total derivative assets | $ | 199,788 | $ | -18,752 | $ | 181,036 | ||||||
Derivative liabilities: | ||||||||||||
Commodity contracts | $ | 18,752 | $ | -18,752 | $ | - | ||||||
Total derivative liabilities | $ | 18,752 | $ | -18,752 | $ | - | ||||||
December 31, 2013 (1) | ||||||||||||
Net | ||||||||||||
Gross | Recognized | |||||||||||
Recognized | Gross | Fair Value | ||||||||||
Not Designated as | Assets/ | Amounts | Assets/ | |||||||||
ASC 815 Hedges | Balance Sheet Classification | Liabilities | Offset | Liabilities | ||||||||
Derivative assets: | ||||||||||||
Commodity contracts | Derivative assets | $ | 23,752 | $ | -22,478 | $ | 1,274 | |||||
Embedded commodity contracts | Other long-term assets | 36,416 | - | 36,416 | ||||||||
Total derivative assets | $ | 60,168 | $ | -22,478 | $ | 37,690 | ||||||
Derivative liabilities: | ||||||||||||
Commodity contracts | Accrued liabilities and other | $ | 25,960 | $ | -22,478 | $ | 3,482 | |||||
Total derivative liabilities | $ | 25,960 | $ | -22,478 | $ | 3,482 | ||||||
_____________________ | ||||||||||||
-1 | Because counterparties to the Company’s financial derivative contracts are lenders under Whiting Oil and Gas’ credit agreement, which eliminates its need to post or receive collateral associated with its derivative positions, columns for cash collateral pledged or received have not been presented in the tables above. | |||||||||||
Contingent Features in Financial Derivative Instruments. None of the Company’s derivative instruments contain credit-risk-related contingent features. Counterparties to the Company’s financial derivative contracts are high credit-quality financial institutions that are lenders under Whiting’s credit agreement. The Company uses only credit agreement participants to hedge with, since these institutions are secured equally with the holders of Whiting’s bank debt, which eliminates the potential need to post collateral when Whiting is in a derivative liability position. As a result, the Company is not required to post letters of credit or corporate guarantees for its financial derivative counterparties in order to secure contract performance obligations. | ||||||||||||
FAIR_VALUE_MEASUREMENTS
FAIR VALUE MEASUREMENTS | 12 Months Ended | ||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||
FAIR VALUE MEASUREMENTS [Abstract] | |||||||||||||||||||||
FAIR VALUE MEASUREMENTS | 7. FAIR VALUE MEASUREMENTS | ||||||||||||||||||||
Cash and cash equivalents, accounts receivable and payable are carried at cost, which approximates their fair value because of the short-term maturity of these instruments. The Company’s credit agreement has a recorded value that approximates its fair value since its variable interest rate is tied to current market rates. The Company’s Senior Notes (including the Kodiak Notes) and Senior Subordinated Notes are recorded at cost, and the fair values of these instruments are included in the Long-Term Debt footnote. The Company’s derivative financial instruments are recorded at fair value and include a measure of the Company’s own nonperformance risk or that of its counterparties as appropriate. | |||||||||||||||||||||
The Company follows FASB ASC Topic 820, Fair Value Measurement and Disclosure, which establishes 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: Quoted Prices in Active Markets for Identical Assets – inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets. | ||||||||||||||||||||
· | Level 2: Significant Other Observable Inputs – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument. | ||||||||||||||||||||
· | Level 3: Significant Unobservable Inputs – inputs to the valuation methodology are unobservable and significant to the fair value measurement. | ||||||||||||||||||||
A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The Company reflects transfers between the three levels at the beginning of the reporting period in which the availability of observable inputs no longer justifies classification in the original level. | |||||||||||||||||||||
The following tables present information about the Company’s financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2014 and 2013, and indicate the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair values (in thousands): | |||||||||||||||||||||
Total Fair Value | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | 31-Dec-14 | ||||||||||||||||||
Financial Assets | |||||||||||||||||||||
Commodity derivatives – current | $ | - | $ | 127,506 | $ | 8,071 | $ | 135,577 | |||||||||||||
Commodity derivatives – non-current | - | - | 45,459 | 45,459 | |||||||||||||||||
Total financial assets | $ | - | $ | 127,506 | $ | 53,530 | $ | 181,036 | |||||||||||||
Total Fair Value | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | 31-Dec-13 | ||||||||||||||||||
Financial Assets | |||||||||||||||||||||
Commodity derivatives – current | $ | - | $ | 1,274 | $ | - | $ | 1,274 | |||||||||||||
Embedded commodity derivatives – non-current | - | - | 36,416 | 36,416 | |||||||||||||||||
Total financial assets | $ | - | $ | 1,274 | $ | 36,416 | $ | 37,690 | |||||||||||||
Financial Liabilities | |||||||||||||||||||||
Commodity derivatives – current | $ | - | $ | 3,482 | $ | - | $ | 3,482 | |||||||||||||
Total financial liabilities | $ | - | $ | 3,482 | $ | - | $ | 3,482 | |||||||||||||
The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the tables above: | |||||||||||||||||||||
Commodity Derivatives. Commodity derivative instruments consist mainly of costless collars and swap contracts for crude oil. The Company’s costless collars and swaps are valued based on an income approach. Both the option and swap models consider various assumptions, such as quoted forward prices for commodities, time value and volatility factors. These assumptions are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace, and are therefore designated as Level 2 within the valuation hierarchy. The discount rates used in the fair values of these instruments include a measure of either the Company’s or the counterparty’s nonperformance risk, as appropriate. The Company utilizes its counterparties’ valuations to assess the reasonableness of its own valuations. | |||||||||||||||||||||
In addition, the Company has two long-term crude oil sales and delivery contracts, whereby it has committed to deliver certain fixed volumes of crude oil at a price equal to NYMEX less the fixed differentials specified in the agreement. Whiting has determined that the contracts do not meet the “normal purchase normal sale” exclusion, and has therefore reflected these contracts at fair value in its consolidated financial statements. These commodity derivatives are valued based on an income approach, which considers various assumptions, including quoted forward prices for commodities, market differentials for crude oil, U.S. Treasury rates and either the Company’s or the counterparty’s nonperformance risk, as appropriate. | |||||||||||||||||||||
The assumptions used in the valuation of the fixed-differential contracts include certain market differential metrics that are unobservable during the term of the contracts. Such unobservable inputs are significant to the contract valuation methodology, and the contracts’ fair values are therefore designated as Level 3 within the valuation hierarchy. | |||||||||||||||||||||
Embedded Commodity Derivatives. The embedded commodity derivative was related to a long-term CO2 purchase contract, which had a price adjustment clause linked to changes in NYMEX crude oil prices. Whiting determined that the portion of this contract linked to NYMEX oil prices was not clearly and closely related to its corresponding host contract, and the Company therefore bifurcated this embedded pricing feature from the host contract and reflected it at fair value in its consolidated financial statements as of December 31, 2013. The assumptions used in the CO2 contract valuation, which was based on the income approach, included certain oil price metrics that were unobservable during the term of the contract. Such unobservable oil price inputs were significant to the CO2 contract valuation methodology, and the contract’s fair value was therefore designated as Level 3 within the valuation hierarchy. Because the Company subsequently terminated this CO2 purchase contract, however, its embedded derivative had a fair value of zero as of December 31, 2014. | |||||||||||||||||||||
Level 3 Fair Value Measurements. A third-party valuation specialist is utilized to determine the fair value of the commodity derivative instruments designated as Level 3. The Company reviews these valuations (including the related model inputs and assumptions) and analyzes changes in fair value measurements between periods. The Company corroborates such inputs, calculations and fair value changes using various methodologies, and reviews unobservable inputs for reasonableness utilizing relevant information from other published sources. | |||||||||||||||||||||
The following table presents a reconciliation of changes in the fair value of financial assets (liabilities) designated as Level 3 in the valuation hierarchy for the years ended December 31, 2014 and 2013 (in thousands): | |||||||||||||||||||||
Year Ended | |||||||||||||||||||||
December 31, | |||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||
Fair value asset, beginning of period | $ | 36,416 | $ | 23,715 | |||||||||||||||||
Unrealized gains (losses) on commodity derivative contracts included in earnings (1) | 17,114 | 12,701 | |||||||||||||||||||
Transfers into (out of) Level 3 | - | - | |||||||||||||||||||
Fair value asset, end of period | $ | 53,530 | $ | 36,416 | |||||||||||||||||
_____________________ | |||||||||||||||||||||
-1 | Included in commodity derivative (gain) loss, net in the consolidated statements of income. | ||||||||||||||||||||
Quantitative Information About Level 3 Fair Value Measurements. The significant unobservable inputs used in the fair value measurement of the Company’s commodity derivative contracts designated as Level 3 are as follows: | |||||||||||||||||||||
Fair Value at | |||||||||||||||||||||
31-Dec-14 | Valuation | Unobservable | Amount | ||||||||||||||||||
(in thousands) | Technique | Input | (per Bbl) | ||||||||||||||||||
Commodity derivative contracts | $53,530 | Income approach | Market differential for crude oil | $5.74 | |||||||||||||||||
Sensitivity to Changes in Significant Unobservable Inputs. As presented above, the significant unobservable inputs used in the fair value measurement of Whiting’s commodity derivative contracts are the market differentials for crude oil over the term of the contracts. Significant increases (decreases) in these unobservable inputs in isolation would result in significantly lower (higher) fair value asset measurement. | |||||||||||||||||||||
Nonrecurring Fair Value Measurements. The Company applies the provisions of the fair value measurement standard to its nonrecurring, non-financial measurements, including proved oil and gas property impairments. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments only in certain circumstances. The following tables present information about the Company’s non-financial assets and liabilities measured at fair value on a nonrecurring basis as of December 31, 2014 and 2013, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair values (in thousands): | |||||||||||||||||||||
Loss (Before | |||||||||||||||||||||
Net Carrying | Tax) Year | ||||||||||||||||||||
Value as of | Ended | ||||||||||||||||||||
December 31, | Fair Value Measurements Using | December 31, | |||||||||||||||||||
2014 | Level 1 | Level 2 | Level 3 | 2014 | |||||||||||||||||
Proved property impairments (1) | $ | 179,155 | $ | - | $ | - | $ | 179,155 | $ | 629,450 | |||||||||||
_____________________ | |||||||||||||||||||||
-1 | During the year ended December 31, 2014, proved oil and gas properties with a carrying amount of $763 million were written down to their fair value of $176 million, resulting in a non-cash impairment charge of $587 million. The impairment primarily consisted of non-core oil and gas properties, that are not currently being developed, in Colorado, Louisiana, North Dakota and Utah and related to the decrease in the forward price curve for crude oil and natural gas on December 31, 2014 and the associated decline in oil and gas reserves in those areas. Also during the year ended December 31, 2014, proved CO2 properties at the Bravo Dome field in New Mexico with a carrying amount of $45 million were written down to their fair value of $3 million, resulting in a non-cash impairment charge of $42 million. | ||||||||||||||||||||
Loss (Before | |||||||||||||||||||||
Net Carrying | Tax) Year | ||||||||||||||||||||
Value as of | Ended | ||||||||||||||||||||
December 31, | Fair Value Measurements Using | December 31, | |||||||||||||||||||
2013 | Level 1 | Level 2 | Level 3 | 2013 | |||||||||||||||||
Proved property impairments (1) | $ | 106,114 | $ | - | $ | - | $ | 106,114 | $ | 267,109 | |||||||||||
_____________________ | |||||||||||||||||||||
-1 | During the year ended December 31, 2013, proved oil and gas properties with a carrying amount of $373 million were written down to their fair value of $106 million, resulting in a non-cash impairment charge of $267 million. The impairment consisted of (i) a $221 million write-down in the Rocky Mountains region and Michigan related to the decrease in the forward price curve for natural gas at December 31, 2013 and the associated decline in gas reserves in those areas and (ii) a $46 million write-down in the Rocky Mountains region related to well performance and associated changes in reserves during the fourth quarter of 2013. | ||||||||||||||||||||
The following methods and assumptions were used to estimate the fair values of the non-financial liabilities in the tables above: | |||||||||||||||||||||
Proved Property Impairments. Once the Company has determined that a proved property impairment has occurred, the cost of the property is written down to its fair value, which is determined using net discounted future cash flows from the producing property, and such discounted cash flows are developed using the income approach. The discounted cash flows are based on management’s expectations for the future. Unobservable inputs include estimates of future oil and gas or CO2 production, as the case may be, from the Company’s reserve reports, commodity prices based on sales contract terms or NYMEX forward price curves as of the date of the estimate (adjusted for basis differentials), estimated operating and development costs, and a risk-adjusted discount rate (all of which are designated as Level 3 inputs within the fair value hierarchy). | |||||||||||||||||||||
DEFERRED_COMPENSATION
DEFERRED COMPENSATION | 12 Months Ended | ||||||
Dec. 31, 2014 | |||||||
DEFERRED COMPENSATION [Abstract] | |||||||
DEFERRED COMPENSATION | 8. DEFERRED COMPENSATION | ||||||
Production Participation Plan—The Company had a Production Participation Plan (the “Plan”) in which all employees participated. On June 11, 2014, the Board of Directors of the Company terminated the Plan effective December 31, 2013. Prior to Plan termination, interests in oil and gas properties acquired, developed or sold during the year were allocated to the Plan on an annual basis as determined by the Compensation Committee of the Company’s Board of Directors. Once allocated, the interests (not legally conveyed) were fixed. Interest allocations prior to 1995 consisted of 2%‑3% overriding royalty interests. Interest allocations after 1995 were 1.75%‑5% of oil and gas sales less lease operating expenses and production taxes. | |||||||
Employees vested in the Plan ratably at 20% per year over a five-year period. However, pursuant to the terms of the Plan, upon Plan termination all employees fully vested, and the Company is required to distribute to each Plan participant an amount, based upon the valuation method set forth in the Plan, in a lump sum payment twelve months after the date of termination. This distribution includes the value of proved undeveloped oil and gas properties (“PUDs”) awarded upon Plan termination and is based on forecasted commodity prices for crude oil, NGLs and natural gas as of December 31, 2013. The fully vested amount due to Plan participants totals $113 million and has been reflected as a current payable, as it will be distributed to Plan participants during the first half of 2015. As of December 31, 2014, a portion of this liability representing a regular distribution under the Plan totaling $41 million had been paid to the Company’s third-party payroll administrator. However, these funds were not distributed by the payroll administrator to Plan participants until January 2015. The final Plan distribution payment will be made in June 2015. | |||||||
Accrued compensation expense under the Plan for the year ended December 31, 2014 primarily relates to the change in liability for employee vestings and PUDs assigned upon Plan termination and amounted to $24 million charged to general and administrative expense and $2 million charged to exploration expense. Accrued compensation expense under the Plan for the years ended December 31, 2013 and 2012 amounted to $66 million and $45 million, respectively, charged to general and administrative expense and $7 million and $4 million, respectively, charged to exploration expense. Of the aggregate $73 million of accrued compensation under the Plan as of December 31, 2013, $24 million relates to the sale of the Postle Properties, which is further described in the Acquisitions and Divestitures footnote. | |||||||
Prior to Plan termination, the Company recorded non-cash changes in the present value of estimated future payments under the Plan as a separate line item in the consolidated statements of income. As a result of Plan termination, all changes in the Plan liability during 2014 related to cash termination payments to be made in 2015. The following table presents changes in the Plan’s estimated long-term liability (in thousands): | |||||||
Year Ended December 31, | |||||||
2014 | 2013 | ||||||
Long-term Production Participation Plan liability at January 1 | $ | 87,503 | $ | 94,483 | |||
Change in liability for accretion, vesting, changes in estimates and new Plan year activity prior to Plan termination | - | 66,284 | |||||
Change in liability for vesting and PUDs assigned upon Plan termination | 25,888 | - | |||||
Amount reflected as a current liability | -113,391 | -73,264 | |||||
Long-term Production Participation Plan liability at December 31 | $ | - | $ | 87,503 | |||
401(k) Plan—The Company has a defined contribution retirement plan for all employees. The plan is funded by employee contributions and discretionary Company contributions. The Company’s contributions for 2014, 2013 and 2012 were $9 million, $8 million and $6 million, respectively. Employees vest in employer contributions at 20% per year of completed service. | |||||||
SHAREHOLDERS_EQUITY_AND_NONCON
SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST | 12 Months Ended | ||||||||||
Dec. 31, 2014 | |||||||||||
SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST [Abstract] | |||||||||||
SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST | 9. SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTEREST | ||||||||||
6.25% Convertible Perpetual Preferred Stock—In June 2009, the Company completed a public offering of 6.25% convertible perpetual preferred stock (“preferred stock”), selling 3,450,000 shares at a price of $100.00 per share. As a result of voluntary conversions and the Company exercising its right to mandatorily convert shares of preferred stock effective June 27, 2013, all 172,129 remaining shares of preferred stock outstanding on March 31, 2013 were converted into 792,919 shares of common stock. As of December 31, 2014, no shares of preferred stock remained issued or outstanding. | |||||||||||
Each holder of the preferred stock was entitled to an annual dividend of $6.25 per share to be paid quarterly in cash, common stock or a combination thereof on March 15, June 15, September 15 and December 15, once such dividend had been declared by Whiting’s board of directors. | |||||||||||
Equity Incentive Plan—At the Company’s 2013 Annual Meeting held on May 7, 2013, shareholders approved the Whiting Petroleum Corporation 2013 Equity Incentive Plan (the “2013 Equity Plan”), which replaced the Whiting Petroleum Corporation 2003 Equity Incentive Plan (the “2003 Equity Plan”) and includes the authority to issue 5,300,000 shares of the Company’s common stock. Upon shareholder approval of the 2013 Equity Plan, the 2003 Equity Plan was terminated. The 2003 Equity Plan continues to govern awards that were outstanding as of the date of its termination, which remain in effect pursuant to their terms. Any shares netted or forfeited after May 7, 2013 under the 2003 Equity Plan will be available for future issuance under the 2013 Equity Plan. Under the 2013 Equity Plan, no employee or officer participant may be granted options for more than 600,000 shares of common stock, stock appreciation rights relating to more than 600,000 shares of common stock, or more than 300,000 shares of restricted stock during any calendar year. On December 8, 2014, the Company increased the number of shares issuable under the 2013 Equity Plan by 978,161 shares to accommodate for the conversion of Kodiak’s outstanding equity awards to Whiting equity awards upon closing of the Kodiak Acquisition. Any shares netted or forfeited under this increased availability will be cancelled and will not be available for future issuance under the 2013 Equity Plan. As of December 31, 2014, 5,048,433 shares of common stock remained available for grant under the 2013 Equity Plan. | |||||||||||
For the years ended December 31, 2014, 2013 and 2012, total stock compensation expense recognized for restricted share awards and stock options was $23 million, $22 million and $18 million, respectively. | |||||||||||
Equity Awards Assumed in Kodiak Acquisition. Upon closing of the Kodiak Acquisition, the Company assumed all of Kodiak’s outstanding equity awards, including restricted stock awards, restricted stock units and stock options. Kodiak’s outstanding equity awards held by employees were converted into Whiting’s equity awards using a conversion ratio of 0.177. The outstanding restricted stock awards and restricted stock units vested upon closing of the transaction, and the $10 million estimated fair value of the 257,601 shares of Whiting common stock issued to convert these awards was recorded as part of the purchase consideration. | |||||||||||
The estimated fair value of the 673,235 Whiting options issued in exchange for Kodiak’s outstanding options was approximately $8 million, based on a Black-Scholes option-pricing model. Of this value, approximately $7 million was attributable to service rendered prior to the date of acquisition and was recorded as part of the purchase consideration, and the remaining $1 million will be expensed over the remaining service term of the replacement stock option awards. The unvested stock option awards will vest over a one to three-year service period from the grant date and are exercisable immediately upon vesting through the tenth anniversary of the grant date. The following table summarizes the assumptions used to estimate the fair value of stock options assumed in the Kodiak Acquisition: | |||||||||||
2014 | |||||||||||
Risk-free interest rate | 0.08% - 1.90% | ||||||||||
Expected volatility | 40.3% - 49.7% | ||||||||||
Expected term | 2.0 yrs. - 6.1 yrs. | ||||||||||
Dividend yield | - | ||||||||||
The weighted average fair value of these options, as determined by the Black-Scholes valuation model, was $12.20 per share as of the December 8, 2014 closing date of the Kodiak Acquisition. | |||||||||||
Restricted Shares. Restricted stock awards for executive officers and employees generally vest ratably over a three-year service period, while awards to directors generally vest ratably over a one-year service period. The Company uses historical data and projections to estimate expected employee behaviors related to restricted stock forfeitures. The expected forfeitures are then included as part of the grant date estimate of compensation cost. For service-based restricted stock awards, the grant date fair value is determined based on the closing bid price of the Company’s common stock on the grant date. | |||||||||||
In January 2014, 2013 and 2012, 750,681 shares, 751,872 shares and 444,501 shares, respectively, of restricted stock, subject to certain market-based vesting criteria in addition to the standard three-year service condition, were granted to executive officers under the Equity Plan. Vesting each year is subject to the condition that Whiting’s stock price increases by a greater percentage (or decreases by a lesser percentage) than the average percentage increase (or decrease, respectively) of the stock prices of a peer group of companies. The market-based conditions must be met in order for the stock awards to vest, and it is therefore possible that no shares could vest in one or more of the three-year vesting periods. However, the Company recognizes compensation expense for awards subject to market conditions regardless of whether it becomes probable that these conditions will be achieved or not, and compensation expense is not reversed if vesting does not actually occur. | |||||||||||
For these awards subject to market conditions, the grant date fair value was estimated using a Monte Carlo valuation model. The Monte Carlo model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility was calculated based on the historical volatility of Whiting’s common stock, and the risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with the three-year vesting period. The key assumptions used in valuing the market-based restricted shares were as follows: | |||||||||||
2014 | 2013 | 2012 | |||||||||
Number of simulations | 65,000 | 65,000 | 65,000 | ||||||||
Expected volatility | 42.30% | 43.10% | 51.90% | ||||||||
Risk-free interest rate | 0.86% | 0.41% | 0.35% | ||||||||
Dividend yield | - | - | - | ||||||||
The grant date fair value of the market-based restricted stock as determined by the Monte Carlo valuation model was $26.59 per share, $23.01 per share and $29.45 per share in January 2014, 2013 and 2012, respectively. | |||||||||||
The following table shows a summary of the Company’s nonvested restricted stock as of December 31, 2012, 2013 and 2014 as well as activity during the years then ended: | |||||||||||
Weighted Average | |||||||||||
Number | Grant Date | ||||||||||
of Shares | Fair Value | ||||||||||
Restricted stock awards nonvested, January 1, 2012 | 724,395 | $ | 29.88 | ||||||||
Granted | 592,400 | 34.45 | |||||||||
Vested | -357,170 | 17.91 | |||||||||
Forfeited | -8,599 | 51.72 | |||||||||
Restricted stock awards nonvested, December 31, 2012 | 951,026 | 37.02 | |||||||||
Granted | 940,792 | 27.59 | |||||||||
Vested | -347,824 | 35.32 | |||||||||
Forfeited | -99,684 | 30.95 | |||||||||
Restricted stock awards nonvested, December 31, 2013 | 1,444,310 | 31.71 | |||||||||
Granted | 907,856 | 32.41 | |||||||||
Assumed in Kodiak Acquisition (1) | 304,926 | 37.25 | |||||||||
Vested | -814,439 | 34.05 | |||||||||
Forfeited | -385,785 | 34.86 | |||||||||
Restricted stock awards nonvested, December 31, 2014 | 1,456,868 | $ | 31.16 | ||||||||
_____________________ | |||||||||||
-1 | Kodiak’s existing restricted stock units and restricted stock awards held by employees, which automatically converted into 257,601 restricted stock units and 47,325 restricted stock awards of Whiting and vested upon closing of the Kodiak Acquisition. | ||||||||||
As of December 31, 2014, there was $13 million of total unrecognized compensation cost related to unvested restricted stock granted under the stock incentive plans. That cost is expected to be recognized over a weighted average period of 1.7 years. For the years ended December 31, 2014, 2013 and 2012, the total fair value of restricted stock vested was $31 million, $17 million and $19 million, respectively. | |||||||||||
Stock Options. Stock options may be granted to certain executive officers of the Company with exercise prices equal to the closing market price of the Company’s common stock on the grant date. There were no stock options granted under either the 2003 Equity Plan or the 2013 Equity Plan during 2014 or 2013, other than the 673,235 stock options assumed in connection with the Kodiak Acquisition. In January 2012, 45,359 stock options were granted under the 2003 Equity Plan. The Company’s stock options vest ratably over a three-year service period from the grant date and are exercisable immediately upon vesting through the tenth anniversary of the grant date. | |||||||||||
The Company uses a Black-Scholes option-pricing model to estimate the fair value of stock option awards. Because the Company first granted stock options in 2009, it does not have historical exercise data upon which to estimate the expected term of the options. As such, the Company has elected to estimate the expected term of the stock options granted using the “simplified” method for “plain vanilla” options. The expected volatility at the grant date is based on the historical volatility of Whiting’s common stock, and the risk-free interest rate is determined based on the yield on U.S. Treasury strips with maturities similar to those of the expected term of the stock options. The following table summarizes the assumptions used to estimate the grant date fair value of stock options awarded in 2012: | |||||||||||
2012 | |||||||||||
Risk-free interest rate | 1.19% | ||||||||||
Expected volatility | 61.40% | ||||||||||
Expected term | 6.0 yrs. | ||||||||||
Dividend yield | - | ||||||||||
The grant date fair value of the stock options awarded, as determined by the Black-Scholes valuation model, was $28.88 per share in January 2012. | |||||||||||
The following table shows a summary of the Company’s stock options outstanding as of December 31, 2012, 2013 and 2014 as well as activity during the years then ended: | |||||||||||
Weighted | |||||||||||
Average | |||||||||||
Weighted | Aggregate | Remaining | |||||||||
Average | Intrinsic | Contractual | |||||||||
Number of | Exercise Price | Value | Term | ||||||||
Options | per Share | (in thousands) | (in years) | ||||||||
Options outstanding at January 1, 2012 | 377,336 | $ | 26.09 | ||||||||
Granted | 45,359 | 51.22 | |||||||||
Exercised | - | - | $ | - | |||||||
Forfeited or expired | - | - | |||||||||
Options outstanding at December 31, 2012 | 422,695 | 28.79 | |||||||||
Granted | - | - | |||||||||
Exercised | - | - | $ | - | |||||||
Forfeited or expired | -1,855 | 60.28 | |||||||||
Options outstanding at December 31, 2013 | 420,840 | 28.65 | |||||||||
Granted | - | - | |||||||||
Assumed in Kodiak Acquisition | 673,235 | 44.48 | |||||||||
Exercised | -117,123 | 15.21 | $ | 6,203,361 | |||||||
Forfeited or expired | -8,559 | 50.51 | |||||||||
Options outstanding at December 31, 2014 | 968,393 | $ | 41.09 | $ | 5,216,952 | 4.8 | |||||
Options vested and expected to vest at December 31, 2014 | 905,107 | $ | 40.78 | $ | 4,984,431 | 4.8 | |||||
Options exercisable at December 31, 2014 | 831,220 | $ | 38.45 | $ | 5,216,952 | 4.2 | |||||
Unrecognized compensation cost as of December 31, 2014 related to unvested stock option awards was $1 million, which is expected to be recognized over a period of 1.2 years. | |||||||||||
Rights Agreement—In 2006, the Board of Directors of the Company declared a dividend of one preferred share purchase right (a “Right”) for each outstanding share of common stock of the Company payable to the stockholders of record as of March 2, 2006. As a result of the two-for-one split of the Company’s common stock effective February 22, 2011, one-half of a Right is now associated with each share of common stock. Each Right entitles the registered holder to purchase from the Company one one-hundredth of a share of Series A Junior Participating Preferred Stock, par value $0.001 per share (“Preferred Shares”), of the Company at a price of $180.00 per one one-hundredth of a Preferred Share, subject to adjustment. If any person becomes a 15% or more stockholder of the Company, then each Right (subject to certain limitations) will entitle its holder to purchase, at the Right’s then current exercise price, a number of shares of common stock of the Company or of the acquirer having a market value at the time of twice the Right’s per share exercise price. The Company’s Board of Directors may redeem the Rights for $0.001 per Right at any time prior to the time when the Rights become exercisable. Unless the Rights are redeemed, exchanged or terminated earlier, they will expire on February 23, 2016. | |||||||||||
Noncontrolling Interest—The noncontrolling interest represents an unrelated third party’s 25% ownership interest in Sustainable Water Resources, LLC. The table below summarizes the activity for the equity attributable to the noncontrolling interest (in thousands): | |||||||||||
Year Ended | |||||||||||
December 31, | |||||||||||
2014 | 2013 | ||||||||||
Balance at January 1 | $ | 8,132 | $ | 8,184 | |||||||
Net loss | -62 | -52 | |||||||||
Balance at December 31 | $ | 8,070 | $ | 8,132 | |||||||
INCOME_TAXES
INCOME TAXES | 12 Months Ended | |||||||||
Dec. 31, 2014 | ||||||||||
INCOME TAXES [Abstract] | ||||||||||
INCOME TAXES | 10. INCOME TAXES | |||||||||
Income tax expense consists of the following (in thousands): | ||||||||||
Year Ended December 31, | ||||||||||
2014 | 2013 | 2012 | ||||||||
Current income tax expense (refund): | ||||||||||
Federal | $ | -2,758 | $ | 7,060 | $ | - | ||||
State | 5,383 | -6,074 | -669 | |||||||
Total current income tax expense (refund) | 2,625 | 986 | -669 | |||||||
Deferred income tax expense: | ||||||||||
Federal | 65,522 | 196,787 | 233,468 | |||||||
State | 11,023 | 8,095 | 15,113 | |||||||
Total deferred income tax expense | 76,545 | 204,882 | 248,581 | |||||||
Total | $ | 79,170 | $ | 205,868 | $ | 247,912 | ||||
Income tax expense differed from amounts that would result from applying the U.S. statutory income tax rate (35%) to income before income taxes as follows (in thousands): | ||||||||||
Year Ended December 31, | ||||||||||
2014 | 2013 | 2012 | ||||||||
U.S. statutory income tax expense | $ | 50,371 | $ | 200,155 | $ | 231,704 | ||||
State income taxes, net of federal benefit | 12,705 | 13,962 | 14,444 | |||||||
State income tax credits | - | -10,525 | - | |||||||
Statutory depletion | -618 | -796 | -620 | |||||||
Enacted changes in state tax laws | 3,700 | -1,416 | - | |||||||
Market-based equity awards | 2,805 | - | - | |||||||
Permanent items | 3,504 | 2,122 | 1,524 | |||||||
Transaction costs | 6,936 | - | - | |||||||
Other | -233 | 2,366 | 860 | |||||||
Total | $ | 79,170 | $ | 205,868 | $ | 247,912 | ||||
The principal components of the Company’s deferred income tax assets and liabilities at December 31, 2014 and 2013 were as follows (in thousands): | ||||||||||
Year Ended December 31, | ||||||||||
2014 | 2013 | |||||||||
Deferred income tax assets: | ||||||||||
Net operating loss carryforward | $ | 588,330 | $ | 438,922 | ||||||
Production Participation Plan liability | 26,942 | 32,245 | ||||||||
Tax sharing liability | - | 9,439 | ||||||||
Asset retirement obligations | 13,791 | 23,642 | ||||||||
Underwriter fees | 14,065 | 10,974 | ||||||||
Restricted stock compensation | 15,527 | 13,384 | ||||||||
Premium on Senior Notes | 7,979 | - | ||||||||
EOR credit carryforwards | 7,946 | 7,946 | ||||||||
Alternative minimum tax credit carryforwards | 15,694 | 18,452 | ||||||||
Transaction costs | 7,957 | - | ||||||||
Other | 9,493 | 3,234 | ||||||||
Total deferred income tax assets | 707,724 | 558,238 | ||||||||
Less valuation allowance | -5,638 | -1,230 | ||||||||
Net deferred income tax assets | 702,086 | 557,008 | ||||||||
Deferred income tax liabilities: | ||||||||||
Oil and gas properties | 1,785,926 | 1,675,916 | ||||||||
Trust distributions | 129,437 | 149,332 | ||||||||
Derivative instruments | 64,898 | 10,438 | ||||||||
Total deferred income tax liabilities | 1,980,261 | 1,835,686 | ||||||||
Total net deferred income tax liabilities | $ | 1,278,175 | $ | 1,278,678 | ||||||
As of December 31, 2014, the Company had federal net operating loss (“NOL”) carryforwards of $1.7 billion. Of this amount, $70 million in NOL carryforwards relate to tax deductions for stock compensation that exceed stock compensation costs recognized for financial statement purposes. The benefit of these excess tax deductions will not be recognized as an NOL in the Company’s financial statements, until the related deductions reduce taxes payable and are thereby realized. In addition, $170 million of NOL carryforwards are a result of the Kodiak Acquisition, and the utilization of this amount is limited to $77 million each year for the next three years. The Company also has various state NOL carryforwards. The determination of the state NOL carryforwards is dependent upon apportionment percentages and state laws that can change from year to year and that can thereby impact the amount of such carryforwards. If unutilized, the federal NOL will expire between 2028 and 2035, and the state NOLs will expire between 2015 and 2035. | ||||||||||
EOR credits are a credit against federal income taxes for certain costs related to extracting high-cost oil, utilizing certain prescribed enhanced tertiary recovery methods. As of December 31, 2014, the Company had recognized aggregate EOR credits of $8 million that are available to offset regular federal income taxes in the future. These credits can be carried forward and will expire between 2023 and 2025. Federal EOR credits are subject to phase-out according to the level of average domestic crude oil prices. The EOR credit has been phased-out since 2006, but this phase-out affects only the periods for which EOR credits can be captured and not the periods in which such credits can be utilized. | ||||||||||
The Company is subject to the alternative minimum tax (“AMT”) principally due to its significant intangible drilling cost deductions. As of December 31, 2014, the Company had AMT credits totaling $16 million that are available to offset future regular federal income taxes. These credits do not expire and can be carried forward indefinitely. | ||||||||||
At December 31, 2014, the Company had a valuation allowance totaling $6 million, comprised of unamortized underwriter fees in Canada and foreign tax credit carryforwards, which will expire between 2015 and 2016. These valuation allowances have been recorded because the Company determined it was more likely than not that the benefit from these deferred tax assets will not be realized due to the divestiture of all foreign operations. | ||||||||||
In conjunction with the Kodiak Acquisition, the Company acquired Kodiak, which is a Canadian entity that is to be disregarded for U.S. tax purposes. Kodiak holds an interest in Whiting Resources Corporation (formerly Kodiak Oil & Gas (USA) Inc.), a U.S. entity which has undistributed earnings at December 31, 2014. These earnings are considered to be indefinitely reinvested, and accordingly, no provision has been provided for on those earnings. If the Company were to repatriate those earnings in the form of dividends or otherwise, no taxes would result. | ||||||||||
Net deferred income tax liabilities were classified in the consolidated balance sheets as follows (in thousands): | ||||||||||
Year Ended December 31, | ||||||||||
2014 | 2013 | |||||||||
Assets: | ||||||||||
Current deferred income taxes | $ | - | $ | - | ||||||
Liabilities: | ||||||||||
Current deferred income taxes | 47,545 | 648 | ||||||||
Non-current deferred income taxes | 1,230,630 | 1,278,030 | ||||||||
Net deferred income tax liabilities | $ | 1,278,175 | $ | 1,278,678 | ||||||
The following table summarizes the activity related to the Company’s liability for unrecognized tax benefits (in thousands): | ||||||||||
Year Ended December 31, | ||||||||||
2014 | 2013 | 2012 | ||||||||
Beginning balance at January 1 | $ | 170 | $ | 170 | $ | 299 | ||||
Decrease related to tax position taken in a prior period | - | - | -129 | |||||||
Ending balance at December 31 | $ | 170 | $ | 170 | $ | 170 | ||||
The unrecognized tax benefit balance at December 31, 2014 includes certain tax positions, the allowance of which would positively affect the annual effective income tax rate. For the year ended December 31, 2014, the Company did not recognize any interest or penalties with respect to unrecognized tax benefits, nor did the Company have any such interest or penalties previously accrued. The Company believes that it is reasonably possible that no increases or decreases to unrecognized tax benefits will occur in the next twelve months. | ||||||||||
The Company files income tax returns in the U.S. federal jurisdiction and in various states, each with varying statutes of limitations. The 2011 through 2014 tax years generally remain subject to examination by federal and state tax authorities. Additionally, in conjunction with the Kodiak Acquisition, the Company has Canadian income tax filings which remain subject to examination by the related tax authorities for the 2009 through 2014 tax years. | ||||||||||
EARNINGS_PER_SHARE
EARNINGS PER SHARE | 12 Months Ended | |||||||||
Dec. 31, 2014 | ||||||||||
EARNINGS PER SHARE [Abstract] | ||||||||||
EARNINGS PER SHARE | 11. EARNINGS PER SHARE | |||||||||
The reconciliations between basic and diluted earnings per share are as follows (in thousands, except per share data): | ||||||||||
Year Ended | ||||||||||
December 31, | ||||||||||
2014 | 2013 | 2012 | ||||||||
Basic Earnings Per Share | ||||||||||
Numerator: | ||||||||||
Net income available to shareholders | $ | 64,807 | $ | 366,055 | $ | 414,189 | ||||
Preferred stock dividends (1) | - | -494 | -1,077 | |||||||
Net income available to common shareholders, basic | $ | 64,807 | $ | 365,561 | $ | 413,112 | ||||
Denominator: | ||||||||||
Weighted average shares outstanding, basic | 122,138 | 118,260 | 117,601 | |||||||
Diluted Earnings Per Share | ||||||||||
Numerator: | ||||||||||
Net income available to common shareholders, basic | $ | 64,807 | $ | 365,561 | $ | 413,112 | ||||
Preferred stock dividends | - | 538 | 1,077 | |||||||
Adjusted net income available to common shareholders, diluted | $ | 64,807 | $ | 366,099 | $ | 414,189 | ||||
Denominator: | ||||||||||
Weighted average shares outstanding, basic | 122,138 | 118,260 | 117,601 | |||||||
Restricted stock and stock options | 381 | 957 | 633 | |||||||
Convertible perpetual preferred stock | - | 371 | 794 | |||||||
Weighted average shares outstanding, diluted | 122,519 | 119,588 | 119,028 | |||||||
Earnings per common share, basic | $ | 0.53 | $ | 3.09 | $ | 3.51 | ||||
Earnings per common share, diluted | $ | 0.53 | $ | 3.06 | $ | 3.48 | ||||
_____________________ | ||||||||||
-1 | For the year ended December 31, 2013, amount includes a decrease of $0.04 million in preferred stock dividends for preferred stock dividends accumulated. There were no accumulated dividend adjustments for the years ended December 31, 2014 or 2012. | |||||||||
For the year ended December 31, 2014, the diluted earnings per share calculation excludes (i) the dilutive effect of 803,902 incremental shares of restricted stock that did not meet its market-based vesting criteria as of December 31, 2014, and (ii) the anti-dilutive effect of 791 common shares for stock options that were out-of-the-money. For the year ended December 31, 2013, the diluted earnings per share calculation excludes the dilutive effect of (i) 173,778 incremental shares of restricted stock that did not meet its market-based vesting criteria as of December 31, 2013, and (ii) 8,689 common shares for stock options that were out-of-the-money. For the year ended December 31, 2012, the diluted earnings per share calculation excludes (i) the dilutive effect of 141,807 incremental shares of restricted stock that did not meet its market-based vesting criteria as of December 31, 2012, and (ii) the anti-dilutive effect of 7,720 common shares for stock options that were out-of-the-money. | ||||||||||
RELATED_PARTY_TRANSACTIONS
RELATED PARTY TRANSACTIONS | 12 Months Ended | ||||||
Dec. 31, 2014 | |||||||
RELATED PARTY TRANSACTIONS [Abstract] | |||||||
RELATED PARTY TRANSACTIONS | 12. RELATED PARTY TRANSACTIONS | ||||||
Whiting USA Trust I—As a result of Whiting’s retained ownership of 15.8%, or 2,186,389 units in Whiting USA Trust I, it is a related party of the Company. The following table summarizes the related party receivable and payable balances between the Company and Trust I as of December 31, 2014 and 2013 (in thousands): | |||||||
December 31, | |||||||
2014 | 2013 | ||||||
Assets | |||||||
Unit distributions due from Trust I (1) | $ | 652 | $ | 1,093 | |||
Liabilities | |||||||
Unit distributions payable to Trust I (2) | $ | 4,133 | $ | 6,932 | |||
_____________________ | |||||||
-1 | This amount represents Whiting’s 15.8% interest in the net proceeds due from Trust I and is included within accounts receivable trade, net in the Company’s consolidated balance sheets. | ||||||
-2 | This amount represents net proceeds from Trust I’s underlying properties that the Company has received between the last Trust I distribution date and December 31, 2014 and 2013, respectively, but which the Company has not yet distributed to Trust I as of December 31, 2014 and 2013, respectively. Due to ongoing processing of Trust I revenues and expenses after December 31, 2014 and 2013, the amount of Whiting’s next scheduled distribution to Trust I, and the related distribution by Trust I to its unitholders, will differ from this amount. These amounts are included within accounts payable trade in the Company’s consolidated balance sheet. | ||||||
For the year ended December 31, 2014, Whiting paid $30 million, net of state tax withholdings, in unit distributions to Trust I and received $5 million in distributions back from Trust I pursuant to its retained ownership in 2,186,389 Trust I units. | |||||||
On January 28, 2015, the net profits interest that Whiting conveyed to Trust I terminated as a result of 9.11 MMBOE (which amount is equivalent to 8.20 MMBOE attributable to the net profits interest) having been produced and sold from the underlying properties. Upon termination, the net profits interest in the underlying properties reverted back to Whiting, and Trust I will no longer be a related party. | |||||||
Tax Sharing Liability—Prior to Whiting’s initial public offering in November 2003, it was a wholly-owned indirect subsidiary of Alliant Energy Corporation (“Alliant Energy”), and when the transactions discussed below were entered into, Alliant Energy was a related party of the Company. As of December 31, 2004 and thereafter, Alliant Energy was no longer a related party. | |||||||
In 2003, the Company entered into a Tax Separation and Indemnification Agreement with Alliant Energy, whereby the Company and Alliant Energy made certain tax elections with the effect that the tax bases of Whiting’s assets were increased. Such additional tax bases have resulted in increased income tax deductions for Whiting and, accordingly, have reduced income taxes otherwise payable by Whiting. Under this Tax Separation and Indemnification Agreement, the Company agreed to pay to Alliant Energy (each year from 2004 to 2013) 90% of the tax benefits the Company realized annually as a result of this step-up in tax bases. In 2014, Whiting was obligated to pay Alliant the present value of 90% of the remaining tax benefits expected to result from its increased tax bases, which payout assumes all such tax benefits will be realized in future years. | |||||||
In March 2014, the Company made the final payment due Alliant Energy under this agreement totaling $26 million, including $3 million of interest. During 2013 and 2012, the Company made payments of $2 million each year under this agreement and recognized interest expense of $3 million and $2 million, respectively. | |||||||
Alliant Energy Guarantee—The Company holds a 6% working interest in three offshore platforms in California and the related onshore plant and equipment. Alliant Energy has guaranteed the Company’s obligation in the abandonment of these assets. | |||||||
COMMITMENTS_AND_CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 12 Months Ended | |||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||
COMMITMENTS AND CONTINGENCIES [Abstract] | ||||||||||||||||||||||
COMMITMENTS AND CONTINGENCIES | 13. COMMITMENTS AND CONTINGENCIES | |||||||||||||||||||||
The table below shows the Company’s minimum future payments under non-cancelable operating leases and unconditional purchase obligations as of December 31, 2014 (in thousands): | ||||||||||||||||||||||
Payments due by period | ||||||||||||||||||||||
2015 | 2016 | 2017 | 2018 | 2019 | Thereafter | Total | ||||||||||||||||
Non-cancelable leases | $ | 7,692 | $ | 7,547 | $ | 6,610 | $ | 6,693 | $ | 5,844 | $ | 216 | $ | 34,602 | ||||||||
Drilling rig contracts | 146,141 | 101,855 | 30,788 | - | - | - | 278,784 | |||||||||||||||
Pipeline transportation agreements | 5,948 | 9,722 | 9,559 | 9,559 | 9,559 | 50,091 | 94,438 | |||||||||||||||
Total | $ | 159,781 | $ | 119,124 | $ | 46,957 | $ | 16,252 | $ | 15,403 | $ | 50,307 | $ | 407,824 | ||||||||
Non-cancelable Leases—The Company leases 197,000 square feet of administrative office space in Denver, Colorado under an operating lease arrangement expiring in 2019, 47,900 square feet of office space in Midland, Texas expiring in 2020, an additional 36,300 square feet of administrative office space in Denver, Colorado assumed in the Kodiak Acquisition expiring in 2016, and 20,000 square feet of office space in Dickinson, North Dakota expiring in 2016. In addition, the Company entered into a lease for several residential apartments in Watford City and Dickinson, North Dakota under an operating lease arrangement expiring in 2015. Rental expense for 2014, 2013 and 2012 amounted to $7 million, $5 million and $6 million, respectively. Minimum lease payments under the terms of non-cancelable operating leases as of December 31, 2014 are shown in the table above. | ||||||||||||||||||||||
Drilling Rig Contracts—As of December 31, 2014, the Company had 18 drilling rigs under long-term contract, all of which were operating in the Rocky Mountains region. Subsequent to December 31, 2014, the Company early terminated five of these long-term contracts incurring early termination penalties totaling approximately $27 million. These penalties and the Company’s minimum drilling commitments under the terms of the 18 long-term drilling rig contracts as of December 31, 2014 are shown in the table above. Of the remaining 13 long-term contracts, seven expire in 2016 and six in 2017. Early termination of the remaining contracts would require termination penalties of $212 million, which would be in lieu of paying the remaining drilling commitments under these contracts. No other drilling rigs working for the Company are currently under long-term contracts or contracts that cannot be terminated at the end of the well that is currently being drilled. During 2014, 2013 and 2012, the Company made payments of $106 million, $93 million and $101 million, respectively, under these long-term contracts, which are initially capitalized as a component of oil and gas properties and either depleted in future periods or written off as exploration expense. | ||||||||||||||||||||||
Pipeline Transportation Agreements—The Company has two ship-or-pay agreements with different suppliers, one expiring in 2015 and one expiring in 2017, whereby it has committed to transport a minimum daily volume of CO2 or water, as the case may be, via certain pipelines or else pay for any deficiencies at a price stipulated in the contracts. Although minimum daily quantities are specified in the agreements, the actual CO2 or water volumes transported and their corresponding unit prices are variable over the term of the contracts. As a result, the future minimum payments for each of the five succeeding fiscal years are not fixed and determinable and are not therefore included in the table above. As of December 31, 2014, the Company estimated future commitments under these ship-or-pay agreements to approximate $20 million through 2017. | ||||||||||||||||||||||
In addition, the Company has three pipeline transportation agreements, one expiring in 2024 and two expiring in 2025, whereby it has committed to pay monthly reservation fees on dedicated pipelines for natural gas and NGL transportation capacity from the Redtail field, plus a variable charge based on actual transportation volumes. These fixed monthly reservation fees totaling approximately $94 million have been included in the table above. | ||||||||||||||||||||||
During 2014, 2013 and 2012, transportation of natural gas, CO2 and water under these contracts amounted to $13 million, $4 million and $3 million, respectively. As of December 31, 2014, the Company estimated future commitments under all of these pipeline transportation agreements to approximate $114 million through 2025. | ||||||||||||||||||||||
Purchase Contracts—The Company has three take-or-pay purchase agreements, of which one agreement expires in 2015 and two agreements expire in 2017. One of these agreements contains commitments to buy certain volumes of CO2 for use in its EOR project in the North Ward Estes field in Texas. Under the remaining two take-or-pay agreements, the Company has committed to buy certain volumes of water for use in the fracture stimulation process of wells in its Redtail field. Under the terms of these agreements, the Company is obligated to purchase a minimum volume of CO2 or water, as the case may be, or else pay for any deficiencies at the price stipulated in the contract. The CO2 volumes planned for use in the Company’s EOR project in the North Ward Estes field and the water volumes planned for use at our Redtail field currently exceed the minimum volumes specified in all of these agreements, therefore, the Company expects to avoid any payments for deficiencies under these contracts. During 2014, 2013 and 2012, purchases of CO2 and water amounted to $105 million, $84 million and $83 million, respectively. Although minimum daily quantities are specified in the agreements, the actual CO2 or water volumes purchased and their corresponding unit prices are variable over the term of the contracts. As a result, the future minimum payments for each of the five succeeding fiscal years are not fixed and determinable and are not therefore included in the table above. As of December 31, 2014, the Company estimated future commitments under all of these purchase agreements to approximate $149 million through 2017. | ||||||||||||||||||||||
Delivery Commitments—The Company has various physical delivery contracts which require the Company to deliver fixed volumes of crude oil. As of December 31, 2014, the Company had delivery commitments of 12.4 MMBbl, 17.8 MMBbl, 19.6 MMBbl, 21.5 MMBbl, 23.3 MMBbl and 6.0 MMBbl of crude oil for the years ended December 31, 2015 through 2020, respectively. These delivery commitments relate to crude oil production at Whiting’s Redtail field in the DJ Basin in Weld County, Colorado. As of December 31, 2014, the Company determined that it is no longer probable that future oil production from its Redtail field will be sufficient to meet the minimum volume requirements specified in these physical delivery contracts, and as a result, the Company expects to make periodic deficiency payments for any shortfalls in delivering the minimum committed volumes. The Company currently anticipates that it will under-deliver by a total of approximately 10.4 MMBbl over the duration of the contracts, which would require undiscounted aggregate deficiency payments of approximately $49 million over the next 5 years. The Company recognizes any monthly deficiency payments in the period in which the underdelivery takes place and the related liability has been incurred. The table above does not include any such deficiency payments that may be incurred under the Company’s physical delivery contracts, since it cannot be predicted with accuracy the amount and timing of any such penalties incurred. | ||||||||||||||||||||||
Litigation—The Company is subject to litigation, claims and governmental and regulatory proceedings arising in the ordinary course of business. We accrue a loss contingency for these lawsuits and claims when it is probable that a loss has been incurred and the amount of the loss can be reasonably estimated. Accordingly, no material amounts for loss contingencies associated with litigation, claims or assessments have been accrued at December 31, 2014 or 2013. While the outcome of these lawsuits and claims cannot be predicted with certainty, it is the opinion of the Company’s management that the loss for any litigation matters and claims that are reasonably possible to occur will not have a material adverse effect, individually or in the aggregate, on its consolidated financial position, cash flows or results of operations. | ||||||||||||||||||||||
SUBSEQUENT_EVENT
SUBSEQUENT EVENT | 12 Months Ended |
Dec. 31, 2014 | |
SUBSEQUENT EVENT [Abstract] | |
SUBSEQUENT EVENT | 14. SUBSEQUENT EVENT |
On January 7, 2015, as required under the Kodiak Indentures upon a change in control, Whiting offered to repurchase at 101% of par all $1,550 million principal amount of Kodiak Notes outstanding. The repurchase offer expires on March 3, 2015. The Company expects to fund any payments due as a result of such repurchase offer with borrowings under its revolving credit facility. | |
OIL_AND_GAS_ACTIVITIES
OIL AND GAS ACTIVITIES | 12 Months Ended | |||||||||
Dec. 31, 2014 | ||||||||||
OIL AND GAS ACTIVITIES [Abstract] | ||||||||||
OIL AND GAS ACTIVITIES | 15. OIL AND GAS ACTIVITIES | |||||||||
The Company’s oil and gas activities for 2014, 2013 and 2012 were entirely within the United States. Costs incurred in oil and gas producing activities were as follows (in thousands): | ||||||||||
Year Ended December 31, | ||||||||||
2014 | 2013 | 2012 | ||||||||
Development (1) | $ | 2,891,893 | $ | 2,132,824 | $ | 1,667,182 | ||||
Proved property acquisition (2) | 2,278,855 | 232,572 | 19,785 | |||||||
Unproved property acquisition (2) | 1,035,439 | 174,103 | 119,175 | |||||||
Exploration | 216,587 | 363,234 | 436,084 | |||||||
Total | $ | 6,422,774 | $ | 2,902,733 | $ | 2,242,226 | ||||
_____________________ | ||||||||||
-1 | During 2014, 2013 and 2012, non-cash additions to oil and gas properties of $45 million, $30 million and $36 million, respectively, which relate to estimated costs of the future plugging and abandonment of the Company’s oil and gas wells, are included in development costs in the table above. | |||||||||
-2 | During 2014, amounts include $2.3 billion of non-cash proved property additions and $1.0 billion of non-cash unproved property additions related to the Kodiak Acquisition. | |||||||||
Net capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands): | ||||||||||
Year Ended December 31, | ||||||||||
2014 | 2013 | |||||||||
Proved oil and gas properties | $ | 12,956,834 | $ | 9,196,845 | ||||||
Unproved oil and gas properties | 1,992,868 | 868,305 | ||||||||
Accumulated depletion | -3,003,270 | -2,645,841 | ||||||||
Oil and gas properties, net | $ | 11,946,432 | $ | 7,419,309 | ||||||
Exploratory well costs that are incurred and expensed in the same annual period have not been included in the table below. The net changes in capitalized exploratory well costs were as follows (in thousands): | ||||||||||
Year Ended December 31, | ||||||||||
2014 | 2013 | 2012 | ||||||||
Beginning balance at January 1 | $ | 85,378 | $ | 108,861 | $ | 90,519 | ||||
Additions to capitalized exploratory well costs pending the determination of proved reserves | 145,336 | 281,951 | 384,223 | |||||||
Reclassifications to wells, facilities and equipment based on the determination of proved reserves | -200,869 | -291,962 | -358,625 | |||||||
Capitalized exploratory well costs charged to expense | -15,552 | -13,472 | -7,256 | |||||||
Ending balance at December 31 | $ | 14,293 | $ | 85,378 | $ | 108,861 | ||||
At December 31, 2014, the Company had no costs capitalized for exploratory wells in progress for a period of greater than one year after the completion of drilling. | ||||||||||
DISCLOSURES_ABOUT_OIL_AND_GAS_
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES | 12 Months Ended | |||||||||
Dec. 31, 2014 | ||||||||||
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES [Abstract] | ||||||||||
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES | 16. DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) | |||||||||
For all years presented our independent petroleum engineers independently estimated all of the proved, probable and possible reserve quantities included in this annual report. In connection with our external petroleum engineers performing their independent reserve estimations, we furnish them with the following information that they review: (1) technical support data, (2) technical analysis of geologic and engineering support information, (3) economic and production data and (4) our well ownership interests. The independent petroleum engineers, Cawley, Gillespie & Associates, Inc., evaluated 100% of our estimated proved reserve quantities and their related pre-tax future net cash flows as of December 31, 2014. Proved reserve estimates included herein conform to the definitions prescribed by the SEC. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. | ||||||||||
As of December 31, 2014, all of the Company’s oil and gas reserves are attributable to properties within the United States. A summary of the Company’s changes in quantities of proved oil and gas reserves for the years ended December 31, 2012, 2013 and 2014 are as follows: | ||||||||||
Oil | NGLs | Natural Gas | Total | |||||||
(MBbl) | (MBbl) | (MMcf) | (MBOE) | |||||||
Balance—January 1, 2012 | 260,144 | 37,609 | 284,975 | 345,249 | ||||||
Extensions and discoveries | 68,134 | 6,526 | 40,915 | 81,479 | ||||||
Sales of minerals in place | -7,960 | -320 | -13,987 | -10,611 | ||||||
Production | -23,139 | -2,766 | -25,827 | -30,209 | ||||||
Revisions to previous estimates | 4,106 | -951 | -61,812 | -7,148 | ||||||
Balance—December 31, 2012 | 301,285 | 40,098 | 224,264 | 378,760 | ||||||
Extensions and discoveries | 88,293 | 9,830 | 63,893 | 108,772 | ||||||
Sales of minerals in place | -36,992 | -4,777 | -12,411 | -43,838 | ||||||
Purchases of minerals in place | 14,543 | 1,311 | 7,751 | 17,146 | ||||||
Production | -27,035 | -2,821 | -26,917 | -34,342 | ||||||
Revisions to previous estimates | 7,327 | 1,228 | 20,934 | 12,044 | ||||||
Balance—December 31, 2013 | 347,421 | 44,869 | 277,514 | 438,542 | ||||||
Extensions and discoveries | 146,122 | 12,947 | 94,452 | 174,811 | ||||||
Sales of minerals in place | -1,642 | - | -2,925 | -2,130 | ||||||
Purchases of minerals in place | 169,586 | - | 156,140 | 195,609 | ||||||
Production | -33,485 | -3,283 | -30,218 | -41,804 | ||||||
Revisions to previous estimates | 15,627 | 151 | -2,943 | 15,288 | ||||||
Balance—December 31, 2014 | 643,629 | 54,684 | 492,020 | 780,316 | ||||||
Proved developed reserves: | ||||||||||
31-Dec-11 | 180,975 | 22,109 | 211,297 | 238,300 | ||||||
31-Dec-12 | 190,845 | 24,204 | 160,893 | 241,864 | ||||||
31-Dec-13 | 198,204 | 23,721 | 183,129 | 252,446 | ||||||
31-Dec-14 | 333,593 | 28,935 | 298,237 | 412,234 | ||||||
Proved undeveloped reserves: | ||||||||||
31-Dec-11 | 79,169 | 15,500 | 73,678 | 106,949 | ||||||
31-Dec-12 | 110,440 | 15,894 | 63,371 | 136,896 | ||||||
31-Dec-13 | 149,217 | 21,148 | 94,385 | 186,096 | ||||||
31-Dec-14 | 310,036 | 25,749 | 193,783 | 368,082 | ||||||
Notable changes in proved reserves for the year ended December 31, 2014 included: | ||||||||||
· | Extensions and discoveries. In 2014, total extensions and discoveries of 174.8 MMBOE were primarily attributable to successful drilling at the Redtail, Sanish, Hidden Bench, Missouri Breaks, Pronghorn, Tarpon and Cassandra fields. Both the new wells drilled in these areas as well as the PUD locations added as a result of drilling increased the Company’s proved reserves. | |||||||||
· | Sales of minerals in place. In 2014, total sales of minerals in place of 2.1 MMBOE were primarily attributable to the disposition of properties in the Big Tex prospect, further described in the Acquisitions and Divestitures footnote, as well as other property divestitures in the Lucky Ditch, Whiskey Springs and Bridger Lake fields, which decreased the Company’s proved reserves. | |||||||||
· | Purchases of minerals in place. In 2014, total purchases of minerals in place of 195.6 MMBOE were primarily attributable to the Kodiak Acquisition, whereby we acquired interests in 778 producing oil and gas wells and undeveloped acreage in the Williston Basin, further described in the Acquisitions and Divestitures footnote, which increased the Company’s proved reserves. | |||||||||
· | Revisions to previous estimates. In 2014, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 15.3 MMBOE. Included in these revisions were (i) 15.6 MMBOE of net upward adjustments attributable to reservoir analysis and well performance and (ii) 0.3 MMBOE of downward adjustments caused by lower crude oil prices incorporated into the Company’s reserve estimates at December 31, 2014 as compared to December 31, 2013. | |||||||||
Notable changes in proved reserves for the year ended December 31, 2013 included: | ||||||||||
· | Extensions and discoveries. In 2013, total extensions and discoveries of 108.8 MMBOE were primarily attributable to successful drilling in the Redtail, Sanish, Missouri Breaks, Hidden Bench and Pronghorn fields. The new producing wells in these areas and their related proved undeveloped locations added during the year increased the Company’s proved reserves. | |||||||||
· | Sales of minerals in place. In 2013, total sales of minerals in place of 43.8 MMBOE were primarily attributable to the disposition of the Postle Properties, further described in the Acquisitions and Divestitures footnote, which decreased the Company’s proved reserves. | |||||||||
· | Purchases of minerals in place. In 2013, total purchases of minerals in place of 17.1 MMBOE were primarily attributable to the acquisition of 121 producing oil and gas wells and undeveloped acreage in the Williston Basin, further described in the Acquisitions and Divestitures footnote, which increased the Company’s proved reserves. | |||||||||
· | Revisions to previous estimates. In 2013, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 12.0 MMBOE. Included in these revisions were (i) 4.9 MMBOE of upward adjustments caused by higher crude oil and natural gas prices incorporated into the Company’s reserve estimates at December 31, 2013 as compared to December 31, 2012 and (ii) 7.1 MMBOE of net upward adjustments attributable to reservoir analysis and well performance. | |||||||||
Notable changes in proved reserves for the year ended December 31, 2012 included: | ||||||||||
· | Extensions and discoveries. In 2012, total extensions and discoveries of 81.5 MMBOE were primarily attributable to successful drilling in the Sanish, Redtail, Missouri Breaks and Pronghorn fields. The new producing wells in these fields and their related proved undeveloped locations added during the year increased the Company’s proved reserves. | |||||||||
· | Revisions to previous estimates. In 2012, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 7.1 MMBOE. Included in these revisions were (i) 11.8 MMBOE of downward adjustments caused by lower crude oil and natural gas prices incorporated into the Company’s reserve estimates at December 31, 2012 as compared to December 31, 2011, and (ii) 4.7 MMBOE of net upward adjustments attributable to reservoir analysis and well performance. | |||||||||
As discussed in Deferred Compensation within these footnotes to the consolidated financial statements, the Company had a Production Participation Plan (the “Plan”) in which all employees participated. On June 11, 2014, the Board of Directors of the Company terminated the Plan effective December 31, 2013. The reserve disclosures above include oil and natural gas reserve volumes that were allocated to the Plan prior to its termination. Once allocated to Plan participants, the interests were fixed. Interest allocations prior to 1995 consisted of 2%–3% overriding royalty interests. Interest allocations after 1995 were 1.75%–5% of oil and gas sales less lease operating expenses and production taxes from the production allocated to the Plan. | ||||||||||
The standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves were prepared in accordance with the provisions of FASB ASC Topic 932, Extractive Activities—Oil and Gas. Future cash inflows as of December 31, 2014, 2013 and 2012 were computed by applying average fiscal-year prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period ended December 31, 2014, 2013 and 2012, respectively) to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year end, based on year-end costs and assuming the continuation of existing economic conditions. | ||||||||||
Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation does not necessarily result in an estimate of the fair value of the Company’s oil and gas properties. | ||||||||||
The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows (in thousands): | ||||||||||
December 31, | ||||||||||
2014 | 2013 | 2012 | ||||||||
Future cash flows | $ | 59,949,707 | $ | 35,178,399 | $ | 29,308,752 | ||||
Future production costs | -20,772,234 | -12,973,292 | -11,397,332 | |||||||
Future development costs | -7,924,573 | -5,355,383 | -3,181,618 | |||||||
Future income tax expense | -8,579,237 | -3,954,401 | -4,278,529 | |||||||
Future net cash flows | 22,673,663 | 12,895,323 | 10,451,273 | |||||||
10% annual discount for estimated timing of cash flows | -11,830,243 | -6,301,462 | -5,044,240 | |||||||
Standardized measure of discounted future net cash flows | $ | 10,843,420 | $ | 6,593,861 | $ | 5,407,033 | ||||
Future cash flows as shown above are reported without consideration for the effects of open hedge contracts at each period end. If the effects of hedging transactions were included in the computation, then undiscounted future cash inflows would have decreased by $7 million in 2014, would not have changed in 2013 and would have decreased by $20 million in 2012. | ||||||||||
The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows (in thousands): | ||||||||||
December 31, | ||||||||||
2014 | 2013 | 2012 | ||||||||
Beginning of year | $ | 6,593,861 | $ | 5,407,033 | $ | 5,272,492 | ||||
Sale of oil and gas produced, net of production costs | -2,274,682 | -2,010,925 | -1,589,665 | |||||||
Sales of minerals in place | -48,532 | -1,064,195 | -438,614 | |||||||
Net changes in prices and production costs | 81,522 | 902,916 | -1,061,495 | |||||||
Extensions, discoveries and improved recoveries | 3,950,413 | 2,827,321 | 3,708,780 | |||||||
Previously estimated development costs incurred during the period | 1,149,926 | 832,096 | 526,982 | |||||||
Changes in estimated future development costs | -3,382,849 | -1,264,189 | -1,498,592 | |||||||
Purchases of minerals in place | 4,420,417 | 445,669 | - | |||||||
Revisions of previous quantity estimates | 345,775 | 313,069 | -295,432 | |||||||
Net change in income taxes | -651,817 | -335,637 | 255,328 | |||||||
Accretion of discount | 659,386 | 540,703 | 527,249 | |||||||
End of year | $ | 10,843,420 | $ | 6,593,861 | $ | 5,407,033 | ||||
Future net revenues included in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves incorporate calculated weighted average sales prices (inclusive of adjustments for quality and location) in effect at December 31, 2014, 2013 and 2012 as follows: | ||||||||||
2014 | 2013 | 2012 | ||||||||
Oil (per Bbl) | $ | 84.69 | $ | 90.8 | $ | 87.15 | ||||
NGLs (per Bbl) | $ | 46.59 | $ | 54.38 | $ | 58.15 | ||||
Natural Gas (per Mcf) | $ | 5.88 | $ | 4.3 | $ | 3.21 | ||||
QUARTERLY_FINANCIAL_DATA
QUARTERLY FINANCIAL DATA | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
QUARTERLY FINANCIAL DATA [Abstract] | |||||||||||||
QUARTERLY FINANCIAL DATA | 17. QUARTERLY FINANCIAL DATA (UNAUDITED) | ||||||||||||
The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2014 and 2013 (in thousands, except per share data): | |||||||||||||
Three Months Ended | |||||||||||||
March 31, | June 30, | September 30, | December 31, | ||||||||||
2014 | 2014 | 2014 | 2014 | ||||||||||
Oil, NGL and natural gas sales | $ | 721,250 | $ | 825,760 | $ | 805,054 | $ | 672,553 | |||||
Operating profit (1) | $ | 311,169 | $ | 370,033 | $ | 326,215 | $ | 177,722 | |||||
Net income (loss) | $ | 109,051 | $ | 151,426 | $ | 157,961 | $ | -353,693 | |||||
Basic earnings (loss) per share | $ | 0.92 | $ | 1.27 | $ | 1.33 | $ | -2.69 | |||||
Diluted earnings (loss) per share | $ | 0.91 | $ | 1.26 | $ | 1.32 | $ | -2.68 | |||||
Three Months Ended | |||||||||||||
March 31, | June 30, | September 30, | December 31, | ||||||||||
2013 | 2013 | 2013 | 2013 | ||||||||||
Oil, NGL and natural gas sales | $ | 605,114 | $ | 651,868 | $ | 706,543 | $ | 703,024 | |||||
Operating profit (1) | $ | 252,806 | $ | 269,528 | $ | 316,764 | $ | 280,311 | |||||
Net income (loss) | $ | 86,244 | $ | 134,944 | $ | 204,091 | $ | -59,276 | |||||
Basic earnings (loss) per share | $ | 0.73 | $ | 1.14 | $ | 1.72 | $ | -0.5 | |||||
Diluted earnings (loss) per share | $ | 0.72 | $ | 1.14 | $ | 1.71 | $ | -0.5 | |||||
_____________________ | |||||||||||||
-1 | Oil, NGL and natural gas sales less lease operating expense, production taxes and depreciation, depletion and amortization. | ||||||||||||
SCHEDULE_I_CONDENSED_FINANCIAL
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT | 12 Months Ended | |||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT [Abstract] | ||||||||||||||||||||||
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT | SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT | |||||||||||||||||||||
WHITING PETROLEUM CORPORATION | ||||||||||||||||||||||
CONDENSED FINANCIAL STATEMENTS OF THE PARENT COMPANY | ||||||||||||||||||||||
CONDENSED BALANCE SHEETS | ||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||
December 31, | ||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||
ASSETS | ||||||||||||||||||||||
Current assets | $ | 3,859 | $ | 5,120 | ||||||||||||||||||
Investment in subsidiaries | 5,464,763 | 2,707,184 | ||||||||||||||||||||
Intercompany receivable | 2,907,270 | 3,796,321 | ||||||||||||||||||||
Total assets | $ | 8,375,892 | $ | 6,508,625 | ||||||||||||||||||
LIABILITIES AND EQUITY | ||||||||||||||||||||||
Current liabilities | $ | 27,738 | $ | 26,054 | ||||||||||||||||||
Long-term debt | 2,653,180 | 2,653,834 | ||||||||||||||||||||
Other long-term liabilities | - | 170 | ||||||||||||||||||||
Shareholders’ equity | 5,694,974 | 3,828,567 | ||||||||||||||||||||
Total liabilities and equity | $ | 8,375,892 | $ | 6,508,625 | ||||||||||||||||||
CONDENSED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME | ||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||
OPERATING EXPENSES: | ||||||||||||||||||||||
General and administrative | $ | -1,010 | $ | -1,131 | $ | -16,506 | ||||||||||||||||
Interest expense | -1,864 | -2,922 | -2,168 | |||||||||||||||||||
Equity in earnings of subsidiaries | 66,100 | 361,732 | 425,870 | |||||||||||||||||||
INCOME BEFORE INCOME TAXES | 63,226 | 357,679 | 407,196 | |||||||||||||||||||
Income tax benefit | 1,581 | 8,376 | 6,993 | |||||||||||||||||||
NET INCOME | $ | 64,807 | $ | 366,055 | $ | 414,189 | ||||||||||||||||
COMPREHENSIVE INCOME | $ | 64,807 | $ | 366,055 | $ | 414,189 | ||||||||||||||||
See notes to condensed financial statements. | ||||||||||||||||||||||
Schedule I | ||||||||||||||||||||||
WHITING PETROLEUM CORPORATION | ||||||||||||||||||||||
CONDENSED FINANCIAL STATEMENTS OF THE PARENT COMPANY | ||||||||||||||||||||||
CONDENSED STATEMENTS OF CASH FLOWS | ||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||
CASH FLOWS PROVIDED BY OPERATING ACTIVITIES | $ | - | $ | - | $ | 16,423 | ||||||||||||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||||||||||||||||
Investment in subsidiaries | - | - | - | |||||||||||||||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||||||||||||||||
Intercompany receivable | 26,373 | -2,048,253 | -14,094 | |||||||||||||||||||
Issuance of 5% Senior Notes due 2019 | - | 1,100,000 | - | |||||||||||||||||||
Issuance of 5.75% Senior Notes due 2021 | - | 1,204,000 | - | |||||||||||||||||||
Redemption of 7% Senior Subordinated Notes due 2014 | - | -253,988 | - | |||||||||||||||||||
Repayment of tax sharing liability | -26,373 | -1,759 | -2,329 | |||||||||||||||||||
Net cash used in financing activities | - | - | -16,423 | |||||||||||||||||||
NET CHANGE IN CASH AND CASH EQUIVALENTS | - | - | - | |||||||||||||||||||
CASH AND CASH EQUIVALENTS: | ||||||||||||||||||||||
Beginning of period | - | - | - | |||||||||||||||||||
End of period | $ | - | $ | - | $ | - | ||||||||||||||||
NONCASH INVESTING AND FINANCING ACTIVITIES: | ||||||||||||||||||||||
Fair value of equity issued in the Kodiak Acquisition | $ | 2,696,094 | $ | - | $ | - | ||||||||||||||||
Distributions from Whiting USA Trust I | $ | 4,614 | $ | 4,749 | $ | 5,827 | ||||||||||||||||
Preferred stock dividends paid | $ | - | $ | -538 | $ | -1,077 | ||||||||||||||||
See notes to condensed financial statements. | ||||||||||||||||||||||
WHITING PETROLEUM CORPORATION | ||||||||||||||||||||||
NOTES TO CONDENSED FINANCIAL STATEMENTS OF THE PARENT COMPANY | ||||||||||||||||||||||
1. BASIS OF PRESENTATION | ||||||||||||||||||||||
Condensed Financial Statements—The condensed financial statements of Whiting Petroleum Corporation (the “Registrant” or “Parent Company”) do not include all of the information and notes normally included with financial statements prepared in accordance with GAAP. These condensed financial statements, therefore, should be read in conjunction with the consolidated financial statements and notes thereto of the Registrant, included elsewhere in this Annual Report on Form 10-K. For purposes of these condensed financial statements, the Parent Company’s investments in wholly-owned subsidiaries are accounted for under the equity method. | ||||||||||||||||||||||
Restricted Assets of Registrant—Except for limited exceptions, including the payment of interest on the senior notes and senior subordinated notes, Whiting Oil and Gas Corporation’s (“Whiting Oil and Gas”) credit agreement restricts the ability of Whiting Oil and Gas to make any dividend payments, distributions or other payments to the Parent Company. As of December 31, 2014, total restricted net assets were $6.9 billion. Accordingly, these condensed financial statements have been prepared pursuant to Rule 5-04 of Regulation S-X of the Securities Exchange Act of 1934, as amended. | ||||||||||||||||||||||
2. LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES | ||||||||||||||||||||||
The Parent Company’s long-term debt and other long-term liabilities consisted of the following at December 31, 2014 and 2013 (in thousands): | ||||||||||||||||||||||
December 31, | ||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||
Long-term debt: | ||||||||||||||||||||||
6.5% Senior Subordinated Notes due 2018 | $ | 350,000 | $ | 350,000 | ||||||||||||||||||
5% Senior Notes due 2019 | 1,100,000 | 1,100,000 | ||||||||||||||||||||
5.75% Senior Notes due 2021, including unamortized debt premium of $3,180 and $3,834, respectively | 1,203,180 | 1,203,834 | ||||||||||||||||||||
Other long-term liabilities | - | 170 | ||||||||||||||||||||
Total long-term debt and other long-term liabilities | $ | 2,653,180 | $ | 2,654,004 | ||||||||||||||||||
Scheduled maturities of the Parent Company’s principal amounts of long-term debt and other long-term liabilities (including the current portions thereof) as of December 31, 2014 were as follows (in thousands): | ||||||||||||||||||||||
2015 | 2016 | 2017 | 2018 | 2019 | Thereafter | Total | ||||||||||||||||
Amounts due | $ | - | $ | - | $ | - | $ | 350,000 | $ | 1,100,000 | $ | 1,200,000 | $ | 2,650,000 | ||||||||
For further information on the Senior Subordinated Notes, Senior Notes and tax sharing liability, refer to the Long-Term Debt and Related Party Transactions notes to the consolidated financial statements of the Registrant. | ||||||||||||||||||||||
3. SHAREHOLDERS’ EQUITY | ||||||||||||||||||||||
6.25% Convertible Perpetual Preferred Stock—In June 2009, the Parent Company completed a public offering of 6.25% convertible perpetual preferred stock (“preferred stock”), selling 3,450,000 shares at a price of $100.00 per share. As a result of voluntary conversions and the Parent Company exercising its right to mandatorily convert shares of preferred stock effective June 27, 2013, all 172,129 remaining shares of preferred stock outstanding on March 31, 2013, were converted into 792,919 shares of common stock. As of December 31, 2014, no shares of preferred stock remained outstanding. | ||||||||||||||||||||||
For further information on the convertible perpetual preferred stock, refer to the Shareholders’ Equity note to the consolidated financial statements of the Registrant. | ||||||||||||||||||||||
SUMMARY_OF_SIGNIFICANT_ACCOUNT1
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 12 Months Ended | ||||||
Dec. 31, 2014 | |||||||
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES [Abstract] | |||||||
Basis of Presentation of Consolidated Financial Statements | Basis of Presentation of Consolidated Financial Statements—The consolidated financial statements include the accounts of Whiting Petroleum Corporation, its consolidated subsidiaries and Whiting’s pro rata share of the accounts of Whiting USA Trust I (“Trust I”) pursuant to Whiting’s 15.8% ownership interest in Trust I. Investments in entities which give Whiting significant influence, but not control, over the investee are accounted for using the equity method. Under the equity method, investments are stated at cost plus the Company’s equity in undistributed earnings and losses. All intercompany balances and transactions have been eliminated upon consolidation. | ||||||
Use of Estimates | Use of Estimates—The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Items subject to such estimates and assumptions include (1) oil and natural gas reserves; (2) cash flow estimates used in impairment tests of long-lived assets; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations, including the determination of any resulting goodwill; (6) income taxes; (7) accrued liabilities; (8) valuation of derivative instruments; and (9) accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ from these estimates. | ||||||
Cash and Cash Equivalents | Cash and Cash Equivalents—Cash equivalents consist of demand deposits and highly liquid investments which have an original maturity of three months or less. | ||||||
Accounts Receivable Trade | Accounts Receivable Trade—Whiting’s accounts receivable trade consist mainly of receivables from oil and gas purchasers and joint interest owners on properties the Company operates. For receivables from joint interest owners, Whiting typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Generally, the Company’s oil and gas receivables are collected within two months, and to date, the Company has had minimal bad debts. | ||||||
The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectability. At December 31, 2014 and 2013, the Company had an allowance for doubtful accounts of $9 million and $4 million, respectively. | |||||||
Inventories | Inventories—Materials and supplies inventories consist primarily of tubular goods and production equipment, carried at weighted-average cost. Materials and supplies are included in other property and equipment. Crude oil in tanks inventory is carried at the lower of the estimated cost to produce or market value and is included in prepaid expenses and other. | ||||||
Oil and Gas Properties | Oil and Gas Properties | ||||||
Proved. The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method of accounting, all property acquisition costs and development costs are capitalized when incurred and depleted on a units-of-production basis over the remaining life of proved reserves and proved developed reserves, respectively. Costs of drilling exploratory wells are initially capitalized but are charged to expense if the well is determined to be unsuccessful. | |||||||
The Company assesses its proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable. The impairment test compares undiscounted future net cash flows to the assets’ net book value. If the net capitalized costs exceed future net cash flows, then the cost of the property is written down to fair value. Fair value for oil and gas properties is generally determined based on discounted future net cash flows. Impairment expense for proved properties is reported in exploration and impairment expense. | |||||||
Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable property are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in income. Gains or losses from the disposal of complete units of depreciable property are recognized to earnings. | |||||||
Interest cost is capitalized as a component of property cost for development projects that require greater than six months to be readied for their intended use. During 2014, 2013 and 2012, the Company capitalized interest of $4 million, $2 million and $3 million, respectively. | |||||||
Unproved. Unproved properties consist of costs to acquire undeveloped leases as well as purchases of unproved reserves. Undeveloped lease costs and unproved reserve acquisitions are capitalized, and individually insignificant unproved properties are amortized on a composite basis, based on past success, past experience and average lease-term lives. The Company evaluates significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. When successful wells are drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit-of-production basis. Impairment expense for unproved properties is reported in exploration and impairment expense. | |||||||
Exploratory. Geological and geophysical costs, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage 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. Amounts of seismic costs capitalized are based on only those blocks of data used in determining development well locations. To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense. | |||||||
Costs of drilling exploratory wells are initially capitalized, pending determination of whether the well has found proved reserves. If an exploratory well has not found proved reserves, the costs of drilling the well and other associated costs are charged to expense. Cost incurred for exploratory wells that find reserves, which cannot yet be classified as proved, continue to be capitalized if (a) the well has found a sufficient quantity of reserves to justify completion as a producing well, and (b) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not met, or if the Company obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well costs, net of any salvage value, are expensed. | |||||||
Enhanced recovery activities. The Company carries out tertiary recovery methods on certain of its oil and gas properties in order to recover additional hydrocarbons that are not recoverable from primary or secondary recovery methods. Acquisition costs of tertiary injectants, such as purchased CO2, for EOR activities that are used during a project’s pilot phase, or prior to a project’s technical and economic viability (i.e. prior to the recognition of proved tertiary recovery reserves) are expensed as incurred. After a project has been determined to be technically feasible and economically viable, all acquisition costs of tertiary injectants are capitalized as development costs and depleted, as they are incurred solely for obtaining access to reserves not otherwise recoverable and have future economic benefits over the life of the project. As CO2 is recovered together with oil and gas production, it is extracted and re-injected, and all the associated CO2 recycling costs are expensed as incurred. Likewise costs incurred to maintain reservoir pressure are also expensed. | |||||||
Other Property and Equipment | Other Property and Equipment—Other property and equipment consists of (i) materials and supplies inventories, (ii) leasehold costs and development costs of our CO2 source properties and (iii) other property and equipment including, furniture and fixtures, buildings, leasehold improvements and automobiles, which are stated at cost and depreciated using the straight-line method over their estimated useful lives ranging from 4 to 30 years. | ||||||
Goodwill | Goodwill—Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in a business combination. Goodwill has an indefinite useful life and is not amortized, but rather is tested by the Company for impairment annually in the second quarter or when events or changes in circumstances indicate that the fair value of a reporting unit has been reduced below its carrying value. If the Company’s qualitative analysis indicates that it is more likely than not that the fair value of the reporting unit is less than its carrying value, the Company then performs a quantitative impairment test. If the carrying value of the reporting unit exceeds its fair value, goodwill is written down to its implied fair value with an offsetting charge to earnings. | ||||||
Debt Issuance Costs | Debt Issuance Costs—Debt issuance costs related to the Company’s Senior Notes and Senior Subordinated Notes are amortized to interest expense using the effective interest method over the term of the related debt. Debt issuance costs related to the credit facility are amortized to interest expense on a straight-line basis over the borrowing term. | ||||||
Derivative Instruments | Derivative Instruments—The Company enters into derivative contracts, primarily costless collars and swap contracts, to manage its exposure to commodity price risk. All derivative instruments, other than those that meet the “normal purchase normal sale” exclusion, are recorded on the balance sheet as either an asset or liability measured at fair value. Gains and losses from changes in the fair value of derivative instruments are recognized immediately in earnings, unless the derivative meets specific hedge accounting criteria, and the derivative has been designated as a hedge. Effective April 1, 2009, however, the Company elected to discontinue all hedge accounting prospectively, and as of December 31, 2013, all amounts related to de-designated cash flow hedges had been reclassified into earnings. | ||||||
Cash flows from derivatives used to manage commodity price risk are classified in operating activities along with the cash flows of the underlying hedged transactions. The Company does not enter into derivative instruments for speculative or trading purposes. | |||||||
Asset Retirement Obligations and Environmental Costs | Asset Retirement Obligations and Environmental Costs—Asset retirement obligations relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred (typically when a well is completed or acquired or an asset is installed at the production location), and the cost of such liability increases the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period through charges to depreciation, depletion and amortization expense, and the capitalized cost is depleted on a units-of-production basis over the proved developed reserves of the related asset. Revisions to estimated retirement obligations result in adjustments to the related capitalized asset and corresponding liability. | ||||||
Liabilities for environmental costs are recorded on an undiscounted basis when it is probable that obligations have been incurred and the amounts can be reasonably estimated. These liabilities are not reduced by possible recoveries from third parties. | |||||||
Deferred Gain On Sales | Deferred Gain on Sale—The deferred gain on sale relates to the sale of 11,677,500 Trust I units and 18,400,000 Whiting USA Trust II (“Trust II”) units, and is amortized to income based on the units-of-production method. | ||||||
Revenue Recognition | Revenue Recognition—Oil and gas revenues are recognized when production volumes are sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, persuasive evidence of a sales arrangement exists and collectability of the revenue is probable. Revenues from the production of gas properties in which the Company has an interest with other producers are recognized on the basis of the Company’s net working interest (entitlement method). Net deliveries in excess of entitled amounts are recorded as liabilities, while net under deliveries are reflected as receivables. The Company’s aggregate imbalance positions as of December 31, 2014 and 2013 were not significant. | ||||||
Taxes collected and remitted to governmental agencies on behalf of customers are not included in revenues or costs and expenses. | |||||||
General and Administrative Expenses | General and Administrative Expenses—General and administrative expenses are reported net of reimbursements of overhead costs that are allocated to working interest owners which participate in oil and gas properties operated by Whiting. | ||||||
Acquisition Cost | Acquisition Costs—Acquisition related expenses, which consist of external costs directly related to the Company’s acquisitions, such as advisory, legal, accounting, valuation and other professional fees, are expensed as incurred. | ||||||
Maintenance and Repairs | Maintenance and Repairs—Maintenance and repair costs which do not extend the useful lives of property and equipment are charged to expense as incurred. Major replacements, renewals and betterments are capitalized. | ||||||
Income Taxes | Income Taxes—Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are accounted for using the liability method. Under this method, deferred tax assets and liabilities are determined by applying the enacted statutory tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the Company’s financial statements. 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 established when it is more likely than not that some portion of the benefit from deferred tax assets will not be realized. The Company’s uncertain tax positions must meet a more-likely-than-not realization threshold to be recognized, and any potential accrued interest and penalties related to unrecognized tax benefits are recognized within income tax expense. | ||||||
Earnings Per Share | Earnings Per Share—Basic earnings per common share is calculated by dividing net income available to common shareholders by the weighted average number of common shares outstanding during each period. Diluted earnings per common share is calculated by dividing adjusted net income available to common shareholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the diluted earnings per share calculations consist of unvested restricted stock awards and outstanding stock options using the treasury method, as well as convertible perpetual preferred stock using the if-converted method. In the computation of diluted earnings per share, excess tax benefits that would be created upon the assumed vesting of unvested restricted shares or the assumed exercise of stock options (i.e. hypothetical excess tax benefits) are included in the assumed proceeds component of the treasury share method to the extent that such excess tax benefits are more likely than not to be realized. When a loss from continuing operations exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. | ||||||
Industry Segment and Geographic Information | Industry Segment and Geographic Information—The Company has evaluated how it is organized and managed and has identified only one operating segment, which is the exploration and production of crude oil, NGLs and natural gas. The Company considers its gathering, processing and marketing functions as ancillary to its oil and gas producing activities. All of the Company’s operations and assets are located in the United States, and substantially all of its revenues are attributable to United States customers. | ||||||
Concentration of Credit Risk | Concentration of Credit Risk—Whiting is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy related industries. The creditworthiness of customers and other counterparties is subject to continuing review. The following table presents the percentages by purchaser that accounted for 10% or more of the Company’s total oil, NGL and natural gas sales for the years ended December 31, 2014, 2013 and 2012: | ||||||
2014 | 2013 | 2012 | |||||
Plains Marketing LP | 17% | 21% | 20% | ||||
Shell Trading US | 10% | 14% | 14% | ||||
Bridger Trading LLC | 10% | 8% | 11% | ||||
Eighty Eight Oil Company | 6% | 11% | 11% | ||||
Commodity derivative contracts held by the Company are with seven counterparties, all of which are participants in Whiting’s credit facility as well, and all of which have investment-grade ratings from Moody’s and Standard & Poor. As of December 31, 2014, outstanding derivative contracts with Wells Fargo Bank, N.A., JP Morgan Chase Bank, N.A. and Canadian Imperial Bank of Commerce represented 34%, 28% and 13%, respectively, of total crude oil volumes hedged. | |||||||
Reclassifications | Reclassifications—Certain prior period balances in the consolidated balance sheets have been reclassified to conform to the current year presentation. Such reclassifications had no impact on net income, cash flows or shareholders’ equity previously reported. | ||||||
Adopted and Recently Issued Accounting Pronouncements | Adopted and Recently Issued Accounting Pronouncements—In February 2013, the FASB issued Accounting Standards Update No. 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“ASU 2013-04”). The objective of ASU 2013-04 is to provide guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date. ASU 2013-04 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The Company adopted ASU 2013-04 effective January 1, 2014, which did not have an impact on the Company’s consolidated financial statements. | ||||||
In July 2013, the FASB issued Accounting Standards Update No. 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (“ASU 2013-11”). The objective of ASU 2013-11 is to provide guidance on financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. ASU 2013-11 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The Company adopted ASU 2013-11 effective January 1, 2014, which did not have an impact on the Company’s consolidated financial statements, other than insignificant balance sheet reclassifications. | |||||||
In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014‑09”). The objective of ASU 2014-09 is to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards. ASU 2014‑09 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. The Company is currently evaluating the impact of adopting ASU 2014‑09, but the standard is not expected to have a significant effect on its consolidated financial statements. | |||||||
In August 2014, the FASB issued Accounting Standards Update No. 2014-15, Presentation of Financial Statements – Going Concern (“ASU 2014-15”). The objective of ASU 2014-15 is to provide guidance on management’s responsibility to evaluate whether there is substantial doubt about a company’s ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for fiscal years ending after December 15, 2016, and annual and interim periods thereafter. This standard is not expected to have an impact on the Company’s consolidated financial statements. | |||||||
FAIR_VALUE_MEASUREMENTS_Policy
FAIR VALUE MEASUREMENTS (Policy) | 12 Months Ended |
Dec. 31, 2014 | |
FAIR VALUE MEASUREMENTS [Abstract] | |
Fair Value of Financial Instruments | Cash and cash equivalents, accounts receivable and payable are carried at cost, which approximates their fair value because of the short-term maturity of these instruments. The Company’s credit agreement has a recorded value that approximates its fair value since its variable interest rate is tied to current market rates. The Company’s Senior Notes (including the Kodiak Notes) and Senior Subordinated Notes are recorded at cost, and the fair values of these instruments are included in the Long-Term Debt footnote. The Company’s derivative financial instruments are recorded at fair value and include a measure of the Company’s own nonperformance risk or that of its counterparties as appropriate. |
SUMMARY_OF_SIGNIFICANT_ACCOUNT2
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables) | 12 Months Ended | ||||||
Dec. 31, 2014 | |||||||
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES [Abstract] | |||||||
Percentages of total oil and gas sales to significant purchasers | |||||||
2014 | 2013 | 2012 | |||||
Plains Marketing LP | 17% | 21% | 20% | ||||
Shell Trading US | 10% | 14% | 14% | ||||
Bridger Trading LLC | 10% | 8% | 11% | ||||
Eighty Eight Oil Company | 6% | 11% | 11% | ||||
OIL_AND_GAS_PROPERTIES_Tables
OIL AND GAS PROPERTIES (Tables) | 12 Months Ended | ||||||
Dec. 31, 2014 | |||||||
OIL AND GAS PROPERTIES [Abstract] | |||||||
Net capitalized costs related to oil and gas producing activities | |||||||
December 31, | |||||||
2014 | 2013 | ||||||
Proved leasehold costs | $ | 3,637,026 | $ | 1,633,495 | |||
Unproved leasehold costs | 1,232,040 | 372,298 | |||||
Costs of completed wells and facilities | 9,319,808 | 7,563,350 | |||||
Wells and facilities in progress | 760,828 | 496,007 | |||||
Total oil and gas properties, successful efforts method | 14,949,702 | 10,065,150 | |||||
Accumulated depletion | -3,003,270 | -2,645,841 | |||||
Oil and gas properties, net | $ | 11,946,432 | $ | 7,419,309 | |||
ACQUISITIONS_AND_DIVESTITURES_
ACQUISITIONS AND DIVESTITURES (Tables) | 12 Months Ended | ||||||
Dec. 31, 2014 | |||||||
Williston Basin [Member] | |||||||
Significant Acquisitions and Disposals [Line Items] | |||||||
Assets acquired and liabilities assumed | |||||||
Purchase price | $ | 255,537 | |||||
Allocation of purchase price: | |||||||
Oil and gas properties, successful efforts method: | |||||||
Proved properties | $ | 229,002 | |||||
Unproved properties | 27,335 | ||||||
Oil in tank inventory | 522 | ||||||
Accounts receivable | 578 | ||||||
Asset retirement obligations | -1,900 | ||||||
Total | $ | 255,537 | |||||
Kodiak [Member] | |||||||
Significant Acquisitions and Disposals [Line Items] | |||||||
Assets acquired and liabilities assumed | |||||||
Consideration: | |||||||
Fair value of Whiting’s common stock issued (1) | $ | 1,771,094 | |||||
Fair value of Kodiak restricted stock units assumed by Whiting (2) | 9,596 | ||||||
Fair value of Kodiak options assumed by Whiting | 7,523 | ||||||
Total consideration | $ | 1,788,213 | |||||
Fair value of liabilities assumed: | |||||||
Accounts payable trade | $ | 18,390 | |||||
Accrued capital expenditures | 104,509 | ||||||
Revenues and royalties payable | 57,423 | ||||||
Accrued liabilities and other | 45,695 | ||||||
Taxes payable | 12,676 | ||||||
Accrued interest | 18,070 | ||||||
Current deferred tax liability | 30,279 | ||||||
Long-term debt | 2,500,875 | ||||||
Asset retirement obligations | 8,646 | ||||||
Other long-term liabilities | 15,735 | ||||||
Amount attributable to liabilities assumed | $ | 2,812,298 | |||||
Fair value of assets acquired: | |||||||
Cash and cash equivalents | $ | 18,879 | |||||
Accounts receivable trade, net | 219,654 | ||||||
Derivative assets | 85,718 | ||||||
Prepaid expenses and other | 8,624 | ||||||
Oil and gas properties, successful efforts method: | |||||||
Proved properties | 2,266,607 | ||||||
Unproved properties | 1,000,396 | ||||||
Other property and equipment | 11,347 | ||||||
Long-term deferred tax asset | 107,497 | ||||||
Other long-term assets | 6,113 | ||||||
Amount attributable to assets acquired | $ | 3,724,835 | |||||
Goodwill | $ | 875,676 | |||||
_____________________ | |||||||
-1 | 47,546,139 shares of Whiting common stock at $37.25 per share (closing price as of December 5, 2014), based on Kodiak’s 268,622,497 common shares outstanding at closing. | ||||||
-2 | 257,601 shares of Whiting common stock issued at $37.25 per share (closing price as of December 5, 2014), based on Kodiak’s 1,455,409 restricted stock units held by employees as of December 8, 2014. | ||||||
Unaudited pro forma operating results | |||||||
December 31, | |||||||
2014 | 2013 | ||||||
(in thousands, except per share data) | |||||||
Total revenues | $ | 4,141,046 | $ | 3,774,137 | |||
Net income available to common shareholders | $ | 362,376 | $ | 576,450 | |||
Earnings per common share: | |||||||
Basic | $ | 2.18 | $ | 3.48 | |||
Diluted | $ | 2.17 | $ | 3.46 | |||
LONGTERM_DEBT_Tables
LONG-TERM DEBT (Tables) | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
LONG-TERM DEBT [Abstract] | ||||||||||||||||
Schedule of long-term debt | ||||||||||||||||
December 31, | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Credit agreement | $ | 1,400,000 | $ | - | ||||||||||||
6.5% Senior Subordinated Notes due 2018 | 350,000 | 350,000 | ||||||||||||||
5% Senior Notes due 2019 | 1,100,000 | 1,100,000 | ||||||||||||||
8.125% Senior Notes due 2019, including unamortized debt premium of $23,742 | 823,742 | - | ||||||||||||||
5.75% Senior Notes due 2021, including unamortized debt premium of $3,180 and $3,834, respectively | 1,203,180 | 1,203,834 | ||||||||||||||
5.5% Senior Notes due 2021, including unamortized debt premium of $867 | 350,867 | - | ||||||||||||||
5.5% Senior Notes due 2022, including unamortized debt premium of $993 | 400,993 | - | ||||||||||||||
Total debt | $ | 5,628,782 | $ | 2,653,834 | ||||||||||||
Schedule of five succeeding fiscal years of scheduled maturities for the Company's long-term debt | 2015 | 2016 | 2017 | 2018 | 2019 | |||||||||||
Long-term debt (1) | $ | - | $ | - | $ | - | $ | 350,000 | $ | 3,300,000 | ||||||
_____________________ | ||||||||||||||||
-1 | Refer to “Kodiak Senior Notes Repurchase Offer” below for more information. | |||||||||||||||
Summary of margin rates and commitment fees | ||||||||||||||||
Applicable | Applicable | |||||||||||||||
Margin for Base | Margin for | Commitment | ||||||||||||||
Ratio of Outstanding Borrowings to Borrowing Base | Rate Loans | Eurodollar Loans | Fee | |||||||||||||
Less than 0.25 to 1.0 | 0.50% | 1.50% | 0.38% | |||||||||||||
Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0 | 0.75% | 1.75% | 0.38% | |||||||||||||
Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0 | 1.00% | 2.00% | 0.50% | |||||||||||||
Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0 | 1.25% | 2.25% | 0.50% | |||||||||||||
Greater than or equal to 0.90 to 1.0 | 1.50% | 2.50% | 0.50% | |||||||||||||
ASSET_RETIREMENT_OBLIGATIONS_T
ASSET RETIREMENT OBLIGATIONS (Tables) | 12 Months Ended | ||||||
Dec. 31, 2014 | |||||||
ASSET RETIREMENT OBLIGATIONS [Abstract] | |||||||
Schedule of reconciliation of the Company's asset retirement obligations | |||||||
December 31, | |||||||
2014 | 2013 | ||||||
Asset retirement obligation at January 1 | $ | 126,148 | $ | 97,818 | |||
Additional liability incurred | 29,186 | 17,535 | |||||
Revisions in estimated cash flows (1) | 25,909 | 12,225 | |||||
Accretion expense | 13,548 | 10,608 | |||||
Obligations on sold properties | -7,237 | -3,630 | |||||
Liabilities settled | -7,623 | -8,408 | |||||
Asset retirement obligation at December 31 | $ | 179,931 | $ | 126,148 | |||
_____________________ | |||||||
-1 | Revisions in estimated cash flows during the year ended December 31, 2014 are primarily attributable to increased estimates of future costs for oilfield goods and services required to plug and abandon wells in certain fields in the Rocky Mountains and Permian Basin regions. Revisions in estimated cash flows during the year ended December 31, 2013 were primarily attributable to increased estimates of futures costs for oilfield goods and services required to plug and abandon wells in certain fields in the Rocky Mountains region. | ||||||
DERIVATIVE_FINANCIAL_INSTRUMEN1
DERIVATIVE FINANCIAL INSTRUMENTS (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Derivative Financial Instruments [Line Items] | ||||||||||||
Schedule of effects of commodity derivative instruments | ||||||||||||
Loss Reclassified from AOCI into | ||||||||||||
Income (Effective Portion) | ||||||||||||
ASC 815 Cash Flow | Year Ended December 31, | |||||||||||
Hedging Relationships (1) | Income Statement Classification | 2014 | 2013 | |||||||||
Commodity contracts | Gain (loss) on hedging activities | $ | - | $ | -1,958 | |||||||
_____________________ | ||||||||||||
-1 | Effective April 1, 2009, the Company de-designated all of its commodity derivative contracts that had been previously designated as cash flow hedges and elected to discontinue hedge accounting prospectively. As a result, such mark-to-market values at March 31, 2009 were frozen in AOCI as of the de-designation date and were reclassified into earnings as the original hedged transactions affected income. As of December 31, 2013, all amounts previously in AOCI had been reclassified into earnings. | |||||||||||
(Gain) Loss Recognized in Income | ||||||||||||
Not Designated as | Year Ended December 31, | |||||||||||
ASC 815 Hedges | Income Statement Classification | 2014 | 2013 | |||||||||
Commodity contracts | Commodity derivative (gain) loss, net | $ | -136,995 | $ | 20,503 | |||||||
Embedded commodity contracts | Commodity derivative (gain) loss, net | 36,416 | -12,701 | |||||||||
Total | $ | -100,579 | $ | 7,802 | ||||||||
Location and fair value of derivative instruments | ||||||||||||
December 31, 2014 (1) | ||||||||||||
Net | ||||||||||||
Gross | Recognized | |||||||||||
Recognized | Gross | Fair Value | ||||||||||
Not Designated as | Assets/ | Amounts | Assets/ | |||||||||
ASC 815 Hedges | Balance Sheet Classification | Liabilities | Offset | Liabilities | ||||||||
Derivative assets: | ||||||||||||
Commodity contracts | Derivative assets | $ | 154,329 | $ | -18,752 | $ | 135,577 | |||||
Commodity contracts | Other long-term assets | 45,459 | - | 45,459 | ||||||||
Total derivative assets | $ | 199,788 | $ | -18,752 | $ | 181,036 | ||||||
Derivative liabilities: | ||||||||||||
Commodity contracts | $ | 18,752 | $ | -18,752 | $ | - | ||||||
Total derivative liabilities | $ | 18,752 | $ | -18,752 | $ | - | ||||||
December 31, 2013 (1) | ||||||||||||
Net | ||||||||||||
Gross | Recognized | |||||||||||
Recognized | Gross | Fair Value | ||||||||||
Not Designated as | Assets/ | Amounts | Assets/ | |||||||||
ASC 815 Hedges | Balance Sheet Classification | Liabilities | Offset | Liabilities | ||||||||
Derivative assets: | ||||||||||||
Commodity contracts | Derivative assets | $ | 23,752 | $ | -22,478 | $ | 1,274 | |||||
Embedded commodity contracts | Other long-term assets | 36,416 | - | 36,416 | ||||||||
Total derivative assets | $ | 60,168 | $ | -22,478 | $ | 37,690 | ||||||
Derivative liabilities: | ||||||||||||
Commodity contracts | Accrued liabilities and other | $ | 25,960 | $ | -22,478 | $ | 3,482 | |||||
Total derivative liabilities | $ | 25,960 | $ | -22,478 | $ | 3,482 | ||||||
_____________________ | ||||||||||||
-1 | Because counterparties to the Company’s financial derivative contracts are lenders under Whiting Oil and Gas’ credit agreement, which eliminates its need to post or receive collateral associated with its derivative positions, columns for cash collateral pledged or received have not been presented in the tables above. | |||||||||||
Whiting Petroleum Corporation [Member] | ||||||||||||
Derivative Financial Instruments [Line Items] | ||||||||||||
Derivative instruments | ||||||||||||
Whiting Petroleum Corporation | ||||||||||||
Derivative | Contracted Crude | Weighted Average NYMEX Price | ||||||||||
Instrument | Period | Oil Volumes (Bbl) | Collar Ranges for Crude Oil (per Bbl) | |||||||||
Three-way collars (1) | Jan - Dec 2015 | 3,600,000 | $50.83 - $62.50 - $83.81 | |||||||||
Jan - Dec 2016 | 6,600,000 | $43.18 - $53.18 - $76.26 | ||||||||||
Collars | Jan - Dec 2015 | 1,309,500 | $52.47 - $59.26 | |||||||||
Jan - Dec 2016 | 3,000,000 | $51.00 - $63.48 | ||||||||||
Jan - Dec 2017 | 3,000,000 | $53.00 - $70.44 | ||||||||||
Swaps | Jan - Dec 2015 | 3,556,560 | $86.05 | |||||||||
Total | 21,066,060 | |||||||||||
_____________________ | ||||||||||||
-1 | A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The sold call establishes a maximum price (ceiling) Whiting will receive for the volumes under contract. The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be NYMEX plus the difference between the purchased put and the sold put strike price. | |||||||||||
FAIR_VALUE_MEASUREMENTS_Tables
FAIR VALUE MEASUREMENTS (Tables) | 12 Months Ended | ||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||
FAIR VALUE MEASUREMENTS [Abstract] | |||||||||||||||||||||
Fair value assets and liabilities measured on a recurring basis | |||||||||||||||||||||
Total Fair Value | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | 31-Dec-14 | ||||||||||||||||||
Financial Assets | |||||||||||||||||||||
Commodity derivatives – current | $ | - | $ | 127,506 | $ | 8,071 | $ | 135,577 | |||||||||||||
Commodity derivatives – non-current | - | - | 45,459 | 45,459 | |||||||||||||||||
Total financial assets | $ | - | $ | 127,506 | $ | 53,530 | $ | 181,036 | |||||||||||||
Total Fair Value | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | 31-Dec-13 | ||||||||||||||||||
Financial Assets | |||||||||||||||||||||
Commodity derivatives – current | $ | - | $ | 1,274 | $ | - | $ | 1,274 | |||||||||||||
Embedded commodity derivatives – non-current | - | - | 36,416 | 36,416 | |||||||||||||||||
Total financial assets | $ | - | $ | 1,274 | $ | 36,416 | $ | 37,690 | |||||||||||||
Financial Liabilities | |||||||||||||||||||||
Commodity derivatives – current | $ | - | $ | 3,482 | $ | - | $ | 3,482 | |||||||||||||
Total financial liabilities | $ | - | $ | 3,482 | $ | - | $ | 3,482 | |||||||||||||
Reconciliation of changes in the fair value of financial assets (liabilities) designated as Level 3 in the valuation hierarchy | |||||||||||||||||||||
Year Ended | |||||||||||||||||||||
December 31, | |||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||
Fair value asset, beginning of period | $ | 36,416 | $ | 23,715 | |||||||||||||||||
Unrealized gains (losses) on commodity derivative contracts included in earnings (1) | 17,114 | 12,701 | |||||||||||||||||||
Transfers into (out of) Level 3 | - | - | |||||||||||||||||||
Fair value asset, end of period | $ | 53,530 | $ | 36,416 | |||||||||||||||||
_____________________ | |||||||||||||||||||||
-1 | Included in commodity derivative (gain) loss, net in the consolidated statements of income. | ||||||||||||||||||||
Significant unobservable inputs used in the fair value measurement | |||||||||||||||||||||
Fair Value at | |||||||||||||||||||||
31-Dec-14 | Valuation | Unobservable | Amount | ||||||||||||||||||
(in thousands) | Technique | Input | (per Bbl) | ||||||||||||||||||
Commodity derivative contracts | $53,530 | Income approach | Market differential for crude oil | $5.74 | |||||||||||||||||
Non-financial assets and liabilities measured at fair value on a nonrecurring basis | |||||||||||||||||||||
Loss (Before | |||||||||||||||||||||
Net Carrying | Tax) Year | ||||||||||||||||||||
Value as of | Ended | ||||||||||||||||||||
December 31, | Fair Value Measurements Using | December 31, | |||||||||||||||||||
2014 | Level 1 | Level 2 | Level 3 | 2014 | |||||||||||||||||
Proved property impairments (1) | $ | 179,155 | $ | - | $ | - | $ | 179,155 | $ | 629,450 | |||||||||||
_____________________ | |||||||||||||||||||||
-1 | During the year ended December 31, 2014, proved oil and gas properties with a carrying amount of $763 million were written down to their fair value of $176 million, resulting in a non-cash impairment charge of $587 million. The impairment primarily consisted of non-core oil and gas properties, that are not currently being developed, in Colorado, Louisiana, North Dakota and Utah and related to the decrease in the forward price curve for crude oil and natural gas on December 31, 2014 and the associated decline in oil and gas reserves in those areas. Also during the year ended December 31, 2014, proved CO2 properties at the Bravo Dome field in New Mexico with a carrying amount of $45 million were written down to their fair value of $3 million, resulting in a non-cash impairment charge of $42 million. | ||||||||||||||||||||
Loss (Before | |||||||||||||||||||||
Net Carrying | Tax) Year | ||||||||||||||||||||
Value as of | Ended | ||||||||||||||||||||
December 31, | Fair Value Measurements Using | December 31, | |||||||||||||||||||
2013 | Level 1 | Level 2 | Level 3 | 2013 | |||||||||||||||||
Proved property impairments (1) | $ | 106,114 | $ | - | $ | - | $ | 106,114 | $ | 267,109 | |||||||||||
_____________________ | |||||||||||||||||||||
-1 | During the year ended December 31, 2013, proved oil and gas properties with a carrying amount of $373 million were written down to their fair value of $106 million, resulting in a non-cash impairment charge of $267 million. The impairment consisted of (i) a $221 million write-down in the Rocky Mountains region and Michigan related to the decrease in the forward price curve for natural gas at December 31, 2013 and the associated decline in gas reserves in those areas and (ii) a $46 million write-down in the Rocky Mountains region related to well performance and associated changes in reserves during the fourth quarter of 2013. | ||||||||||||||||||||
DEFERRED_COMPENSATION_Tables
DEFERRED COMPENSATION (Tables) | 12 Months Ended | ||||||
Dec. 31, 2014 | |||||||
DEFERRED COMPENSATION [Abstract] | |||||||
Schedule of changes in the plan's estimated long-term liability | |||||||
Year Ended December 31, | |||||||
2014 | 2013 | ||||||
Long-term Production Participation Plan liability at January 1 | $ | 87,503 | $ | 94,483 | |||
Change in liability for accretion, vesting, changes in estimates and new Plan year activity prior to Plan termination | - | 66,284 | |||||
Change in liability for vesting and PUDs assigned upon Plan termination | 25,888 | - | |||||
Amount reflected as a current liability | -113,391 | -73,264 | |||||
Long-term Production Participation Plan liability at December 31 | $ | - | $ | 87,503 | |||
SHAREHOLDERS_EQUITY_AND_NONCON1
SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (Tables) | 12 Months Ended | ||||||||||
Dec. 31, 2014 | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Assumption for valuing market based restricted shares | |||||||||||
2014 | 2013 | 2012 | |||||||||
Number of simulations | 65,000 | 65,000 | 65,000 | ||||||||
Expected volatility | 42.30% | 43.10% | 51.90% | ||||||||
Risk-free interest rate | 0.86% | 0.41% | 0.35% | ||||||||
Dividend yield | - | - | - | ||||||||
Summary of nonvested restricted stock | |||||||||||
Weighted Average | |||||||||||
Number | Grant Date | ||||||||||
of Shares | Fair Value | ||||||||||
Restricted stock awards nonvested, January 1, 2012 | 724,395 | $ | 29.88 | ||||||||
Granted | 592,400 | 34.45 | |||||||||
Vested | -357,170 | 17.91 | |||||||||
Forfeited | -8,599 | 51.72 | |||||||||
Restricted stock awards nonvested, December 31, 2012 | 951,026 | 37.02 | |||||||||
Granted | 940,792 | 27.59 | |||||||||
Vested | -347,824 | 35.32 | |||||||||
Forfeited | -99,684 | 30.95 | |||||||||
Restricted stock awards nonvested, December 31, 2013 | 1,444,310 | 31.71 | |||||||||
Granted | 907,856 | 32.41 | |||||||||
Assumed in Kodiak Acquisition (1) | 304,926 | 37.25 | |||||||||
Vested | -814,439 | 34.05 | |||||||||
Forfeited | -385,785 | 34.86 | |||||||||
Restricted stock awards nonvested, December 31, 2014 | 1,456,868 | $ | 31.16 | ||||||||
Assumptions used to estimate the grant date fair value of stock options awarded | |||||||||||
2012 | |||||||||||
Risk-free interest rate | 1.19% | ||||||||||
Expected volatility | 61.40% | ||||||||||
Expected term | 6.0 yrs. | ||||||||||
Dividend yield | - | ||||||||||
Summary of stock options outstanding | |||||||||||
Weighted | |||||||||||
Average | |||||||||||
Weighted | Aggregate | Remaining | |||||||||
Average | Intrinsic | Contractual | |||||||||
Number of | Exercise Price | Value | Term | ||||||||
Options | per Share | (in thousands) | (in years) | ||||||||
Options outstanding at January 1, 2012 | 377,336 | $ | 26.09 | ||||||||
Granted | 45,359 | 51.22 | |||||||||
Exercised | - | - | $ | - | |||||||
Forfeited or expired | - | - | |||||||||
Options outstanding at December 31, 2012 | 422,695 | 28.79 | |||||||||
Granted | - | - | |||||||||
Exercised | - | - | $ | - | |||||||
Forfeited or expired | -1,855 | 60.28 | |||||||||
Options outstanding at December 31, 2013 | 420,840 | 28.65 | |||||||||
Granted | - | - | |||||||||
Assumed in Kodiak Acquisition | 673,235 | 44.48 | |||||||||
Exercised | -117,123 | 15.21 | $ | 6,203,361 | |||||||
Forfeited or expired | -8,559 | 50.51 | |||||||||
Options outstanding at December 31, 2014 | 968,393 | $ | 41.09 | $ | 5,216,952 | 4.8 | |||||
Options vested and expected to vest at December 31, 2014 | 905,107 | $ | 40.78 | $ | 4,984,431 | 4.8 | |||||
Options exercisable at December 31, 2014 | 831,220 | $ | 38.45 | $ | 5,216,952 | 4.2 | |||||
Schedule of noncontrolling interest | |||||||||||
Year Ended | |||||||||||
December 31, | |||||||||||
2014 | 2013 | ||||||||||
Balance at January 1 | $ | 8,132 | $ | 8,184 | |||||||
Net loss | -62 | -52 | |||||||||
Balance at December 31 | $ | 8,070 | $ | 8,132 | |||||||
Kodiak [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Assumptions used to estimate the grant date fair value of stock options awarded | |||||||||||
2014 | |||||||||||
Risk-free interest rate | 0.08% - 1.90% | ||||||||||
Expected volatility | 40.3% - 49.7% | ||||||||||
Expected term | 2.0 yrs. - 6.1 yrs. | ||||||||||
Dividend yield | - | ||||||||||
INCOME_TAXES_Tables
INCOME TAXES (Tables) | 12 Months Ended | |||||||||
Dec. 31, 2014 | ||||||||||
INCOME TAXES [Abstract] | ||||||||||
Schedule of income tax expense | ||||||||||
Year Ended December 31, | ||||||||||
2014 | 2013 | 2012 | ||||||||
Current income tax expense (refund): | ||||||||||
Federal | $ | -2,758 | $ | 7,060 | $ | - | ||||
State | 5,383 | -6,074 | -669 | |||||||
Total current income tax expense (refund) | 2,625 | 986 | -669 | |||||||
Deferred income tax expense: | ||||||||||
Federal | 65,522 | 196,787 | 233,468 | |||||||
State | 11,023 | 8,095 | 15,113 | |||||||
Total deferred income tax expense | 76,545 | 204,882 | 248,581 | |||||||
Total | $ | 79,170 | $ | 205,868 | $ | 247,912 | ||||
Reconciliation of statutory income tax expense to income tax expense | ||||||||||
Year Ended December 31, | ||||||||||
2014 | 2013 | 2012 | ||||||||
U.S. statutory income tax expense | $ | 50,371 | $ | 200,155 | $ | 231,704 | ||||
State income taxes, net of federal benefit | 12,705 | 13,962 | 14,444 | |||||||
State income tax credits | - | -10,525 | - | |||||||
Statutory depletion | -618 | -796 | -620 | |||||||
Enacted changes in state tax laws | 3,700 | -1,416 | - | |||||||
Market-based equity awards | 2,805 | - | - | |||||||
Permanent items | 3,504 | 2,122 | 1,524 | |||||||
Transaction costs | 6,936 | - | - | |||||||
Other | -233 | 2,366 | 860 | |||||||
Total | $ | 79,170 | $ | 205,868 | $ | 247,912 | ||||
Components of deferred income tax assets and liabilities | ||||||||||
Year Ended December 31, | ||||||||||
2014 | 2013 | |||||||||
Deferred income tax assets: | ||||||||||
Net operating loss carryforward | $ | 588,330 | $ | 438,922 | ||||||
Production Participation Plan liability | 26,942 | 32,245 | ||||||||
Tax sharing liability | - | 9,439 | ||||||||
Asset retirement obligations | 13,791 | 23,642 | ||||||||
Underwriter fees | 14,065 | 10,974 | ||||||||
Restricted stock compensation | 15,527 | 13,384 | ||||||||
Premium on Senior Notes | 7,979 | - | ||||||||
EOR credit carryforwards | 7,946 | 7,946 | ||||||||
Alternative minimum tax credit carryforwards | 15,694 | 18,452 | ||||||||
Transaction costs | 7,957 | - | ||||||||
Other | 9,493 | 3,234 | ||||||||
Total deferred income tax assets | 707,724 | 558,238 | ||||||||
Less valuation allowance | -5,638 | -1,230 | ||||||||
Net deferred income tax assets | 702,086 | 557,008 | ||||||||
Deferred income tax liabilities: | ||||||||||
Oil and gas properties | 1,785,926 | 1,675,916 | ||||||||
Trust distributions | 129,437 | 149,332 | ||||||||
Derivative instruments | 64,898 | 10,438 | ||||||||
Total deferred income tax liabilities | 1,980,261 | 1,835,686 | ||||||||
Total net deferred income tax liabilities | $ | 1,278,175 | $ | 1,278,678 | ||||||
Net deferred income tax liabilities | ||||||||||
Year Ended December 31, | ||||||||||
2014 | 2013 | |||||||||
Assets: | ||||||||||
Current deferred income taxes | $ | - | $ | - | ||||||
Liabilities: | ||||||||||
Current deferred income taxes | 47,545 | 648 | ||||||||
Non-current deferred income taxes | 1,230,630 | 1,278,030 | ||||||||
Net deferred income tax liabilities | $ | 1,278,175 | $ | 1,278,678 | ||||||
Liability for unrecognized tax benefits | ||||||||||
Year Ended December 31, | ||||||||||
2014 | 2013 | 2012 | ||||||||
Beginning balance at January 1 | $ | 170 | $ | 170 | $ | 299 | ||||
Decrease related to tax position taken in a prior period | - | - | -129 | |||||||
Ending balance at December 31 | $ | 170 | $ | 170 | $ | 170 | ||||
EARNINGS_PER_SHARE_Tables
EARNINGS PER SHARE (Tables) | 12 Months Ended | |||||||||
Dec. 31, 2014 | ||||||||||
EARNINGS PER SHARE [Abstract] | ||||||||||
Reconciliations between basic and diluted earnings per share | ||||||||||
Year Ended | ||||||||||
December 31, | ||||||||||
2014 | 2013 | 2012 | ||||||||
Basic Earnings Per Share | ||||||||||
Numerator: | ||||||||||
Net income available to shareholders | $ | 64,807 | $ | 366,055 | $ | 414,189 | ||||
Preferred stock dividends (1) | - | -494 | -1,077 | |||||||
Net income available to common shareholders, basic | $ | 64,807 | $ | 365,561 | $ | 413,112 | ||||
Denominator: | ||||||||||
Weighted average shares outstanding, basic | 122,138 | 118,260 | 117,601 | |||||||
Diluted Earnings Per Share | ||||||||||
Numerator: | ||||||||||
Net income available to common shareholders, basic | $ | 64,807 | $ | 365,561 | $ | 413,112 | ||||
Preferred stock dividends | - | 538 | 1,077 | |||||||
Adjusted net income available to common shareholders, diluted | $ | 64,807 | $ | 366,099 | $ | 414,189 | ||||
Denominator: | ||||||||||
Weighted average shares outstanding, basic | 122,138 | 118,260 | 117,601 | |||||||
Restricted stock and stock options | 381 | 957 | 633 | |||||||
Convertible perpetual preferred stock | - | 371 | 794 | |||||||
Weighted average shares outstanding, diluted | 122,519 | 119,588 | 119,028 | |||||||
Earnings per common share, basic | $ | 0.53 | $ | 3.09 | $ | 3.51 | ||||
Earnings per common share, diluted | $ | 0.53 | $ | 3.06 | $ | 3.48 | ||||
_____________________ | ||||||||||
-1 | For the year ended December 31, 2013, amount includes a decrease of $0.04 million in preferred stock dividends for preferred stock dividends accumulated. There were no accumulated dividend adjustments for the years ended December 31, 2014 or 2012. | |||||||||
RELATED_PARTY_TRANSACTIONS_Tab
RELATED PARTY TRANSACTIONS (Tables) | 12 Months Ended | ||||||
Dec. 31, 2014 | |||||||
RELATED PARTY TRANSACTIONS [Abstract] | |||||||
Summary of related party receivable and payable balances | |||||||
December 31, | |||||||
2014 | 2013 | ||||||
Assets | |||||||
Unit distributions due from Trust I (1) | $ | 652 | $ | 1,093 | |||
Liabilities | |||||||
Unit distributions payable to Trust I (2) | $ | 4,133 | $ | 6,932 | |||
_____________________ | |||||||
-1 | This amount represents Whiting’s 15.8% interest in the net proceeds due from Trust I and is included within accounts receivable trade, net in the Company’s consolidated balance sheets. | ||||||
-2 | This amount represents net proceeds from Trust I’s underlying properties that the Company has received between the last Trust I distribution date and December 31, 2014 and 2013, respectively, but which the Company has not yet distributed to Trust I as of December 31, 2014 and 2013, respectively. Due to ongoing processing of Trust I revenues and expenses after December 31, 2014 and 2013, the amount of Whiting’s next scheduled distribution to Trust I, and the related distribution by Trust I to its unitholders, will differ from this amount. These amounts are included within accounts payable trade in the Company’s consolidated balance sheet. | ||||||
COMMITMENTS_AND_CONTINGENCIES_
COMMITMENTS AND CONTINGENCIES (Tables) | 12 Months Ended | |||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||
COMMITMENTS AND CONTINGENCIES [Abstract] | ||||||||||||||||||||||
Minimum future payments under non-cancelable operating leases and unconditional purchase obligations | ||||||||||||||||||||||
Payments due by period | ||||||||||||||||||||||
2015 | 2016 | 2017 | 2018 | 2019 | Thereafter | Total | ||||||||||||||||
Non-cancelable leases | $ | 7,692 | $ | 7,547 | $ | 6,610 | $ | 6,693 | $ | 5,844 | $ | 216 | $ | 34,602 | ||||||||
Drilling rig contracts | 146,141 | 101,855 | 30,788 | - | - | - | 278,784 | |||||||||||||||
Pipeline transportation agreements | 5,948 | 9,722 | 9,559 | 9,559 | 9,559 | 50,091 | 94,438 | |||||||||||||||
Total | $ | 159,781 | $ | 119,124 | $ | 46,957 | $ | 16,252 | $ | 15,403 | $ | 50,307 | $ | 407,824 | ||||||||
OIL_AND_GAS_ACTIVITIES_Tables
OIL AND GAS ACTIVITIES (Tables) | 12 Months Ended | |||||||||
Dec. 31, 2014 | ||||||||||
OIL AND GAS ACTIVITIES [Abstract] | ||||||||||
Schedule of cost Incurred in oil and gas producing activities | ||||||||||
Year Ended December 31, | ||||||||||
2014 | 2013 | 2012 | ||||||||
Development (1) | $ | 2,891,893 | $ | 2,132,824 | $ | 1,667,182 | ||||
Proved property acquisition (2) | 2,278,855 | 232,572 | 19,785 | |||||||
Unproved property acquisition (2) | 1,035,439 | 174,103 | 119,175 | |||||||
Exploration | 216,587 | 363,234 | 436,084 | |||||||
Total | $ | 6,422,774 | $ | 2,902,733 | $ | 2,242,226 | ||||
_____________________ | ||||||||||
-1 | During 2014, 2013 and 2012, non-cash additions to oil and gas properties of $45 million, $30 million and $36 million, respectively, which relate to estimated costs of the future plugging and abandonment of the Company’s oil and gas wells, are included in development costs in the table above. | |||||||||
-2 | During 2014, amounts include $2.3 billion of non-cash proved property additions and $1.0 billion of non-cash unproved property additions related to the Kodiak Acquisition. | |||||||||
Net capitalized costs related to the Companybs oil and gas producing activities | ||||||||||
Year Ended December 31, | ||||||||||
2014 | 2013 | |||||||||
Proved oil and gas properties | $ | 12,956,834 | $ | 9,196,845 | ||||||
Unproved oil and gas properties | 1,992,868 | 868,305 | ||||||||
Accumulated depletion | -3,003,270 | -2,645,841 | ||||||||
Oil and gas properties, net | $ | 11,946,432 | $ | 7,419,309 | ||||||
Net changes in capitalized exploratory well costs | ||||||||||
Year Ended December 31, | ||||||||||
2014 | 2013 | 2012 | ||||||||
Beginning balance at January 1 | $ | 85,378 | $ | 108,861 | $ | 90,519 | ||||
Additions to capitalized exploratory well costs pending the determination of proved reserves | 145,336 | 281,951 | 384,223 | |||||||
Reclassifications to wells, facilities and equipment based on the determination of proved reserves | -200,869 | -291,962 | -358,625 | |||||||
Capitalized exploratory well costs charged to expense | -15,552 | -13,472 | -7,256 | |||||||
Ending balance at December 31 | $ | 14,293 | $ | 85,378 | $ | 108,861 | ||||
DISCLOSURES_ABOUT_OIL_AND_GAS_1
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (Tables) | 12 Months Ended | |||||||||
Dec. 31, 2014 | ||||||||||
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES [Abstract] | ||||||||||
Summary of changes in quantities of proved oil and gas reserve | ||||||||||
Oil | NGLs | Natural Gas | Total | |||||||
(MBbl) | (MBbl) | (MMcf) | (MBOE) | |||||||
Balance—January 1, 2012 | 260,144 | 37,609 | 284,975 | 345,249 | ||||||
Extensions and discoveries | 68,134 | 6,526 | 40,915 | 81,479 | ||||||
Sales of minerals in place | -7,960 | -320 | -13,987 | -10,611 | ||||||
Production | -23,139 | -2,766 | -25,827 | -30,209 | ||||||
Revisions to previous estimates | 4,106 | -951 | -61,812 | -7,148 | ||||||
Balance—December 31, 2012 | 301,285 | 40,098 | 224,264 | 378,760 | ||||||
Extensions and discoveries | 88,293 | 9,830 | 63,893 | 108,772 | ||||||
Sales of minerals in place | -36,992 | -4,777 | -12,411 | -43,838 | ||||||
Purchases of minerals in place | 14,543 | 1,311 | 7,751 | 17,146 | ||||||
Production | -27,035 | -2,821 | -26,917 | -34,342 | ||||||
Revisions to previous estimates | 7,327 | 1,228 | 20,934 | 12,044 | ||||||
Balance—December 31, 2013 | 347,421 | 44,869 | 277,514 | 438,542 | ||||||
Extensions and discoveries | 146,122 | 12,947 | 94,452 | 174,811 | ||||||
Sales of minerals in place | -1,642 | - | -2,925 | -2,130 | ||||||
Purchases of minerals in place | 169,586 | - | 156,140 | 195,609 | ||||||
Production | -33,485 | -3,283 | -30,218 | -41,804 | ||||||
Revisions to previous estimates | 15,627 | 151 | -2,943 | 15,288 | ||||||
Balance—December 31, 2014 | 643,629 | 54,684 | 492,020 | 780,316 | ||||||
Proved developed reserves: | ||||||||||
31-Dec-11 | 180,975 | 22,109 | 211,297 | 238,300 | ||||||
31-Dec-12 | 190,845 | 24,204 | 160,893 | 241,864 | ||||||
31-Dec-13 | 198,204 | 23,721 | 183,129 | 252,446 | ||||||
31-Dec-14 | 333,593 | 28,935 | 298,237 | 412,234 | ||||||
Proved undeveloped reserves: | ||||||||||
31-Dec-11 | 79,169 | 15,500 | 73,678 | 106,949 | ||||||
31-Dec-12 | 110,440 | 15,894 | 63,371 | 136,896 | ||||||
31-Dec-13 | 149,217 | 21,148 | 94,385 | 186,096 | ||||||
31-Dec-14 | 310,036 | 25,749 | 193,783 | 368,082 | ||||||
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves | ||||||||||
December 31, | ||||||||||
2014 | 2013 | 2012 | ||||||||
Future cash flows | $ | 59,949,707 | $ | 35,178,399 | $ | 29,308,752 | ||||
Future production costs | -20,772,234 | -12,973,292 | -11,397,332 | |||||||
Future development costs | -7,924,573 | -5,355,383 | -3,181,618 | |||||||
Future income tax expense | -8,579,237 | -3,954,401 | -4,278,529 | |||||||
Future net cash flows | 22,673,663 | 12,895,323 | 10,451,273 | |||||||
10% annual discount for estimated timing of cash flows | -11,830,243 | -6,301,462 | -5,044,240 | |||||||
Standardized measure of discounted future net cash flows | $ | 10,843,420 | $ | 6,593,861 | $ | 5,407,033 | ||||
Changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves | ||||||||||
December 31, | ||||||||||
2014 | 2013 | 2012 | ||||||||
Beginning of year | $ | 6,593,861 | $ | 5,407,033 | $ | 5,272,492 | ||||
Sale of oil and gas produced, net of production costs | -2,274,682 | -2,010,925 | -1,589,665 | |||||||
Sales of minerals in place | -48,532 | -1,064,195 | -438,614 | |||||||
Net changes in prices and production costs | 81,522 | 902,916 | -1,061,495 | |||||||
Extensions, discoveries and improved recoveries | 3,950,413 | 2,827,321 | 3,708,780 | |||||||
Previously estimated development costs incurred during the period | 1,149,926 | 832,096 | 526,982 | |||||||
Changes in estimated future development costs | -3,382,849 | -1,264,189 | -1,498,592 | |||||||
Purchases of minerals in place | 4,420,417 | 445,669 | - | |||||||
Revisions of previous quantity estimates | 345,775 | 313,069 | -295,432 | |||||||
Net change in income taxes | -651,817 | -335,637 | 255,328 | |||||||
Accretion of discount | 659,386 | 540,703 | 527,249 | |||||||
End of year | $ | 10,843,420 | $ | 6,593,861 | $ | 5,407,033 | ||||
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves calculating average sales prices | ||||||||||
2014 | 2013 | 2012 | ||||||||
Oil (per Bbl) | $ | 84.69 | $ | 90.8 | $ | 87.15 | ||||
NGLs (per Bbl) | $ | 46.59 | $ | 54.38 | $ | 58.15 | ||||
Natural Gas (per Mcf) | $ | 5.88 | $ | 4.3 | $ | 3.21 | ||||
QUARTERLY_FINANCIAL_DATA_Table
QUARTERLY FINANCIAL DATA (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
QUARTERLY FINANCIAL DATA [Abstract] | |||||||||||||
Summary of the unaudited quarterly financial data | |||||||||||||
Three Months Ended | |||||||||||||
March 31, | June 30, | September 30, | December 31, | ||||||||||
2014 | 2014 | 2014 | 2014 | ||||||||||
Oil, NGL and natural gas sales | $ | 721,250 | $ | 825,760 | $ | 805,054 | $ | 672,553 | |||||
Operating profit (1) | $ | 311,169 | $ | 370,033 | $ | 326,215 | $ | 177,722 | |||||
Net income (loss) | $ | 109,051 | $ | 151,426 | $ | 157,961 | $ | -353,693 | |||||
Basic earnings (loss) per share | $ | 0.92 | $ | 1.27 | $ | 1.33 | $ | -2.69 | |||||
Diluted earnings (loss) per share | $ | 0.91 | $ | 1.26 | $ | 1.32 | $ | -2.68 | |||||
Three Months Ended | |||||||||||||
March 31, | June 30, | September 30, | December 31, | ||||||||||
2013 | 2013 | 2013 | 2013 | ||||||||||
Oil, NGL and natural gas sales | $ | 605,114 | $ | 651,868 | $ | 706,543 | $ | 703,024 | |||||
Operating profit (1) | $ | 252,806 | $ | 269,528 | $ | 316,764 | $ | 280,311 | |||||
Net income (loss) | $ | 86,244 | $ | 134,944 | $ | 204,091 | $ | -59,276 | |||||
Basic earnings (loss) per share | $ | 0.73 | $ | 1.14 | $ | 1.72 | $ | -0.5 | |||||
Diluted earnings (loss) per share | $ | 0.72 | $ | 1.14 | $ | 1.71 | $ | -0.5 | |||||
_____________________ | |||||||||||||
-1 | Oil, NGL and natural gas sales less lease operating expense, production taxes and depreciation, depletion and amortization. | ||||||||||||
SUMMARY_OF_SIGNIFICANT_ACCOUNT3
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Narrative I) (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Summary Of Significant Accounting Policies [Line Items] | |||
Oil and gas receivables collection period | 2 months | ||
Allowance for doubtful account | $9 | $4 | |
Interest cost capitalized | $4 | $2 | $3 |
Whiting USA Trust I [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Company retained ownership (as a percent) | 15.80% | ||
Minimum [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Estimated useful life | 4 years | ||
Maximum [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Estimated useful life | 30 years |
SUMMARY_OF_SIGNIFICANT_ACCOUNT4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Narrative II) (Details) | 0 Months Ended | 12 Months Ended | |
Mar. 28, 2012 | Dec. 31, 2014 | Dec. 31, 2012 | |
Concentration Risk [Line Items] | |||
Number of operating segments | 1 | ||
Whiting USA Trust I [Member] | |||
Concentration Risk [Line Items] | |||
Trust units sold to the public (in shares) | 11,677,500 | ||
Whiting USA Trust II Units [Member] | |||
Concentration Risk [Line Items] | |||
Trust units sold to the public (in shares) | 18,400,000 | 18,400,000 | 18,400,000 |
Commodity Price Risk [Member] | Derivative Contracts [Member] | |||
Concentration Risk [Line Items] | |||
Number of counterparties | 7 | ||
Wells Fargo Bank [Member] | Commodity Price Risk [Member] | Derivative Contracts [Member] | |||
Concentration Risk [Line Items] | |||
Outstanding derivative contracts as percentage of crude oil volumes hedged | 34.00% | ||
JP Morgan Chase [Member] | Commodity Price Risk [Member] | Derivative Contracts [Member] | |||
Concentration Risk [Line Items] | |||
Outstanding derivative contracts as percentage of crude oil volumes hedged | 28.00% | ||
Canadian Imperial Bank Of Commerce [Member] | Commodity Price Risk [Member] | Derivative Contracts [Member] | |||
Concentration Risk [Line Items] | |||
Outstanding derivative contracts as percentage of crude oil volumes hedged | 13.00% |
SUMMARY_OF_SIGNIFICANT_ACCOUNT5
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Percentages of total oil and gas sales to significant purchases) (Details) (Credit Concentration Risk [Member], Oil And Gas Sales [Member]) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Plains Marketing LP [Member] | |||
Concentration Risk [Line Items] | |||
Sales as percentage of oil and gas revenue | 17.00% | 21.00% | 20.00% |
Shell Trading US [Member] | |||
Concentration Risk [Line Items] | |||
Sales as percentage of oil and gas revenue | 10.00% | 14.00% | 14.00% |
Bridger Trading LLC [Member] | |||
Concentration Risk [Line Items] | |||
Sales as percentage of oil and gas revenue | 10.00% | 8.00% | 11.00% |
Eighty Eight Oil Company [Member] | |||
Concentration Risk [Line Items] | |||
Sales as percentage of oil and gas revenue | 6.00% | 11.00% | 11.00% |
OIL_AND_GAS_PROPERTIES_Details
OIL AND GAS PROPERTIES (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
OIL AND GAS PROPERTIES [Abstract] | ||
Proved leasehold costs | $3,637,026 | $1,633,495 |
Unproved leasehold costs | 1,232,040 | 372,298 |
Costs of completed wells and facilities | 9,319,808 | 7,563,350 |
Wells and facilities in progress | 760,828 | 496,007 |
Total oil and gas properties, successful efforts method | 14,949,702 | 10,065,150 |
Accumulated depletion | -3,003,270 | -2,645,841 |
Oil and gas properties, net | $11,946,432 | $7,419,309 |
ACQUISITIONS_AND_DIVESTITURES_1
ACQUISITIONS AND DIVESTITURES (Narrative I) (Details) (USD $) | 0 Months Ended | 1 Months Ended | |
Dec. 08, 2014 | Dec. 31, 2014 | Dec. 05, 2014 | |
Business Acquisition [Line Items] | |||
Goodwill deducted for income tax purposes | $0 | ||
Goodwill | 875,676,000 | ||
Kodiak [Member] | |||
Business Acquisition [Line Items] | |||
Shares exchanged per each share owned | 0.177 | ||
Total consideration | 1,788,213,000 | ||
Aggregate purchase price | 4,300,000,000 | ||
Outstanding debt | 2,500,000,000 | ||
Cash acquired from acquisition | 19,000,000 | ||
Gross acquisition area (in acres) | 327,000 | ||
Net acquisition area (in acres) | 178,000 | ||
Number of wells acquired | 778 | ||
Goodwill | 875,676,000 | ||
Revenue | 46,000,000 | ||
Net income | $17,000,000 | ||
Kodiak [Member] | Wyoming And Colorado [Member] | |||
Business Acquisition [Line Items] | |||
Net acquisition area (in acres) | 10,000 | ||
Common Stock [Member] | Kodiak [Member] | |||
Business Acquisition [Line Items] | |||
Awards Assumed in Kodiak Acquisition (in shares) | 47,546,139 | ||
Closing price, per share | $37.25 |
ACQUISITIONS_AND_DIVESTITURES_2
ACQUISITIONS AND DIVESTITURES (Narrative II) (Details) (USD $) | 0 Months Ended | 12 Months Ended | 0 Months Ended | |||||
Mar. 28, 2012 | Dec. 31, 2014 | Dec. 31, 2012 | Mar. 27, 2014 | Oct. 31, 2013 | Jul. 15, 2013 | 18-May-12 | Sep. 20, 2013 | |
MBoe | acre | |||||||
item | ||||||||
Whiting USA Trust II Units [Member] | ||||||||
Acquisitions and divestitures [Line Items] | ||||||||
Proceeds from sale | $322,000,000 | |||||||
Number of units received in exchange of oil and gas properties contributed (in shares) | 18,400,000 | 18,400,000 | 18,400,000 | |||||
Price per unit of shares | $20 | |||||||
Deferred gain on sale | 128,000,000 | |||||||
Percentage of units issued | 100.00% | |||||||
Entitled to receive percentage of net proceeds from sale of oil and gas production | 90.00% | |||||||
Termination of net profits interest, cumulative production from underlying properties (in MBOE) | 11,790 | |||||||
Proved producing reserves conveyed (in MBOE) | 10,610 | |||||||
Williston Basin [Member] | ||||||||
Acquisitions and divestitures [Line Items] | ||||||||
Gross acquisition area (in acres) | 39,300 | |||||||
Net acquisition area (in acres) | 17,300 | |||||||
Number of wells acquired | 121 | |||||||
Purchase price for acquisition | 261,000,000 | |||||||
Post-closing purchase price adjustments | 6,000,000 | |||||||
Adjusted purchase price of tangible assets acquired and liabilities assumed | 255,537,000 | |||||||
Big Tex prospect properties [Member] | ||||||||
Acquisitions and divestitures [Line Items] | ||||||||
Gross acquisition area (in acres) | 49,900 | 45,000 | ||||||
Net acquisition area (in acres) | 41,000 | 32,200 | ||||||
Proceeds from sale | 76,000,000 | 151,000,000 | ||||||
Pre tax gain on Divestiture | 12,000,000 | 11,000,000 | ||||||
Big Tex prospect properties [Member] | Pecos County, TX [Member] | ||||||||
Acquisitions and divestitures [Line Items] | ||||||||
Net acquisition area (in acres) | 30,800 | |||||||
Big Tex prospect properties [Member] | Reeves County, TX [Member] | ||||||||
Acquisitions and divestitures [Line Items] | ||||||||
Net acquisition area (in acres) | 1,400 | |||||||
Postle Properties [Member] | ||||||||
Acquisitions and divestitures [Line Items] | ||||||||
Ownership interest sold (as a percent) | 60.00% | |||||||
Proceeds from sale | 809,000,000 | |||||||
Pre tax gain on Divestiture | 109,000,000 | |||||||
Belfield Gas Processing Plant [Member] | ||||||||
Acquisitions and divestitures [Line Items] | ||||||||
Ownership interest sold (as a percent) | 50.00% | |||||||
Proceeds from sale | $66,000,000 |
ACQUISITIONS_AND_DIVESTITURES_3
ACQUISITIONS AND DIVESTITURES (Preliminary Consideration Transferred) (Details) (USD $) | 12 Months Ended | 0 Months Ended | |||
In Thousands, except Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 08, 2014 | Dec. 31, 2013 | Dec. 05, 2014 | |
Business Acquisition [Line Items] | |||||
Proved properties | $12,956,834 | $9,196,845 | |||
Unproved properties | 1,232,040 | 372,298 | |||
Goodwill | 875,676 | ||||
Common stock, shares issued | 168,346,020 | 120,101,555 | |||
Restricted Stock Units (RSUs) [Member] | |||||
Business Acquisition [Line Items] | |||||
Fair value of Whitingbs common stock issued | 9,596 | ||||
Closing price, per share | $37.25 | ||||
Stock Option [Member] | |||||
Business Acquisition [Line Items] | |||||
Fair value of Whitingbs common stock issued | 7,523 | ||||
Awards Assumed in Kodiak Acquisition (in shares) | 673,235 | ||||
Kodiak [Member] | Restricted Stock Units (RSUs) [Member] | |||||
Business Acquisition [Line Items] | |||||
Common stock, shares issued | 1,455,409 | ||||
Kodiak [Member] | |||||
Business Acquisition [Line Items] | |||||
Total consideration | 1,788,213 | ||||
Accounts payable trade | 18,390 | ||||
Accrued capital expenditures | 104,509 | ||||
Revenues and royalties payable | 57,423 | ||||
Accrued liabilities and other | 45,695 | ||||
Taxes payable | 12,676 | ||||
Accrued interest | 18,070 | ||||
Current deferred tax liability | 30,279 | ||||
Long-term debt | 2,500,875 | ||||
Asset retirement obligations | 8,646 | ||||
Other long-term liabilities | 15,735 | ||||
Amount attributable to liabilities assumed | 2,812,298 | ||||
Cash and cash equivalents | 18,879 | ||||
Accounts receivable trade, net | 219,654 | ||||
Derivative assets | 85,718 | ||||
Prepaid expenses and other | 8,624 | ||||
Proved properties | 2,266,607 | ||||
Unproved properties | 1,000,396 | ||||
Other property and equipment | 11,347 | ||||
Long-term deferred tax asset | 107,497 | ||||
Other long-term assets | 6,113 | ||||
Amount attributable to assets acquired | 3,724,835 | ||||
Goodwill | 875,676 | ||||
Common Stock [Member] | Restricted Stock Units (RSUs) [Member] | |||||
Business Acquisition [Line Items] | |||||
Awards Assumed in Kodiak Acquisition (in shares) | 258,000 | 257,601 | |||
Common Stock [Member] | Kodiak [Member] | |||||
Business Acquisition [Line Items] | |||||
Common stock, shares issued | 268,622,497 | ||||
Common Stock [Member] | Kodiak [Member] | Restricted Stock Units (RSUs) [Member] | |||||
Business Acquisition [Line Items] | |||||
Fair value of Whitingbs common stock issued | 9,596 | [1] | |||
Common Stock [Member] | Kodiak [Member] | Stock Option [Member] | |||||
Business Acquisition [Line Items] | |||||
Fair value of Whitingbs common stock issued | 7,523 | ||||
Common Stock [Member] | |||||
Business Acquisition [Line Items] | |||||
Fair value of Whitingbs common stock issued | 1,771,094 | ||||
Closing price, per share | $37.25 | ||||
Common Stock [Member] | Common Stock [Member] | |||||
Business Acquisition [Line Items] | |||||
Fair value of Whitingbs common stock issued | 48 | ||||
Awards Assumed in Kodiak Acquisition (in shares) | 47,546,000 | 47,546,139 | |||
Common Stock [Member] | Common Stock [Member] | Kodiak [Member] | |||||
Business Acquisition [Line Items] | |||||
Fair value of Whitingbs common stock issued | $1,771,094 | [2] | |||
[1] | 257,601 shares of Whiting common stock issued at $37.25 per share (closing price as of December 5, 2014), based on Kodiakbs 1,455,409 restricted stock units held by employees as of December 8, 2014. | ||||
[2] | 47,546,139 shares of Whiting common stock at $37.25 per share (closing price as of December 5, 2014), based on Kodiakbs 268,622,497 common shares outstanding at closing. |
ACQUISITIONS_AND_DIVESTITURES_4
ACQUISITIONS AND DIVESTITURES (Purchase price allocation) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Significant Acquisitions and Disposals [Line Items] | ||
Proved properties | $12,956,834 | $9,196,845 |
Unproved properties | 1,232,040 | 372,298 |
Williston Basin [Member] | ||
Significant Acquisitions and Disposals [Line Items] | ||
Proved properties | 229,002 | |
Unproved properties | 27,335 | |
Oil in tank inventory | 522 | |
Accounts receivable | 578 | |
Asset retirement obligations | -1,900 | |
Total | $255,537 |
ACQUISITIONS_AND_DIVESTITURES_5
ACQUISITIONS AND DIVESTITURES (Unaudited Pro forma Operating Results) (Details) (USD $) | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Acquisition-related Costs [Member] | ||
Business Acquisition [Line Items] | ||
Acquisition-related costs | $86,000,000 | |
Kodiak [Member] | ||
Business Acquisition [Line Items] | ||
Total revenues | 4,141,046,000 | 3,774,137,000 |
Net income available to common shareholders | $362,376,000 | $576,450,000 |
Net income (loss) per share: Basic | $2.18 | $3.48 |
Net income (loss) per share: Diluted | $2.17 | $3.46 |
LONGTERM_DEBT_Credit_agreement
LONG-TERM DEBT (Credit agreement) (Details) (USD $) | 12 Months Ended |
Dec. 31, 2014 | |
LIBOR Rate, Scenario 1 [Member] | |
Debt disclosures [Line Items] | |
Basis points added to reference rate (as a percent) | 2.00% |
LIBOR rate, Scenario 2 [Member] | |
Debt disclosures [Line Items] | |
Basis points added to reference rate (as a percent) | 2.50% |
Whiting Oil and Gas Corporation [Member] | |
Debt disclosures [Line Items] | |
Maximum borrowing capacity of credit facility | 4,500,000,000 |
Maximum aggregate commitments | 3,500,000,000 |
Current borrowing capacity of credit facility | 3,500,000,000 |
Whiting Oil and Gas Corporation [Member] | Amendment credit agreement [Member] | |
Debt disclosures [Line Items] | |
Borrowing capacity of credit facility, net of letter of credit | 3,100,000,000 |
Outstanding borrowings under credit facility | 1,400,000,000 |
Letters of credit borrowings outstanding | 3,000,000 |
Portion of line of credit available for issuance of letters of credit | 100,000,000 |
Amount of revolving credit agreement available for additional letters of credit under the agreement | 97,000,000 |
Weighted average interest rate | 1.90% |
Restricted net assets | 6,900,000,000 |
Retained earnings free from restrictions | 24,000,000 |
EBITDAX ratio (percentage) | 4 |
Minimum consolidated current assets to consolidated current liabilities ratio (percentage) | 1 |
Whiting Oil and Gas Corporation [Member] | Amendment credit agreement [Member] | Base Rate [Member] | |
Debt disclosures [Line Items] | |
Basis points added to reference rate (as a percent) | 0.50% |
Variable interest rate basis | federal funds |
Whiting Oil and Gas Corporation [Member] | Amendment credit agreement [Member] | LIBOR [Member] | |
Debt disclosures [Line Items] | |
Basis points added to reference rate (as a percent) | 1.00% |
Variable interest rate basis | LIBOR |
Delayed Draw Facility [Member] | |
Debt disclosures [Line Items] | |
Commitment Fee (as a percent) | 0.25% |
Delayed Draw Facility [Member] | Base Rate, Scenario 1 [Member] | |
Debt disclosures [Line Items] | |
Basis points added to reference rate (as a percent) | 1.00% |
Delayed Draw Facility [Member] | Base Rate, Scenario 2 [Member] | |
Debt disclosures [Line Items] | |
Basis points added to reference rate (as a percent) | 1.50% |
Delayed Draw Facility [Member] | Whiting Oil and Gas Corporation [Member] | |
Debt disclosures [Line Items] | |
Maximum borrowing capacity of credit facility | 1,000,000,000 |
LONGTERM_DEBT_Schedule_of_long
LONG-TERM DEBT (Schedule of long-term debt) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2010 | Sep. 30, 2013 | Sep. 26, 2013 |
In Thousands, unless otherwise specified | |||||
Debt Instrument [Line Items] | |||||
Long-term debt | $5,628,782 | $2,653,834 | |||
Amendment credit agreement [Member] | |||||
Debt Instrument [Line Items] | |||||
Long-term debt | 1,400,000 | ||||
Senior Subordinated Notes [Member] | 6.5% Senior Subordinated Notes due 2018 [Member] | |||||
Debt Instrument [Line Items] | |||||
Long-term debt | 350,000 | 350,000 | |||
Interest rate on debt instrument (as a percent) | 6.50% | 6.50% | 6.50% | ||
Senior Notes [Member] | 5% Senior Notes due 2019 [Member] | |||||
Debt Instrument [Line Items] | |||||
Long-term debt | 1,100,000 | 1,100,000 | |||
Interest rate on debt instrument (as a percent) | 5.00% | 5.00% | 5.00% | ||
Senior Notes [Member] | 8.125% Kodiak Senior Notes due 2019 [Member] | |||||
Debt Instrument [Line Items] | |||||
Long-term debt | 823,742 | ||||
Interest rate on debt instrument (as a percent) | 8.13% | ||||
Unamortized debt premium | 23,742 | ||||
Senior Notes [Member] | 5.75% Senior Notes due 2021 [Member] | |||||
Debt Instrument [Line Items] | |||||
Long-term debt | 1,203,180 | 1,203,834 | |||
Interest rate on debt instrument (as a percent) | 5.75% | 5.75% | 5.75% | 5.75% | |
Unamortized debt premium | 3,180 | 3,834 | |||
Senior Notes [Member] | 5.5% Kodiak Senior Notes due 2021 [Member] | |||||
Debt Instrument [Line Items] | |||||
Long-term debt | 350,867 | ||||
Interest rate on debt instrument (as a percent) | 5.50% | ||||
Unamortized debt premium | 867 | ||||
Senior Notes [Member] | 5.5% Kodiak Senior Notes due 2022 [Member] | |||||
Debt Instrument [Line Items] | |||||
Long-term debt | 400,993 | ||||
Interest rate on debt instrument (as a percent) | 5.50% | ||||
Unamortized debt premium | $993 |
LONGTERM_DEBT_Schedule_of_five
LONG-TERM DEBT (Schedule of five succeeding fiscal years of scheduled maturities for long-term debt) (Details) (USD $) | Dec. 31, 2014 | |
In Thousands, unless otherwise specified | ||
LONG-TERM DEBT [Abstract] | ||
2018 | $350,000 | [1] |
2019 | $3,300,000 | [1] |
[1] | Refer to bKodiak Senior Notes Repurchase Offerb below for more information. |
LONGTERM_DEBT_Summary_of_margi
LONG-TERM DEBT (Summary of margin rates and commitment fees) (Details) (Amendment credit agreement [Member], Whiting Oil and Gas Corporation [Member]) | 12 Months Ended |
Dec. 31, 2014 | |
Base Rate [Member] | |
Debt Instrument [Line Items] | |
Variable interest rate basis | federal funds |
Applicable Margin for Loans (as percent) | 0.50% |
Less than 0.25 to 1.0 [Member] | |
Debt Instrument [Line Items] | |
Variable interest rate basis | LIBOR |
Alternate variable interest rate basis | base loan rate |
Range, less than | 0.25 |
Commitment Fee (as a percent) | 0.38% |
Less than 0.25 to 1.0 [Member] | Base Rate [Member] | |
Debt Instrument [Line Items] | |
Applicable Margin for Loans (as percent) | 0.50% |
Less than 0.25 to 1.0 [Member] | Eurodollar [Member] | |
Debt Instrument [Line Items] | |
Applicable Margin for Loans (as percent) | 1.50% |
Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0 [Member] | |
Debt Instrument [Line Items] | |
Variable interest rate basis | LIBOR |
Alternate variable interest rate basis | base loan rate |
Range, greater than or equal to | 0.25 |
Range, less than | 0.5 |
Commitment Fee (as a percent) | 0.38% |
Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0 [Member] | Base Rate [Member] | |
Debt Instrument [Line Items] | |
Applicable Margin for Loans (as percent) | 0.75% |
Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0 [Member] | Eurodollar [Member] | |
Debt Instrument [Line Items] | |
Applicable Margin for Loans (as percent) | 1.75% |
Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0 [Member] | |
Debt Instrument [Line Items] | |
Variable interest rate basis | LIBOR |
Alternate variable interest rate basis | base loan rate |
Range, greater than or equal to | 0.5 |
Range, less than | 0.75 |
Commitment Fee (as a percent) | 0.50% |
Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0 [Member] | Base Rate [Member] | |
Debt Instrument [Line Items] | |
Applicable Margin for Loans (as percent) | 1.00% |
Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0 [Member] | Eurodollar [Member] | |
Debt Instrument [Line Items] | |
Applicable Margin for Loans (as percent) | 2.00% |
Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0 [Member] | |
Debt Instrument [Line Items] | |
Variable interest rate basis | LIBOR |
Alternate variable interest rate basis | base loan rate |
Range, greater than or equal to | 0.75 |
Range, less than | 0.9 |
Commitment Fee (as a percent) | 0.50% |
Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0 [Member] | Base Rate [Member] | |
Debt Instrument [Line Items] | |
Applicable Margin for Loans (as percent) | 1.25% |
Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0 [Member] | Eurodollar [Member] | |
Debt Instrument [Line Items] | |
Applicable Margin for Loans (as percent) | 2.25% |
Greater than or equal to 0.90 to 1.0 [Member] | |
Debt Instrument [Line Items] | |
Variable interest rate basis | LIBOR |
Alternate variable interest rate basis | base loan rate |
Range, greater than or equal to | 0.9 |
Commitment Fee (as a percent) | 0.50% |
Greater than or equal to 0.90 to 1.0 [Member] | Base Rate [Member] | |
Debt Instrument [Line Items] | |
Applicable Margin for Loans (as percent) | 1.50% |
Greater than or equal to 0.90 to 1.0 [Member] | Eurodollar [Member] | |
Debt Instrument [Line Items] | |
Applicable Margin for Loans (as percent) | 2.50% |
LONGTERM_DEBT_Senior_notes_and
LONG-TERM DEBT (Senior notes and senior subordinated notes) (Details) (USD $) | 12 Months Ended | 1 Months Ended | 0 Months Ended | |||||
Dec. 31, 2013 | Oct. 31, 2013 | Jan. 07, 2015 | Dec. 31, 2014 | Sep. 30, 2010 | Sep. 30, 2013 | Sep. 26, 2013 | Dec. 08, 2014 | |
Debt disclosures [Line Items] | ||||||||
Payment for redemption of senior debt | ($253,988,000) | |||||||
Loss on early extinguishment of debt | -4,412,000 | |||||||
Long-term Debt | 2,653,834,000 | 5,628,782,000 | ||||||
Senior Subordinated Notes [Member] | 6.5% Senior Subordinated Notes due 2018 [Member] | ||||||||
Debt disclosures [Line Items] | ||||||||
Interest rate on debt instrument (as a percent) | 6.50% | 6.50% | 6.50% | |||||
Notes Issued | 350,000,000 | |||||||
Estimated fair value of Notes | 371,000,000 | 345,000,000 | ||||||
Long-term Debt | 350,000,000 | 350,000,000 | ||||||
Senior Subordinated Notes [Member] | 7% Senior Subordinated Notes due 2014 [Member] | ||||||||
Debt disclosures [Line Items] | ||||||||
Interest rate on debt instrument (as a percent) | 7.00% | |||||||
Payment for redemption of senior debt | 254,000,000 | |||||||
Senior subordinated notes redeemed, face amount | 250,000,000 | |||||||
Percentage of redemption price | 101.60% | |||||||
Loss on early extinguishment of debt | 4,000,000 | |||||||
Cash charge related to the redemption premium | 4,000,000 | |||||||
Senior Notes [Member] | 5% Senior Notes due 2019 [Member] | ||||||||
Debt disclosures [Line Items] | ||||||||
Interest rate on debt instrument (as a percent) | 5.00% | 5.00% | 5.00% | |||||
Notes Issued | 1,100,000,000 | |||||||
Estimated fair value of Notes | 1,100,000,000 | 1,000,000,000 | ||||||
Long-term Debt | 1,100,000,000 | 1,100,000,000 | ||||||
Senior Notes [Member] | 5.75% Senior Notes due 2021 [Member] | ||||||||
Debt disclosures [Line Items] | ||||||||
Interest rate on debt instrument (as a percent) | 5.75% | 5.75% | 5.75% | 5.75% | ||||
Notes Issued | 800,000,000 | 400,000,000 | ||||||
Estimated fair value of Notes | 1,300,000,000 | 1,100,000,000 | ||||||
Premium as a percentage of par | 101.00% | |||||||
Unamortized debt premium | 3,834,000 | 3,180,000 | ||||||
Long-term Debt | 1,203,834,000 | 1,203,180,000 | ||||||
Senior Notes [Member] | 8.125% Kodiak Senior Notes due 2019 [Member] | ||||||||
Debt disclosures [Line Items] | ||||||||
Interest rate on debt instrument (as a percent) | 8.13% | |||||||
Notes Issued | 800,000,000 | |||||||
Estimated fair value of Notes | 812,000,000 | 824,000,000 | ||||||
Unamortized debt premium | 23,742,000 | |||||||
Long-term Debt | 823,742,000 | |||||||
Senior Notes [Member] | 5.5% Kodiak Senior Notes due 2021 [Member] | ||||||||
Debt disclosures [Line Items] | ||||||||
Interest rate on debt instrument (as a percent) | 5.50% | |||||||
Notes Issued | 350,000,000 | |||||||
Estimated fair value of Notes | 351,000,000 | 351,000,000 | ||||||
Unamortized debt premium | 867,000 | |||||||
Long-term Debt | 350,867,000 | |||||||
Senior Notes [Member] | 5.5% Kodiak Senior Notes due 2022 [Member] | ||||||||
Debt disclosures [Line Items] | ||||||||
Interest rate on debt instrument (as a percent) | 5.50% | |||||||
Notes Issued | 400,000,000 | |||||||
Estimated fair value of Notes | 401,000,000 | 401,000,000 | ||||||
Unamortized debt premium | 993,000 | |||||||
Long-term Debt | 400,993,000 | |||||||
Senior Notes [Member] | Kodiak [Member] | Subsequent Event [Member] | ||||||||
Debt disclosures [Line Items] | ||||||||
Notes Issued | $1,550,000,000 | |||||||
Percentage of redemption price | 101.00% |
ASSET_RETIREMENT_OBLIGATIONS_D
ASSET RETIREMENT OBLIGATIONS (Details) (USD $) | 12 Months Ended | |||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | ||
Asset Retirement Obligations | ||||
Asset retirement obligations, current portion | $12,000 | $10,000 | ||
Reconciliation of the Company's asset retirement obligations | ||||
Balance at the beginning of the period | 126,148 | 97,818 | ||
Additional liability incurred | 29,186 | 17,535 | ||
Revisions in estimated cash flows | 25,909 | [1] | 12,225 | [1] |
Accretion expense | 13,548 | 10,608 | ||
Obligations on sold properties | -7,237 | -3,630 | ||
Liabilities settled | -7,623 | -8,408 | ||
Balance at the end of the period | $179,931 | $126,148 | ||
[1] | Revisions in estimated cash flows during the year ended December 31, 2014 are primarily attributable to increased estimates of future costs for oilfield goods and services required to plug and abandon wells in certain fields in the Rocky Mountains and Permian Basin regions. Revisions in estimated cash flows during the year ended December 31, 2013 were primarily attributable to increased estimates of futures costs for oilfield goods and services required to plug and abandon wells in certain fields in the Rocky Mountains region. |
DERIVATIVE_FINANCIAL_INSTRUMEN2
DERIVATIVE FINANCIAL INSTRUMENTS (Derivative instruments) (Details) (Whiting Petroleum Corporation [Member], Crude oil [Member], Subsequent Event [Member]) | Feb. 13, 2015 | |
item | ||
Derivative Financial Instruments [Line Items] | ||
Aggregate notional amount of price risk derivatives (in Bbl) | 21,066,060 | |
Three-way collars [Member] | Jan - Dec 2015 [Member] | ||
Derivative Financial Instruments [Line Items] | ||
Aggregate notional amount of price risk derivatives (in Bbl) | 3,600,000 | [1] |
Derivative, Floor Price (in dollars per Bbl) | 50.83 | [1] |
Derivative, Strike Price (in dollars per Bbl) | 62.5 | [1] |
Derivative, Cap Price (in dollars per Bbl) | 83.81 | [1] |
Three-way collars [Member] | Jan - Dec 2016 [Member] | ||
Derivative Financial Instruments [Line Items] | ||
Aggregate notional amount of price risk derivatives (in Bbl) | 6,600,000 | |
Derivative, Floor Price (in dollars per Bbl) | 43.18 | |
Derivative, Strike Price (in dollars per Bbl) | 53.18 | |
Derivative, Cap Price (in dollars per Bbl) | 76.26 | |
Collars [Member] | Jan - Dec 2015 [Member] | ||
Derivative Financial Instruments [Line Items] | ||
Aggregate notional amount of price risk derivatives (in Bbl) | 1,309,500 | |
Derivative, Floor Price (in dollars per Bbl) | 52.47 | |
Derivative, Cap Price (in dollars per Bbl) | 59.26 | |
Collars [Member] | Jan - Dec 2016 [Member] | ||
Derivative Financial Instruments [Line Items] | ||
Aggregate notional amount of price risk derivatives (in Bbl) | 3,000,000 | |
Derivative, Floor Price (in dollars per Bbl) | 51 | |
Derivative, Cap Price (in dollars per Bbl) | 63.48 | |
Collars [Member] | Jan - Dec 2017 [Member] | ||
Derivative Financial Instruments [Line Items] | ||
Aggregate notional amount of price risk derivatives (in Bbl) | 3,000,000 | |
Derivative, Floor Price (in dollars per Bbl) | 53 | |
Derivative, Cap Price (in dollars per Bbl) | 70.44 | |
Swap [Member] | Jan - Dec 2015 [Member] | ||
Derivative Financial Instruments [Line Items] | ||
Aggregate notional amount of price risk derivatives (in Bbl) | 3,556,560 | |
Derivative, Swap Price (in dollars per Bbl) | 86.05 | |
[1] | A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The sold call establishes a maximum price (ceiling) Whiting will receive for the volumes under contract. The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be NYMEX plus the difference between the purchased put and the sold put strike price. |
DERIVATIVE_FINANCIAL_INSTRUMEN3
DERIVATIVE FINANCIAL INSTRUMENTS (Fixed-differential crude oil contracts) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Derivative Financial Instruments [Line Items] | |||
Fair value asset | $53,530,000 | $36,416,000 | $23,715,000 |
CO 2 Contract [Member] | |||
Derivative Financial Instruments [Line Items] | |||
The estimated fair value of the embedded derivative in this purchase contract asset | $0 |
DERIVATIVE_FINANCIAL_INSTRUMEN4
DERIVATIVE FINANCIAL INSTRUMENTS (Schedule of effects of commodity derivative instruments) (Details) (USD $) | 12 Months Ended | |||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Derivative Financial Instruments [Line Items] | ||||
(Gain) Loss Recognized in Income | ($100,579) | $7,802 | ($85,911) | |
Not Designated as ASC 815 Hedges [Member] | ||||
Derivative Financial Instruments [Line Items] | ||||
(Gain) Loss Recognized in Income | -100,579 | 7,802 | ||
Commodity contracts [Member] | Not Designated as ASC 815 Hedges [Member] | ||||
Derivative Financial Instruments [Line Items] | ||||
(Gain) Loss Recognized in Income | -136,995 | 20,503 | ||
Commodity contracts [Member] | ASC 815 Cash Flow Hedging Relationships [Member] | ||||
Derivative Financial Instruments [Line Items] | ||||
Loss Reclassified from AOCI into Income (Effective Portion) | -1,958 | [1] | ||
Embedded commodity contracts [Member] | Not Designated as ASC 815 Hedges [Member] | ||||
Derivative Financial Instruments [Line Items] | ||||
(Gain) Loss Recognized in Income | $36,416 | ($12,701) | ||
[1] | Effective April 1, 2009, the Company de-designated all of its commodity derivative contracts that had been previously designated as cash flow hedges and elected to discontinue hedge accounting prospectively. As a result, such mark-to-market values at March 31, 2009 were frozen in AOCI as of the de-designation date and were reclassified into earnings as the original hedged transactions affected income. As of December 31, 2013, all amounts previously in AOCI had been reclassified into earnings. |
DERIVATIVE_FINANCIAL_INSTRUMEN5
DERIVATIVE FINANCIAL INSTRUMENTS (Location and fair value of derivative instruments, assets) (Details) (Not Designated as ASC 815 Hedges [Member], USD $) | Dec. 31, 2014 | Dec. 31, 2013 | ||
In Thousands, unless otherwise specified | ||||
Gross amounts of derivative assets and gross amounts offset [Line Items] | ||||
Gross Amounts of Recognized Assets | $199,788 | [1] | $60,168 | [1] |
Gross Amounts Offset | -18,752 | [1] | -22,478 | [1] |
Total financial assets | 181,036 | [1] | 37,690 | [1] |
Commodity contracts [Member] | Derivative Assets [Member] | ||||
Gross amounts of derivative assets and gross amounts offset [Line Items] | ||||
Gross Amounts of Recognized Assets | 23,752 | [1] | ||
Gross Amounts Offset | -22,478 | [1] | ||
Total financial assets | 1,274 | [1] | ||
Commodity contracts [Member] | Prepaid Expenses and Other [Member] | ||||
Gross amounts of derivative assets and gross amounts offset [Line Items] | ||||
Gross Amounts of Recognized Assets | 154,329 | [1] | ||
Gross Amounts Offset | -18,752 | [1] | ||
Total financial assets | 135,577 | [1] | ||
Commodity contracts [Member] | Other Long Term Assets [Member] | ||||
Gross amounts of derivative assets and gross amounts offset [Line Items] | ||||
Gross Amounts of Recognized Assets | 45,459 | [1] | ||
Total financial assets | 45,459 | [1] | ||
Embedded commodity contracts [Member] | Other Long Term Assets [Member] | ||||
Gross amounts of derivative assets and gross amounts offset [Line Items] | ||||
Gross Amounts of Recognized Assets | 36,416 | [1] | ||
Total financial assets | $36,416 | [1] | ||
[1] | Because counterparties to the Companybs financial derivative contracts are lenders under Whiting Oil and Gasb credit agreement, which eliminates its need to post or receive collateral associated with its derivative positions, columns for cash collateral pledged or received have not been presented in the tables above. |
DERIVATIVE_FINANCIAL_INSTRUMEN6
DERIVATIVE FINANCIAL INSTRUMENTS (Location and fair value of derivative instruments, liabilities) (Details) (Not Designated as ASC 815 Hedges [Member], USD $) | Dec. 31, 2014 | Dec. 31, 2013 | ||
In Thousands, unless otherwise specified | ||||
Gross amounts of derivative liabilities and gross amounts offset [Line Items] | ||||
Gross Amounts of Recognized Liabilities | $18,752 | [1] | $25,960 | [1] |
Gross Amounts Offset | -18,752 | [1] | -22,478 | [1] |
Total financial liabilities | 3,482 | [1] | ||
Commodity contracts [Member] | ||||
Gross amounts of derivative liabilities and gross amounts offset [Line Items] | ||||
Gross Amounts of Recognized Liabilities | 18,752 | [1] | ||
Gross Amounts Offset | -18,752 | [1] | ||
Commodity contracts [Member] | Accrued Liabilities And Other [Member] | ||||
Gross amounts of derivative liabilities and gross amounts offset [Line Items] | ||||
Gross Amounts of Recognized Liabilities | 25,960 | [1] | ||
Gross Amounts Offset | -22,478 | [1] | ||
Total financial liabilities | $3,482 | [1] | ||
[1] | Because counterparties to the Companybs financial derivative contracts are lenders under Whiting Oil and Gasb credit agreement, which eliminates its need to post or receive collateral associated with its derivative positions, columns for cash collateral pledged or received have not been presented in the tables above. |
FAIR_VALUE_MEASUREMENTS_Fair_v
FAIR VALUE MEASUREMENTS (Fair value assets and liabilities measured on a recurring basis) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Financial Assets | ||
Financial assets - current | $135,577 | $1,274 |
Recurring Basis [Member] | ||
Financial Assets | ||
Total financial assets | 181,036 | 37,690 |
Financial Liabilities | ||
Total financial liabilities | 3,482 | |
Recurring Basis [Member] | Commodity contracts [Member] | ||
Financial Assets | ||
Financial assets - current | 135,577 | 1,274 |
Financial assets - non-current | 45,459 | |
Financial Liabilities | ||
Financial liabilities - current | 3,482 | |
Recurring Basis [Member] | Embedded commodity contracts [Member] | ||
Financial Assets | ||
Financial assets - non-current | 36,416 | |
Recurring Basis [Member] | Level 2 [Member] | ||
Financial Assets | ||
Total financial assets | 127,506 | 1,274 |
Financial Liabilities | ||
Total financial liabilities | 3,482 | |
Recurring Basis [Member] | Level 2 [Member] | Commodity contracts [Member] | ||
Financial Assets | ||
Financial assets - current | 127,506 | 1,274 |
Financial Liabilities | ||
Financial liabilities - current | 3,482 | |
Recurring Basis [Member] | Level 3 [Member] | ||
Financial Assets | ||
Total financial assets | 53,530 | 36,416 |
Recurring Basis [Member] | Level 3 [Member] | Commodity contracts [Member] | ||
Financial Assets | ||
Financial assets - current | 8,071 | |
Financial assets - non-current | 45,459 | |
Recurring Basis [Member] | Level 3 [Member] | Embedded commodity contracts [Member] | ||
Financial Assets | ||
Financial assets - non-current | $36,416 |
FAIR_VALUE_MEASUREMENTS_Reconc
FAIR VALUE MEASUREMENTS (Reconciliation of changes in the fair value of financial assets (liabilities) designated as Level 3 in the valuation hierarchy)(Details) (USD $) | 12 Months Ended | |||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | ||
Reconciliation of changes in the fair value of financial assets (liabilities) designated as Level 3 in the valuation hierarchy | ||||
Fair value asset, beginning of period | $36,416 | $23,715 | ||
Unrealized gains (losses) on commodity derivative contracts included in earnings | 17,114 | [1] | 12,701 | [1] |
Fair value asset, end of period | $53,530 | $36,416 | ||
[1] | Included in commodity derivative (gain) loss, net in the consolidated statements of income. |
FAIR_VALUE_MEASUREMENTS_Signif
FAIR VALUE MEASUREMENTS (Significant unobservable inputs used in the fair value measurement) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
FAIR VALUE MEASUREMENTS [Line Items] | |||
Fair value asset | $53,530 | $36,416 | $23,715 |
Commodity contracts [Member] | Level 3 [Member] | |||
FAIR VALUE MEASUREMENTS [Line Items] | |||
Fair value asset | $53,530 | ||
Market Differentail For Crude Oil, Amount (Per Bbl) | 5.74 |
FAIR_VALUE_MEASUREMENTS_Nonfin
FAIR VALUE MEASUREMENTS (Non-financial assets and liabilities measured at fair value on a nonrecurring basis) (Details) (USD $) | 12 Months Ended | ||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Loss (Before Tax) Year | $767,627,000 | $358,455,000 | $107,855,000 | ||
Proved CO2 Properties [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Property, Plant, and Equipment, Fair Value Disclosure | 3,000,000 | ||||
Impairment of Proved Properties | 42,000,000 | ||||
CO2 Properties, Net Carrying Value | 45,000,000 | ||||
Proved Oil and Natural Gas Properties [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Property, Plant, and Equipment, Fair Value Disclosure | 176,000,000 | ||||
Impairment of Proved Properties | 587,000,000 | ||||
Nonrecurring [Member] | Proved Properties [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Property, Plant, and Equipment, Fair Value Disclosure | 179,155,000 | [1] | |||
Impairment of Proved Properties | 629,450,000 | [1] | |||
Nonrecurring [Member] | Proved Properties [Member] | Level 3 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Property, Plant, and Equipment, Fair Value Disclosure | 179,155,000 | [1] | |||
Nonrecurring [Member] | Proved Oil and Natural Gas Properties [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Property, Plant, and Equipment, Fair Value Disclosure | 106,114,000 | [2] | |||
Loss (Before Tax) Year | 267,109,000 | [2] | |||
Proved Oil and Gas Properties, Net Carrying Value | 763,000,000 | 373,000,000 | |||
Nonrecurring [Member] | Proved Oil and Natural Gas Properties [Member] | Rocky Mountains Region And Michigan [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Loss (Before Tax) Year | 221,000,000 | ||||
Nonrecurring [Member] | Proved Oil and Natural Gas Properties [Member] | Rocky Mountains Region [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Loss (Before Tax) Year | 46,000,000 | ||||
Nonrecurring [Member] | Proved Oil and Natural Gas Properties [Member] | Level 3 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Property, Plant, and Equipment, Fair Value Disclosure | $106,114,000 | [2] | |||
[1] | During the year ended December 31, 2014, proved oil and gas properties with a carrying amount of $763 million were written down to their fair value of $176 million, resulting in a non-cash impairment charge of $587 million. The impairment primarily consisted of non-core oil and gas properties, that are not currently being developed, in Colorado, Louisiana, North Dakota and Utah and related to the decrease in the forward price curve for crude oil and natural gas on December 31, 2014 and the associated decline in oil and gas reserves in those areas. Also during the year ended December 31, 2014, proved CO2 properties at the Bravo Dome field in New Mexico with a carrying amount of $45 million were written down to their fair value of $3 million, resulting in a non-cash impairment charge of $42 million. | ||||
[2] | During the year ended December 31, 2013, proved oil and gas properties with a carrying amount of $373 million were written down to their fair value of $106 million, resulting in a non-cash impairment charge of $267 million. The impairment consisted of (i) a $221 million write-down in the Rocky Mountains region and Michigan related to the decrease in the forward price curve for natural gas at December 31, 2013 and the associated decline in gas reserves in those areas and (ii) a $46 million write-down in the Rocky Mountains region related to well performance and associated changes in reserves during the fourth quarter of 2013. |
DEFERRED_COMPENSATION_Producti
DEFERRED COMPENSATION (Production participation plan) (Details) (USD $) | 12 Months Ended | 240 Months Ended | 12 Months Ended | ||||
Dec. 31, 2014 | Dec. 31, 1995 | Dec. 31, 1994 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Jan. 31, 2015 | |
Additional Deferred Compensation | |||||||
Percentage of employees vesting ratably per year | 20.00% | ||||||
Plan period (years) | 5 years | ||||||
Distribution period after date of termination (months) | 12 months | ||||||
Amount reflected as a current liability | $113,391,000 | 113,391,000 | $73,264,000 | ||||
Subsequent Event [Member] | |||||||
Deferred Compensation [Line Items] | |||||||
Distribution under the Plan | 41,000,000 | ||||||
Minimum [Member] | |||||||
Deferred Compensation [Line Items] | |||||||
Percentage of overriding royalty interest allocated | 2.00% | ||||||
Percentage of oil and gas sales less lease operating expenses and production taxes allocated | 1.75% | 1.75% | 1.75% | ||||
Maximum [Member] | |||||||
Deferred Compensation [Line Items] | |||||||
Percentage of overriding royalty interest allocated | 3.00% | ||||||
Percentage of oil and gas sales less lease operating expenses and production taxes allocated | 5.00% | 5.00% | 5.00% | ||||
General and administrative expense [Member] | |||||||
Deferred Compensation [Line Items] | |||||||
Accrued compensation expense allocation | 24,000,000 | 66,000,000 | 45,000,000 | ||||
Exploration expense [Member] | |||||||
Deferred Compensation [Line Items] | |||||||
Accrued compensation expense allocation | 2,000,000 | 7,000,000 | 4,000,000 | ||||
Postle Properties [Member] | |||||||
Additional Deferred Compensation | |||||||
Amount reflected as a current liability | $24,000,000 |
DEFERRED_COMPENSATION_401K_Pla
DEFERRED COMPENSATION (401K Plan) (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
DEFERRED COMPENSATION [Abstract] | |||
Employer's contribution in employees retirement plan | $9 | $8 | $6 |
Employees vest in employer contribution Percentage, per year of completed service | 20.00% |
DEFERRED_COMPENSATION_Schedule
DEFERRED COMPENSATION (Schedule of changes in the plan's estimated long-term liability) (Details) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
DEFERRED COMPENSATION [Abstract] | ||
Long-term Production Participation Plan liability at beginning of the period | $87,503 | $94,483 |
Change in liability for accretion, vesting, changes in estimates and new Plan year activity prior to Plan termination | 66,284 | |
Change in liability for vesting and PUDs assigned upon Plan termination | 25,888 | |
Amount reflected as a current liability | -113,391 | -73,264 |
Long-term Production Participation Plan liability at end of the period | $87,503 |
SHAREHOLDERS_EQUITY_AND_NONCON2
SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (6.25% Convertible perpetual preferred stock) (Details) (USD $) | 1 Months Ended | 0 Months Ended | 12 Months Ended | |
Jun. 30, 2009 | Mar. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2014 | |
Convertible perpetual preferred stock [Member] | ||||
Class of Stock [Line Items] | ||||
Interest rate on convertible perpetual preferred stock (as a percent) | 6.25% | |||
6.25% convertible perpetual preferred stock, shares issued | 3,450,000 | 0 | ||
6.25% convertible perpetual preferred stock, shares issue Price per share (in dollars per share) | $100 | |||
6.25% convertible perpetual preferred stock, shares outstanding | 172,129 | 0 | ||
Dividend on preferred stock per share Per annum (in dollars per share) | $6.25 | |||
Common Stock [Member] | ||||
Class of Stock [Line Items] | ||||
Common stock issued on conversion of preferred stock (in shares) | 792,919 | 794,000 |
SHAREHOLDERS_EQUITY_AND_NONCON3
SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (Equity incentive plan) (Details) (USD $) | 12 Months Ended | 0 Months Ended | 1 Months Ended | |||||
In Millions, except Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 08, 2014 | Jan. 31, 2014 | Jan. 31, 2013 | Jan. 31, 2012 | |
Share-based compensation disclosures [Line Items] | ||||||||
Stock compensation expense | $23 | $22 | $18 | |||||
Stock Option [Member] | ||||||||
Share-based compensation disclosures [Line Items] | ||||||||
Maximum number of Shares per employee | 600,000 | |||||||
Vesting (service) period | 3 years | |||||||
Awards Assumed in Kodiak Acquisition (in shares) | 673,235 | |||||||
Weighted average period over which cost will be recognized | 1 year 2 months 12 days | |||||||
Granted (in shares) | 45,359 | |||||||
Granted date fair value (in dollars per share) | $28.88 | |||||||
Unrecognized compensation cost | 1 | |||||||
Stock Appreciation Rights (SARs) [Member] | ||||||||
Share-based compensation disclosures [Line Items] | ||||||||
Maximum number of Shares per employee | 600,000 | |||||||
Restricted Stock [Member] | ||||||||
Share-based compensation disclosures [Line Items] | ||||||||
Maximum number of Shares per employee | 300,000 | |||||||
Awards Assumed in Kodiak Acquisition (in shares) | 304,926 | [1] | 47,325 | |||||
Granted (in shares) | 907,856 | 940,792 | 592,400 | |||||
Granted (in dollars per share) | $32.41 | $27.59 | $34.45 | |||||
Unrecognized compensation cost | 13 | |||||||
Weighted average period over which cost will be recognized | 1 year 8 months 12 days | |||||||
Total fair value of restricted stock vested | $31 | $17 | $19 | |||||
2013 Equity Plan [Member] | ||||||||
Share-based compensation disclosures [Line Items] | ||||||||
Number of shares authorized upon shareholder's approval | 5,300,000 | |||||||
Increase in authorized shares | 978,161 | |||||||
Number of options available for grant | 5,048,433 | |||||||
Executive officers and employees [Member] | Restricted Stock [Member] | ||||||||
Share-based compensation disclosures [Line Items] | ||||||||
Vesting (service) period | 3 years | |||||||
Minimum [Member] | Stock Option [Member] | ||||||||
Share-based compensation disclosures [Line Items] | ||||||||
Vesting (service) period | 1 year | |||||||
Minimum [Member] | Directors [Member] | Restricted Stock [Member] | ||||||||
Share-based compensation disclosures [Line Items] | ||||||||
Vesting (service) period | 1 year | |||||||
Maximum [Member] | Stock Option [Member] | ||||||||
Share-based compensation disclosures [Line Items] | ||||||||
Vesting (service) period | 3 years | |||||||
Market-based vesting criteria [Member] | Executive officers [Member] | Restricted Stock [Member] | ||||||||
Share-based compensation disclosures [Line Items] | ||||||||
Vesting (service) period | 3 years | |||||||
Granted (in shares) | 750,681 | 751,872 | 444,501 | |||||
Granted (in dollars per share) | $26.59 | $23.01 | $29.45 | |||||
[1] | Kodiakbs existing restricted stock units and restricted stock awards held by employees, which automatically converted into 257,601 restricted stock units and 47,325 restricted stock awards of Whiting and vested upon closing of the Kodiak Acquisition. |
SHAREHOLDERS_EQUITY_AND_NONCON4
SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (Equity awards assumed in Kodiak acquisition) (Details) (USD $) | 0 Months Ended | 12 Months Ended | ||
Dec. 08, 2014 | Dec. 31, 2014 | Dec. 31, 2012 | ||
Kodiak [Member] | ||||
Business Acquisition [Line Items] | ||||
Shares exchanged per each share owned | 0.177 | |||
Restricted Stock Units (RSUs) [Member] | ||||
Business Acquisition [Line Items] | ||||
Fair value of Whitingbs common stock issued | $9,596,000 | |||
Stock Option [Member] | ||||
Business Acquisition [Line Items] | ||||
Awards Assumed in Kodiak Acquisition (in shares) | 673,235 | |||
Fair value of Whitingbs common stock issued | 7,523,000 | |||
Amount attributed to prior service rendered | 7,000,000 | |||
Remaining amount to be expensed over remaining service term | 1,000,000 | |||
Vesting (service) period (in years) | 3 years | |||
Weighted average fair value, per share | $28.88 | |||
Stock Option [Member] | Maximum [Member] | ||||
Business Acquisition [Line Items] | ||||
Vesting (service) period (in years) | 3 years | |||
Stock Option [Member] | Minimum [Member] | ||||
Business Acquisition [Line Items] | ||||
Vesting (service) period (in years) | 1 year | |||
Stock Option [Member] | Kodiak [Member] | ||||
Business Acquisition [Line Items] | ||||
Weighted average fair value, per share | 12.2 | |||
Common Stock [Member] | Restricted Stock Units (RSUs) [Member] | ||||
Business Acquisition [Line Items] | ||||
Awards Assumed in Kodiak Acquisition (in shares) | 257,601 | 258,000 | ||
Common Stock [Member] | Restricted Stock Units (RSUs) [Member] | Kodiak [Member] | ||||
Business Acquisition [Line Items] | ||||
Fair value of Whitingbs common stock issued | 9,596,000 | [1] | ||
Common Stock [Member] | Stock Option [Member] | Kodiak [Member] | ||||
Business Acquisition [Line Items] | ||||
Fair value of Whitingbs common stock issued | 7,523,000 | |||
[1] | 257,601 shares of Whiting common stock issued at $37.25 per share (closing price as of December 5, 2014), based on Kodiakbs 1,455,409 restricted stock units held by employees as of December 8, 2014. |
SHAREHOLDERS_EQUITY_AND_NONCON5
SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (Assumption for valuing market based restricted shares) (Details) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
item | item | item | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Dividend yield (as a percent) | 0.00% | ||
Stock Option [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Expected volatility (as a percent) | 61.40% | ||
Risk-free interest rate (as a percent) | 1.19% | ||
Expected term | 6 years | ||
Dividend yield (as a percent) | 0.00% | ||
Stock Option [Member] | Kodiak [Member] | Maximum [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Expected volatility (as a percent) | 49.70% | ||
Risk-free interest rate (as a percent) | 1.90% | ||
Expected term | 6 years 1 month 6 days | ||
Stock Option [Member] | Kodiak [Member] | Minimum [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Expected volatility (as a percent) | 40.30% | ||
Risk-free interest rate (as a percent) | 0.08% | ||
Expected term | 2 years | ||
Market-based vesting criteria [Member] | Executive officers [Member] | Restricted Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Number of simulations | 65,000 | 65,000 | 65,000 |
Expected volatility (as a percent) | 42.30% | 43.10% | 51.90% |
Risk-free interest rate (as a percent) | 0.86% | 0.41% | 0.35% |
Dividend yield (as a percent) | 0.00% | 0.00% | 0.00% |
SHAREHOLDERS_EQUITY_AND_NONCON6
SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (Summary of nonvested restricted stock) (Details) (Restricted Stock [Member], USD $) | 0 Months Ended | 12 Months Ended | |||
Dec. 08, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||
Restricted Stock [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Balance at the beginning of the period (in shares) | 1,444,310 | 951,026 | 724,395 | ||
Granted (in shares) | 907,856 | 940,792 | 592,400 | ||
Awards Assumed in Kodiak Acquisition (in shares) | 47,325 | 304,926 | [1] | ||
Vested (in shares) | -814,439 | -347,824 | -357,170 | ||
Forfeited (in shares) | -385,785 | -99,684 | -8,599 | ||
Balance at the end of the period (in shares) | 1,456,868 | 1,444,310 | 951,026 | ||
Balance at the beginning of the period (in dollars per share) | $31.71 | $37.02 | $29.88 | ||
Granted (in dollars per share) | $32.41 | $27.59 | $34.45 | ||
Awards Assumed in Kodiak Acquisition (in dollars per share) | $37.25 | [1] | |||
Vested (in dollars per share) | $34.05 | $35.32 | $17.91 | ||
Forfeited (in dollars per share) | $34.86 | $30.95 | $51.72 | ||
Balance at the end of the period (in dollars per share) | $31.16 | $31.71 | $37.02 | ||
[1] | Kodiakbs existing restricted stock units and restricted stock awards held by employees, which automatically converted into 257,601 restricted stock units and 47,325 restricted stock awards of Whiting and vested upon closing of the Kodiak Acquisition. |
SHAREHOLDERS_EQUITY_AND_NONCON7
SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (Summary of stock options outstanding) (Details) (Stock Option [Member], USD $) | 12 Months Ended | ||
In Thousands, except Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Stock Option [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Balance at the beginning of the period (in shares) | 420,840 | 422,695 | 377,336 |
Granted (in shares) | 45,359 | ||
Options Assumed in Kodiak Acquisition (in shares) | 673,235 | ||
Exercised (in shares) | -117,123 | ||
Forfeited or expired (in shares) | -8,559 | -1,855 | |
Balance at the end of the period (in shares) | 968,393 | 420,840 | 422,695 |
Options vested and expected to vest (in shares) | 905,107 | ||
Options exercisable (in shares) | 831,220 | ||
Balance at the beginning of the period (in dollars per share) | $28.65 | $28.79 | $26.09 |
Granted (in dollars per share) | $51.22 | ||
Options Assumed in Kodiak Acquisition (in dollars per share) | $44.48 | ||
Exercised (in dollars per share) | $15.21 | ||
Forfeitures or expired (in dollars per share) | $50.51 | $60.28 | |
Balance at the end of the period (in dollars per share) | $41.09 | $28.65 | $28.79 |
Options vested and expected to vest (in dollars per share) | $40.78 | ||
Options exercisable (in dollars per share) | $38.45 | ||
Aggregate Intrinsic Value, options Exercised | $6,203,361 | ||
Aggregate Intrinsic Value, options outstanding, end of period | 5,216,952 | ||
Options vested and expected to vest, Aggregate Intrinsic Value | 4,984,431 | ||
Options exercisable, Aggregate Intrinsic Value | $5,216,952 | ||
Weighted Average Remaining Contractual Term, options outstanding | 4 years 9 months 18 days | ||
Weighted Average Remaining Contractual Term, options vested and expected to vest | 4 years 9 months 18 days | ||
Weighted Average Remaining Contractual Term, options exercisable | 4 years 2 months 12 days |
SHAREHOLDERS_EQUITY_AND_NONCON8
SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (Rights Agreement) (Details) (USD $) | 0 Months Ended | 12 Months Ended | |
Feb. 22, 2011 | Dec. 31, 2014 | Dec. 31, 2006 | |
Rights [Member] | |||
Class of Warrant or Right [Line Items] | |||
Price of one hundredth of a share, Series A Junior Participating Preferred Stock | 180 | ||
Redemption price per share, Series A Junior Participating Preferred Stock | 0.001 | ||
Common Stock [Member] | |||
Class of Warrant or Right [Line Items] | |||
Number of preferred share purchase rights declared as a dividend on a common stock | 1 | ||
Stock split approved | 2 | ||
Number of rights outstanding per common share | 0.5 | ||
Minimum percentage ownership for preferred rights price to apply | 15.00% | ||
Series A Junior Participating Preferred Stock [Member] | |||
Class of Warrant or Right [Line Items] | |||
Junior Participating Preferred Stock par value | 0.001 | ||
Series A Junior Participating Preferred Stock [Member] | Rights [Member] | |||
Class of Warrant or Right [Line Items] | |||
Number of securities into which each warrant or right may be converted | 0.01 |
SHAREHOLDERS_EQUITY_AND_NONCON9
SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (Schedule of noncontrolling interest) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Noncontrolling Interest disclosures [Line Items] | |||
Balance at the beginning of the period | $8,132 | $8,184 | |
Net income (loss) | -62 | -52 | -90 |
Balance at the end of the period | $8,070 | $8,132 | $8,184 |
Sustainable Water Resources, LLC [Member] | |||
Noncontrolling Interest disclosures [Line Items] | |||
Third party ownership interest (as a percent) | 25.00% |
INCOME_TAXES_Narrative_Details
INCOME TAXES (Narrative) (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Operating Loss Carryforwards [Line Items] | |||
EOR credit carryforwards | $7,946,000 | $7,946,000 | |
Alternative minimum tax credit carryforwards | 15,694,000 | 18,452,000 | |
Valuation allowance | 5,638,000 | 1,230,000 | |
Income Tax Expense (Benefit) | 79,170,000 | 205,868,000 | 247,912,000 |
Unrecognized tax benefits, penalties and interest expense | 0 | ||
Kodiak [Member] | |||
Operating Loss Carryforwards [Line Items] | |||
Federal operating loss carryforwards | 170,000,000 | ||
Operating loss carryforwards, maximum utilization per year | 77,000,000 | ||
Operating loss carryforwards, expiration period | 3 years | ||
Whiting Resources Corporation [Member] | |||
Operating Loss Carryforwards [Line Items] | |||
Income Tax Expense (Benefit) | 0 | ||
Federal [Member] | |||
Operating Loss Carryforwards [Line Items] | |||
Federal operating loss carryforwards | 1,700,000,000 | ||
Net operating loss carryforwards related to tax deductions that deviate from compensation expense | $70,000,000 |
INCOME_TAXES_Schedule_of_incom
INCOME TAXES (Schedule of income expense) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
INCOME TAXES [Abstract] | |||
Federal | ($2,758) | $7,060 | |
State | 5,383 | -6,074 | -669 |
Total current income tax expense (refund) | 2,625 | 986 | -669 |
Federal | 65,522 | 196,787 | 233,468 |
State | 11,023 | 8,095 | 15,113 |
Total deferred income tax expense | 76,545 | 204,882 | 248,581 |
Total income tax expense | $79,170 | $205,868 | $247,912 |
INCOME_TAXES_Reconciliation_of
INCOME TAXES (Reconciliation of statutory income tax expense to income expense) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
INCOME TAXES [Abstract] | |||
U.S. statutory income tax rate (as a percent) | 35.00% | 35.00% | 35.00% |
U.S. statutory income tax expense | $50,371 | $200,155 | $231,704 |
State income taxes, net of federal benefit | 12,705 | 13,962 | 14,444 |
State income tax credits | -10,525 | ||
Statutory depletion | -618 | -796 | -620 |
Enacted changes in state tax laws | 3,700 | -1,416 | |
Market-based equity awards | 2,805 | ||
Permanent items | 3,504 | 2,122 | 1,524 |
Transaction costs | 6,936 | ||
Other | -233 | 2,366 | 860 |
Total income tax expense | $79,170 | $205,868 | $247,912 |
INCOME_TAXES_Components_of_def
INCOME TAXES (Components of deferred income tax assets and liabilities) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
INCOME TAXES [Abstract] | ||
Net operating loss carryforward | $588,330 | $438,922 |
Production Participation Plan Liability | 26,942 | 32,245 |
Tax sharing liability | 9,439 | |
Asset retirement obligations | 13,791 | 23,642 |
Underwriter fees | 14,065 | 10,974 |
Restricted stock compensation | 15,527 | 13,384 |
Premium on Senior Notes | 7,979 | |
EOR credit carryforwards | 7,946 | 7,946 |
Alternative minimum tax credit carryforwards | 15,694 | 18,452 |
Transaction costs | 7,957 | |
Other | 9,493 | 3,234 |
Total deferred income tax assets | 707,724 | 558,238 |
Less valuation allowances | -5,638 | -1,230 |
Net deferred income tax assets | 702,086 | 557,008 |
Oil and gas properties | 1,785,926 | 1,675,916 |
Trust distributions | 129,437 | 149,332 |
Derivative instruments | 64,898 | 10,438 |
Total deferred income tax liabilities | 1,980,261 | 1,835,686 |
Total net deferred income tax liabilities | $1,278,175 | $1,278,678 |
INCOME_TAXES_Net_deferred_inco
INCOME TAXES (Net deferred income tax liabilities) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
INCOME TAXES [Abstract] | ||
Current deferred income taxes | ||
Current deferred income taxes | 47,545 | 648 |
Non-current deferred income taxes | 1,230,630 | 1,278,030 |
Total net deferred income tax liabilities | $1,278,175 | $1,278,678 |
INCOME_TAXES_Liabilities_for_u
INCOME TAXES (Liabilities for unrecognized tax benefits) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2012 | Dec. 31, 2014 | Dec. 31, 2013 |
INCOME TAXES [Abstract] | |||
Balance at the beginning of the period | $299 | $170 | $170 |
Decrease related to tax position taken in a prior period | -129 | ||
Balance at the end of the period | $170 | $170 | $170 |
EARNINGS_PER_SHARE_Narrative_D
EARNINGS PER SHARE (Narrative) (Details) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Restricted Stock [Member] | |||
Shares excluded from Earnings Per Share calculation [Line Items] | |||
Stock options excluded from earnings per share calculation (in shares) | 803,902 | 173,778 | 141,807 |
Stock options [Member] | |||
Shares excluded from Earnings Per Share calculation [Line Items] | |||
Restricted stock excluded from earnings per share calculation (in shares) | 791 | 8,689 | 7,720 |
EARNINGS_PER_SHARE_Reconciliat
EARNINGS PER SHARE (Reconciliation between basic and diluted earnings per share)(Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||||
Share data 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 | ||
Numerator: | |||||||||||||
Net income available to shareholders | $64,807,000 | $366,055,000 | $414,189,000 | ||||||||||
Preferred stock dividends | -494,000 | [1] | -1,077,000 | [1] | |||||||||
Net income available to common shareholders, basic | 64,807,000 | 365,561,000 | 413,112,000 | ||||||||||
Denominator: | |||||||||||||
Weighted average shares outstanding, basic | 122,138 | 118,260 | 117,601 | ||||||||||
Numerator: | |||||||||||||
Net income available to common shareholders, basic | 64,807,000 | 365,561,000 | 413,112,000 | ||||||||||
Preferred stock dividends | 538,000 | 1,077,000 | |||||||||||
Adjusted net income available to common shareholders, diluted | 64,807,000 | 366,099,000 | 414,189,000 | ||||||||||
Denominator: | |||||||||||||
Weighted average shares outstanding, basic | 122,138 | 118,260 | 117,601 | ||||||||||
Restricted stock and stock options (in shares) | 381 | 957 | 633 | ||||||||||
Convertible perpetual preferred stock (in shares) | 371 | 794 | |||||||||||
Weighted average shares outstanding, diluted | 122,519 | 119,588 | 119,028 | ||||||||||
Earnings per common share, basic (in dollars per share) | ($2.69) | $1.33 | $1.27 | $0.92 | ($0.50) | $1.72 | $1.14 | $0.73 | $0.53 | $3.09 | $3.51 | ||
Earnings per common share, diluted (in dollars per share) | ($2.68) | $1.32 | $1.26 | $0.91 | ($0.50) | $1.71 | $1.14 | $0.72 | $0.53 | $3.06 | $3.48 | ||
Decrease in accumulated preferred stock dividends | $0 | $40,000 | $0 | ||||||||||
[1] | For the year ended December 31, 2013, amount includes a decrease of $0.04 million in preferred stock dividends for preferred stock dividends accumulated. There were no accumulated dividend adjustments for the years ended December 31, 2014 or 2012. |
RELATED_PARTY_TRANSACTIONS_Nar
RELATED PARTY TRANSACTIONS (Narrative) (Details) (USD $) | 12 Months Ended | 0 Months Ended | 1 Months Ended | 12 Months Ended | |
In Millions, except Share data, unless otherwise specified | Dec. 31, 2014 | Jan. 28, 2015 | Mar. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
MBoe | |||||
Whiting USA Trust I [Member] | |||||
Related Party Transaction [Line Items] | |||||
Percentage of ownership in subsidiary | 15.80% | ||||
Whiting's ownership interest (in units) | 2,186,389 | ||||
Payments of unit distributions, net of state tax withholdings | $30 | ||||
Distributions back from the trust | 5 | ||||
Whiting USA Trust I [Member] | Subsequent Event [Member] | |||||
Related Party Transaction [Line Items] | |||||
Termination of net profits interest, cumulative production from underlying properties (in MBOE) | 9,110 | ||||
Proved producing reserves conveyed (in MBOE) | 8,200 | ||||
Alliant Energy Corporation [Member] | |||||
Related Party Transaction [Line Items] | |||||
Percentage of tax benefits due to affiliate related to step-up of tax basis assets | 90.00% | ||||
Payments under agreement | 26 | 2 | 2 | ||
Interest expense | $3 | $3 | $2 | ||
Working interest in offshore platforms (as a percent) | 6.00% | ||||
Number of offshore platforms in California that the Company has working interest in | 3 |
RELATED_PARTY_TRANSACTIONS_Sum
RELATED PARTY TRANSACTIONS (Summary of related party receivable and payable balances) (Details) (Whiting USA Trust I [Member], USD $) | Dec. 31, 2014 | Dec. 31, 2013 | ||
In Thousands, unless otherwise specified | ||||
Whiting USA Trust I [Member] | ||||
Related Party Transaction [Line Items] | ||||
Unit distributions due from Trust I | $652 | [1] | $1,093 | [1] |
Unit distributions payable to Trust I | $4,133 | [2] | $6,932 | [2] |
Percentage of ownership in subsidiary | 15.80% | |||
[1] | This amount represents Whitingbs 15.8% interest in the net proceeds due from Trust I and is included within accounts receivable trade, net in the Companybs consolidated balance sheets. | |||
[2] | This amount represents net proceeds from Trust Ibs underlying properties that the Company has received between the last Trust I distribution date and December 31, 2014 and 2013, respectively, but which the Company has not yet distributed to Trust I as of December 31, 2014 and 2013, respectively. Due to ongoing processing of Trust I revenues and expenses after December 31, 2014 and 2013, the amount of Whitingbs next scheduled distribution to Trust I, and the related distribution by Trust I to its unitholders, will differ from this amount. These amounts are included within accounts payable trade in the Companybs consolidated balance sheet. |
COMMITMENTS_AND_CONTINGENCIES_1
COMMITMENTS AND CONTINGENCIES (Narrative) (Details) (USD $) | 12 Months Ended | 2 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Feb. 27, 2015 |
contract | ||||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||||
Rental expense | $7 | $5 | $6 | |
Subsequent Event [Member] | ||||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||||
Number of contracts with drilling rig companies terminated early | 5 | |||
Termination penalties | 27 | |||
Dickinson, North Dakota office [Member] | ||||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||||
Administrative office space (in square feet) | 20,000 | |||
Midland, Texas office [Member] | ||||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||||
Administrative office space (in square feet) | 47,900 | |||
Expiration 2016 [Member] | Denver, Colorado office [Member] | ||||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||||
Administrative office space (in square feet) | 36,300 | |||
Expiration 2016 And 2017 [Member] | Subsequent Event [Member] | ||||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||||
Number of contracts with drilling rig companies | 13 | |||
Expiration 2019 [Member] | Denver, Colorado office [Member] | ||||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||||
Administrative office space (in square feet) | 197,000 | |||
Drilling Rig Contracts [Member] | ||||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||||
Number of contracts with drilling rig companies | 18 | |||
Termination penalties | 212 | |||
Amount spent under contractual commitment | $106 | $93 | $101 | |
Drilling Rig Contracts [Member] | Expiration 2016 [Member] | ||||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||||
Number of contracts with drilling rig companies | 7 | |||
Drilling Rig Contracts [Member] | Expiration 2017 [Member] | ||||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||||
Number of contracts with drilling rig companies | 6 |
COMMITMENTS_AND_CONTINGENCIES_2
COMMITMENTS AND CONTINGENCIES (Narrative II) (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
contract | |||
Unrecorded Unconditional Purchase Obligation [Line Items] | |||
Number of pipeline transportation agreements | 3 | ||
Ship-Or-Pay Arrangements [Member] | |||
Unrecorded Unconditional Purchase Obligation [Line Items] | |||
Number of Ship or pay agreements | 2 | ||
Future commitments under purchase agreements | $20,000,000 | ||
Crude oil [Member] | |||
Unrecorded Unconditional Purchase Obligation [Line Items] | |||
Delivery commitments for year 2015 | 12,400 | ||
Delivery commitments for year 2016 | 17,800 | ||
Delivery commitments for year 2017 | 19,600 | ||
Delivery commitments for year 2018 | 21,500 | ||
Delivery commitments for year 2019 | 23,300 | ||
Delivery commitments for year 2020 | 6,000 | ||
Anticipated under-delivery of contractual volume | 10,400 | ||
Impact on earnings and financing needs resulting from inability to meet oil and gas delivery commitments | 49,000,000 | ||
Period in which under-delivery of volume is anticipated | 5 years | ||
Take-Or-Pay Agreements [Member] | |||
Unrecorded Unconditional Purchase Obligation [Line Items] | |||
Number of take or pay purchase agreements | 3 | ||
Payments under purchase contracts | 105,000,000 | 84,000,000 | 83,000,000 |
Future commitments under purchase agreements | 149,000,000 | ||
Pipeline Transportation Agreements [Member] | |||
Unrecorded Unconditional Purchase Obligation [Line Items] | |||
Future commitments under purchase agreements | 94,438,000 | ||
Natural Gas, CO2 And Water Contracts [Member] | |||
Unrecorded Unconditional Purchase Obligation [Line Items] | |||
Payments under purchase contracts | 13,000,000 | 4,000,000 | 3,000,000 |
Future commitments under purchase agreements | $114,000,000 | ||
Expiration 2015 [Member] | Ship-Or-Pay Arrangements [Member] | |||
Unrecorded Unconditional Purchase Obligation [Line Items] | |||
Number of Ship or pay agreements | 1 | ||
Expiration 2015 [Member] | Take-Or-Pay Agreements [Member] | |||
Unrecorded Unconditional Purchase Obligation [Line Items] | |||
Number of take or pay purchase agreements | 1 | ||
Expiration 2017 [Member] | Ship-Or-Pay Arrangements [Member] | |||
Unrecorded Unconditional Purchase Obligation [Line Items] | |||
Number of Ship or pay agreements | 1 | ||
Expiration 2017 [Member] | Take-Or-Pay Agreements [Member] | |||
Unrecorded Unconditional Purchase Obligation [Line Items] | |||
Number of take or pay purchase agreements | 2 | ||
Expiration 2024 [Member] | |||
Unrecorded Unconditional Purchase Obligation [Line Items] | |||
Number of pipeline transportation agreements | 1 | ||
Expiration 2025 [Member] | |||
Unrecorded Unconditional Purchase Obligation [Line Items] | |||
Number of pipeline transportation agreements | 2 |
COMMITMENTS_AND_CONTINGENCIES_3
COMMITMENTS AND CONTINGENCIES (Minimum future payments under non-cancelable operating leases and unconditional purchase obligations) (Details) (USD $) | Dec. 31, 2014 |
In Thousands, unless otherwise specified | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
2015 | $159,781 |
2016 | 119,124 |
2017 | 46,957 |
2018 | 16,252 |
2019 | 15,403 |
Thereafter | 50,307 |
Total | 407,824 |
Non-Cancelable Leases [Member] | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
2015 | 7,692 |
2016 | 7,547 |
2017 | 6,610 |
2018 | 6,693 |
2019 | 5,844 |
Thereafter | 216 |
Total | 34,602 |
Drilling Rig Contracts [Member] | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
2015 | 146,141 |
2016 | 101,855 |
2017 | 30,788 |
Total | 278,784 |
Pipeline Transportation Agreements [Member] | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
2015 | 5,948 |
2016 | 9,722 |
2017 | 9,559 |
2018 | 9,559 |
2019 | 9,559 |
Thereafter | 50,091 |
Total | $94,438 |
SUBSEQUENT_EVENT_Details
SUBSEQUENT EVENT (Details) (Senior Notes [Member], Subsequent Event [Member], Kodiak [Member], USD $) | 0 Months Ended | |
Jan. 07, 2015 | Jan. 07, 2015 | |
Senior Notes [Member] | Subsequent Event [Member] | Kodiak [Member] | ||
Subsequent Event [Line Items] | ||
Percentage of redemption price | 101.00% | |
Outstanding debt | $1,550,000,000 | $1,550,000,000 |
OIL_AND_GAS_ACTIVITIES_Schedul
OIL AND GAS ACTIVITIES (Schedule of cost Incurred in oil and gas producing activities) (Details) (USD $) | 12 Months Ended | ||||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 08, 2014 | ||||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||||||
Development | $2,891,893,000 | [1] | $2,132,824,000 | [1] | $1,667,182,000 | [1] | |
Proved property acquisition | 2,278,855,000 | [2] | 232,572,000 | [2] | 19,785,000 | [2] | |
Unproved property acquisition | 1,035,439,000 | [2] | 174,103,000 | [2] | 119,175,000 | [2] | |
Exploration | 216,587,000 | 363,234,000 | 436,084,000 | ||||
Total | 6,422,774,000 | 2,902,733,000 | 2,242,226,000 | ||||
Addition to Oil and Gas Properties for Asset Retirement Costs related to new wells drilled or acquired | 45,000,000 | 30,000,000 | 36,000,000 | ||||
Proved properties | 12,956,834,000 | 9,196,845,000 | |||||
Unproved leasehold costs | 1,232,040,000 | 372,298,000 | |||||
Kodiak [Member] | |||||||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||||||
Proved properties | 2,266,607,000 | ||||||
Unproved leasehold costs | $1,000,396,000 | ||||||
[1] | During 2014, 2013 and 2012, non-cash additions to oil and gas properties of $45 million, $30 million and $36 million, respectively, which relate to estimated costs of the future plugging and abandonment of the Companybs oil and gas wells, are included in development costs in the table above. | ||||||
[2] | During 2014, amounts include $2.3 billion of non-cash proved property additions and $1.0 billion of non-cash unproved property additions related to the Kodiak Acquisition. |
OIL_AND_GAS_ACTIVITIES_Net_cap
OIL AND GAS ACTIVITIES (Net capitalized costs related to the Companybs oil and gas producing activities) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
OIL AND GAS ACTIVITIES [Abstract] | ||
Proved oil and gas properties | $12,956,834 | $9,196,845 |
Unproved oil and gas properties | 1,992,868 | 868,305 |
Accumulated depletion | -3,003,270 | -2,645,841 |
Oil and gas properties, net | $11,946,432 | $7,419,309 |
OIL_AND_GAS_ACTIVITIES_Net_cha
OIL AND GAS ACTIVITIES (Net changes in capitalized exploratory well costs) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
OIL AND GAS ACTIVITIES [Abstract] | |||
Balance at the beginning of the period | $85,378 | $108,861 | $90,519 |
Additions to capitalized exploratory well costs pending the determination of proved reserves | 145,336 | 281,951 | 384,223 |
Reclassifications to wells, facilities and equipment based on the determination of proved reserves | -200,869 | -291,962 | -358,625 |
Capitalized exploratory well costs charged to expense | -15,552 | -13,472 | -7,256 |
Balance at the end of the period | 14,293 | 85,378 | 108,861 |
Capitalized exploratory cost for exploratory wells in progress | $0 |
DISCLOSURES_ABOUT_OIL_AND_GAS_2
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (Narrative) (Details) (USD $) | 12 Months Ended | 240 Months Ended | ||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 1995 | Dec. 31, 1994 | Dec. 31, 2014 |
Percentage of proved reserve quantities and related future cash flows reviewed by independent petroleum engineers | 100.00% | 100.00% | ||||
Increase (Decrease) in undiscounted future cash flow if hedging impact considered | ($7) | $0 | ($20) | |||
Maximum [Member] | ||||||
Percentage of overriding royalty interest allocated | 3.00% | |||||
Percentage of oil and gas sales less lease operating expenses and production taxes allocated | 5.00% | 5.00% | 5.00% | |||
Minimum [Member] | ||||||
Percentage of overriding royalty interest allocated | 2.00% | |||||
Percentage of oil and gas sales less lease operating expenses and production taxes allocated | 1.75% | 1.75% | 1.75% |
DISCLOSURES_ABOUT_OIL_AND_GAS_3
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (Summary of changes in quantities of proved oil and gas reserve) (Details) | 12 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
MBoe | MBoe | MBoe | MBoe | |
Reserve Quantities [Line Items] | ||||
Beginning balance of proved oil and gas reserve | 438,542 | 378,760 | 345,249 | |
Extensions and discoveries | 174,811 | 108,772 | 81,479 | |
Sales of minerals in place | -2,130 | -43,838 | -10,611 | |
Purchase of minerals in place | 195,609 | 17,146 | ||
Production | -41,804 | -34,342 | -30,209 | |
Revisions to previous estimates | 15,288 | 12,044 | -7,148 | |
Ending balance of proved oil and gas reserves | 780,316 | 438,542 | 378,760 | |
Proved developed reserves | 412,234 | 252,446 | 241,864 | 238,300 |
Proved undeveloped reserves | 368,082 | 186,096 | 136,896 | 106,949 |
Oil [Member] | ||||
Reserve Quantities [Line Items] | ||||
Beginning balance of proved oil and gas reserve | 347,421 | 301,285 | 260,144 | |
Extensions and discoveries | 146,122 | 88,293 | 68,134 | |
Sales of minerals in place | -1,642 | -36,992 | -7,960 | |
Purchases of minerals in place | 169,586 | 14,543 | ||
Production | -33,485 | -27,035 | -23,139 | |
Revisions to previous estimates | 15,627 | 7,327 | 4,106 | |
Ending balance of proved oil and gas reserves | 643,629 | 347,421 | 301,285 | |
Proved developed reserves | 333,593 | 198,204 | 190,845 | 180,975 |
Proved undeveloped reserves | 310,036 | 149,217 | 110,440 | 79,169 |
NGLs [Member] | ||||
Reserve Quantities [Line Items] | ||||
Beginning balance of proved oil and gas reserve | 44,869 | 40,098 | 37,609 | |
Extensions and discoveries | 12,947 | 9,830 | 6,526 | |
Sales of minerals in place | -4,777 | -320 | ||
Purchases of minerals in place | 1,311 | |||
Production | -3,283 | -2,821 | -2,766 | |
Revisions to previous estimates | 151 | 1,228 | -951 | |
Ending balance of proved oil and gas reserves | 54,684 | 44,869 | 40,098 | |
Proved developed reserves | 28,935 | 23,721 | 24,204 | 22,109 |
Proved undeveloped reserves | 25,749 | 21,148 | 15,894 | 15,500 |
Natural Gas [Member] | ||||
Reserve Quantities [Line Items] | ||||
Beginning balance of proved oil and gas reserve | 277,514 | 224,264 | 284,975 | |
Extensions and discoveries | 94,452 | 63,893 | 40,915 | |
Sales of minerals in place | -2,925 | -12,411 | -13,987 | |
Purchases of minerals in place | 156,140 | 7,751 | ||
Production | -30,218 | -26,917 | -25,827 | |
Revisions to previous estimates | -2,943 | 20,934 | -61,812 | |
Ending balance of proved oil and gas reserves | 492,020 | 277,514 | 224,264 | |
Proved developed reserves | 298,237 | 183,129 | 160,893 | 211,297 |
Proved undeveloped reserves | 193,783 | 94,385 | 63,371 | 73,678 |
DISCLOSURES_ABOUT_OIL_AND_GAS_4
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (Summary of changes in quantities of proved oil and gas reserve-Narrative) (Details) | 12 Months Ended | ||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Sep. 20, 2013 | Dec. 08, 2014 | |
MBoe | item | item | item | item | |
item | MBoe | MBoe | |||
Reserve Quantities [Line Items] | |||||
Extensions and discoveries | 174,811 | 108,772 | 81,479 | ||
Sales of minerals in place | 2,130 | 43,838 | 10,611 | ||
Purchase of minerals in place | 195,609 | 17,146 | |||
Revisions to previous estimates | 15,288 | 12,044 | -7,148 | ||
Revisions to estimated caused by higher crude oil prices incorporated into the Company's reserve estimates | 15,600 | 4,900 | 11,800 | ||
Revisions to estimated attributable to reservoir analysis and well performance | 300 | 7,100 | 4,700 | ||
Williston Basin [Member] | |||||
Reserve Quantities [Line Items] | |||||
Number of wells acquired | 121 | ||||
Kodiak [Member] | |||||
Reserve Quantities [Line Items] | |||||
Number of wells acquired | 778 |
DISCLOSURES_ABOUT_OIL_AND_GAS_5
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
In Thousands, unless otherwise specified | ||||
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES [Abstract] | ||||
Future cash flows | $59,949,707 | $35,178,399 | $29,308,752 | |
Future production costs | -20,772,234 | -12,973,292 | -11,397,332 | |
Future development costs | -7,924,573 | -5,355,383 | -3,181,618 | |
Future income tax expense | -8,579,237 | -3,954,401 | -4,278,529 | |
Future net cash flows | 22,673,663 | 12,895,323 | 10,451,273 | |
10% annual discount for estimated timing of cash flows | -11,830,243 | -6,301,462 | -5,044,240 | |
Standardized measure of discounted future net cash flows | $10,843,420 | $6,593,861 | $5,407,033 | $5,272,492 |
DISCLOSURES_ABOUT_OIL_AND_GAS_6
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (Changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES [Abstract] | |||
Beginning of year | $6,593,861 | $5,407,033 | $5,272,492 |
Sale of oil and gas produced, net of production costs | -2,274,682 | -2,010,925 | -1,589,665 |
Sales of minerals in place | -48,532 | -1,064,195 | -438,614 |
Net changes in prices and production costs | 81,522 | 902,916 | -1,061,495 |
Extensions, discoveries and improved recoveries | 3,950,413 | 2,827,321 | 3,708,780 |
Previously estimated development costs incurred during the period | 1,149,926 | 832,096 | 526,982 |
Changes in estimated future development costs | -3,382,849 | -1,264,189 | -1,498,592 |
Purchases of minerals in place | 4,420,417 | 445,669 | |
Revisions of previous quantity estimates | 345,775 | 313,069 | -295,432 |
Net change in income taxes | -651,817 | -335,637 | 255,328 |
Accretion of discount | 659,386 | 540,703 | 527,249 |
End of year | $10,843,420 | $6,593,861 | $5,407,033 |
DISCLOSURES_ABOUT_OIL_AND_GAS_7
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves calculating average sales prices) (Details) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Oil (per Bbl) [Member] | |||
Weighted Average Sales Price [Line Items] | |||
Weighted average sales price | 84.69 | 90.8 | 87.15 |
NGLs (per Bbl) [Member] | |||
Weighted Average Sales Price [Line Items] | |||
Weighted average sales price | 46.59 | 54.38 | 58.15 |
Natural Gas (per Mcf) [Member] | |||
Weighted Average Sales Price [Line Items] | |||
Weighted average sales price | 5.88 | 4.3 | 3.21 |
QUARTERLY_FINANCIAL_DATA_Detai
QUARTERLY FINANCIAL DATA (Details) (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 | ||||||||
QUARTERLY FINANCIAL DATA [Abstract] | |||||||||||||||||||
Oil, NGL and natural gas sales | $672,553 | $805,054 | $825,760 | $721,250 | $703,024 | $706,543 | $651,868 | $605,114 | $3,024,617 | $2,666,549 | $2,137,714 | ||||||||
Operating profit | 177,722 | [1] | 326,215 | [1] | 370,033 | [1] | 311,169 | [1] | 280,311 | [1] | 316,764 | [1] | 269,528 | [1] | 252,806 | [1] | |||
Net income | ($353,693) | $157,961 | $151,426 | $109,051 | ($59,276) | $204,091 | $134,944 | $86,244 | $64,745 | $366,003 | $414,099 | ||||||||
Basic (in dollars per share) | ($2.69) | $1.33 | $1.27 | $0.92 | ($0.50) | $1.72 | $1.14 | $0.73 | $0.53 | $3.09 | $3.51 | ||||||||
Diluted (in dollars per share) | ($2.68) | $1.32 | $1.26 | $0.91 | ($0.50) | $1.71 | $1.14 | $0.72 | $0.53 | $3.06 | $3.48 | ||||||||
[1] | Oil, NGL and natural gas sales less lease operating expense, production taxes and depreciation, depletion and amortization. |
SCHEDULE_I_CONDENSED_FINANCIAL1
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (Condensed balance sheets) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Condensed Financial Statements, Captions [Line Items] | ||
Current assets | $842,999 | $1,069,618 |
TOTAL ASSETS | 14,019,504 | 8,833,470 |
Current liabilities | 1,208,516 | 777,685 |
Long-term debt | 5,628,782 | 2,653,834 |
Other long-term liabilities | 20,486 | 4,212 |
Shareholders' equity | 5,694,974 | 3,828,567 |
TOTAL LIABILITIES AND EQUITY | 14,019,504 | 8,833,470 |
Whiting Petroleum Corporation [Member] | ||
Condensed Financial Statements, Captions [Line Items] | ||
Current assets | 3,859 | 5,120 |
Investment in subsidiaries | 5,464,763 | 2,707,184 |
Intercompany receivable | 2,907,270 | 3,796,321 |
TOTAL ASSETS | 8,375,892 | 6,508,625 |
Current liabilities | 27,738 | 26,054 |
Long-term debt | 2,653,180 | 2,653,834 |
Other long-term liabilities | 170 | |
Shareholders' equity | 5,694,974 | 3,828,567 |
TOTAL LIABILITIES AND EQUITY | $8,375,892 | $6,508,625 |
SCHEDULE_I_CONDENSED_FINANCIAL2
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (Condensed statements of operations and comprehensive income) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Condensed Financial Statements, Captions [Line Items] | |||
General and administrative | ($177,211) | ($137,994) | ($108,573) |
Interest expense | -170,642 | -112,936 | -75,210 |
INCOME BEFORE INCOME TAXES | 143,915 | 571,871 | 662,011 |
Income tax benefit | 79,170 | 205,868 | 247,912 |
NET INCOME AVAILABLE TO SHAREHOLDERS | 64,807 | 366,055 | 414,189 |
COMPREHENSIVE INCOME ATTRIBUTABLE TO WHITING | 64,807 | 367,291 | 412,713 |
Whiting Petroleum Corporation [Member] | |||
Condensed Financial Statements, Captions [Line Items] | |||
General and administrative | -1,010 | -1,131 | -16,506 |
Interest expense | -1,864 | -2,922 | -2,168 |
Equity in earnings of subsidiaries | 66,100 | 361,732 | 425,870 |
INCOME BEFORE INCOME TAXES | 63,226 | 357,679 | 407,196 |
Income tax benefit | 1,581 | 8,376 | 6,993 |
NET INCOME AVAILABLE TO SHAREHOLDERS | 64,807 | 366,055 | 414,189 |
COMPREHENSIVE INCOME ATTRIBUTABLE TO WHITING | $64,807 | $366,055 | $414,189 |
SCHEDULE_I_CONDENSED_FINANCIAL3
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (Condensed statements of cash flows) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Condensed Financial Statements, Captions [Line Items] | |||
Cash flows provided by operating activities | $1,815,302 | $1,744,745 | $1,401,215 |
Redemption of 7% Senior Subordinated Notes due 2014 | -253,988 | ||
Net cash provided by financing activities | 423,855 | 812,414 | 408,092 |
Beginning of period | 699,460 | 44,800 | 15,811 |
End of period | 78,100 | 699,460 | 44,800 |
Fair value of equity issued and debt assumed in the Kodiak Acquisition | 4,289,088 | ||
Preferred stock dividends paid | -538 | -1,077 | |
Whiting Petroleum Corporation [Member] | |||
Condensed Financial Statements, Captions [Line Items] | |||
Cash flows provided by operating activities | 16,423 | ||
Intercompany receivable | 26,373 | -2,048,253 | -14,094 |
Redemption of 7% Senior Subordinated Notes due 2014 | -253,988 | ||
Other financing activities | -26,373 | -1,759 | -2,329 |
Net cash provided by financing activities | -16,423 | ||
Fair value of equity issued and debt assumed in the Kodiak Acquisition | 2,696,094 | ||
Distributions from Whiting USA Trust I | 4,614 | 4,749 | 5,827 |
Preferred stock dividends paid | -538 | -1,077 | |
5% Senior Notes due 2019 [Member] | Senior Notes [Member] | |||
Condensed Financial Statements, Captions [Line Items] | |||
Issuance of Senior Notes | 1,100,000 | ||
Interest Rate (as a percent) | 5.00% | 5.00% | |
5% Senior Notes due 2019 [Member] | Senior Notes [Member] | Whiting Petroleum Corporation [Member] | |||
Condensed Financial Statements, Captions [Line Items] | |||
Issuance of Senior Notes | 1,100,000 | ||
Interest Rate (as a percent) | 5.00% | 5.00% | 5.00% |
5.75% Senior Notes due 2021 [Member] | Senior Notes [Member] | |||
Condensed Financial Statements, Captions [Line Items] | |||
Issuance of Senior Notes | 1,204,000 | ||
Interest Rate (as a percent) | 5.75% | 5.75% | |
5.75% Senior Notes due 2021 [Member] | Senior Notes [Member] | Whiting Petroleum Corporation [Member] | |||
Condensed Financial Statements, Captions [Line Items] | |||
Issuance of Senior Notes | $1,204,000 | ||
Interest Rate (as a percent) | 5.75% | 5.75% | |
7% Senior Subordinated Notes due 2014 [Member] | Senior Subordinated Notes [Member] | |||
Condensed Financial Statements, Captions [Line Items] | |||
Interest Rate (as a percent) | 7.00% | ||
7% Senior Subordinated Notes due 2014 [Member] | Senior Subordinated Notes [Member] | Whiting Petroleum Corporation [Member] | |||
Condensed Financial Statements, Captions [Line Items] | |||
Interest Rate (as a percent) | 7.00% |
SCHEDULE_I_CONDENSED_FINANCIAL4
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (Basis of presentation) (Details) (Whiting Petroleum Corporation [Member], USD $) | Dec. 31, 2014 |
In Billions, unless otherwise specified | |
Whiting Petroleum Corporation [Member] | |
Restricted net assets | $6.90 |
SCHEDULE_I_CONDENSED_FINANCIAL5
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (Long-term debt and other-long term liabilities) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2010 | Sep. 30, 2013 | Sep. 26, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt | $5,628,782 | $2,653,834 | ||||
Senior Subordinated Notes [Member] | 6.5% Senior Subordinated Notes due 2018 [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate on debt instrument (as a percent) | 6.50% | 6.50% | 6.50% | |||
Senior Notes [Member] | 5% Senior Notes due 2019 [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate on debt instrument (as a percent) | 5.00% | 5.00% | 5.00% | |||
Senior Notes [Member] | 5.75% Senior Notes due 2021 [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate on debt instrument (as a percent) | 5.75% | 5.75% | 5.75% | 5.75% | ||
Unamortized debt premium | 3,180 | 3,834 | ||||
Whiting Petroleum Corporation [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt | 2,653,180 | 2,653,834 | ||||
Other | 170 | |||||
Total long-term debt and other long-term liabilities | 2,653,180 | 2,654,004 | ||||
Whiting Petroleum Corporation [Member] | Senior Subordinated Notes [Member] | 6.5% Senior Subordinated Notes due 2018 [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt | 350,000 | 350,000 | ||||
Whiting Petroleum Corporation [Member] | Senior Notes [Member] | 5% Senior Notes due 2019 [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt | 1,100,000 | 1,100,000 | ||||
Interest rate on debt instrument (as a percent) | 5.00% | 5.00% | 5.00% | |||
Whiting Petroleum Corporation [Member] | Senior Notes [Member] | 5.75% Senior Notes due 2021 [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Long-term debt | $1,203,180 | $1,203,834 | ||||
Interest rate on debt instrument (as a percent) | 5.75% | 5.75% |
SCHEDULE_I_CONDENSED_FINANCIAL6
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (Schedule of five succeeding fiscal years of scheduled maturities for long-term debt) (Details) (USD $) | Dec. 31, 2014 | |
In Thousands, unless otherwise specified | ||
2018 | $350,000 | [1] |
2019 | 3,300,000 | [1] |
Whiting Petroleum Corporation [Member] | ||
2018 | 350,000 | |
2019 | 1,100,000 | |
Thereafter | 1,200,000 | |
Total | $2,650,000 | |
[1] | Refer to bKodiak Senior Notes Repurchase Offerb below for more information. |
SCHEDULE_I_CONDENSED_FINANCIAL7
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (Shareholders' equity) (Details) (USD $) | 0 Months Ended | 12 Months Ended | 1 Months Ended | ||
Mar. 31, 2013 | Dec. 31, 2013 | Jun. 30, 2009 | Mar. 31, 2013 | Dec. 31, 2014 | |
Common Stock [Member] | |||||
Class of Stock [Line Items] | |||||
Conversion of preferred stock to common (in shares) | 792,919 | 794,000 | |||
Convertible perpetual preferred stock [Member] | |||||
Class of Stock [Line Items] | |||||
Convertible perpetual preferred stock (as a percent) | 6.25% | ||||
6.25% convertible perpetual preferred stock, shares issued | 3,450,000 | 0 | |||
6.25% convertible perpetual preferred stock, shares issue Price per share (in dollars per share) | $100 | ||||
Preferred stock remained outstanding | 172,129 | 172,129 | 0 | ||
Convertible perpetual preferred stock [Member] | Whiting Petroleum Corporation [Member] | |||||
Class of Stock [Line Items] | |||||
Convertible perpetual preferred stock (as a percent) | 6.25% | ||||
6.25% convertible perpetual preferred stock, shares issued | 3,450,000 | ||||
6.25% convertible perpetual preferred stock, shares issue Price per share (in dollars per share) | $100 | ||||
Preferred stock remained outstanding | 172,129 | 172,129 | 0 | ||
Conversion of preferred stock to common (in shares) | 792,919 |