Document_and_Entity_Informatio
Document and Entity Information Document and Entity Information (USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Feb. 14, 2014 | Jun. 30, 2013 | |
Document And Entity Information [Abstract] | ' | ' | ' |
Document Type | '10-K | ' | ' |
Amendment Flag | 'false | ' | ' |
Document Period End Date | 31-Dec-13 | ' | ' |
Document Fiscal Year Focus | '2013 | ' | ' |
Document Fiscal Period Focus | 'FY | ' | ' |
Trading Symbol | 'unt | ' | ' |
Entity Registrant Name | 'UNIT CORP | ' | ' |
Entity Central Index Key | '0000798949 | ' | ' |
Current Fiscal Year End Date | '--12-31 | ' | ' |
Entity Filer Category | 'Large Accelerated Filer | ' | ' |
Entity Common Stock, Shares Outstanding | ' | 49,232,860 | ' |
Entity Well-known Seasoned Issuer | 'Yes | ' | ' |
Entity Public Float | ' | ' | $1,080,689,810 |
Entity Current Reporting Status | 'Yes | ' | ' |
Entity Voluntary Filers | 'No | ' | ' |
Consolidated_Balance_Sheets
Consolidated Balance Sheets (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Current assets: | ' | ' |
Cash and cash equivalents | $18,593 | $974 |
Accounts receivable (less allowance for doubtful accounts of $5,342 and $5,343 at December 31, 2013 and 2012, respectively) | 139,788 | 146,046 |
Materials and supplies | 10,998 | 8,563 |
Current derivative asset (Note 13) | 515 | 16,552 |
Current income tax receivable | 0 | 901 |
Current deferred tax asset (Note 8) | 13,585 | 8,765 |
Assets held for sale (Note 3) | 15,621 | 0 |
Prepaid expenses and other | 12,931 | 13,843 |
Total current assets | 212,031 | 195,644 |
Oil and natural gas properties, on the full cost method: | ' | ' |
Proved properties | 4,235,712 | 3,822,381 |
Unproved properties not being amortized | 545,588 | 521,659 |
Drilling equipment | 1,477,093 | 1,478,645 |
Gas gathering and processing equipment | 549,422 | 461,629 |
Transportation equipment | 39,666 | 37,728 |
Other | 87,435 | 62,840 |
Property, plant and equipment, gross, total | 6,934,916 | 6,384,882 |
Less accumulated depreciation, depletion, amortization, and impairment | 3,212,225 | 2,907,660 |
Net property and equipment | 3,722,691 | 3,477,222 |
Debt issuance cost | 11,844 | 13,432 |
Goodwill (Note 2) | 62,808 | 62,808 |
Other intangible assets, net | 0 | 680 |
Other assets | 13,016 | 11,334 |
Total assets | 4,022,390 | 3,761,120 |
Current liabilities: | ' | ' |
Accounts payable | 154,062 | 138,811 |
Accrued liabilities (Note 5) | 64,363 | 54,098 |
Income taxes payable | 7,474 | 0 |
Current derivative liabilities (Note 13) | 5,561 | 1,948 |
Current portion of other long-term liabilities (Note 6) | 12,113 | 12,282 |
Total current liabilities | 243,573 | 207,139 |
Long-term debt (Note 6) | 645,696 | 716,359 |
Non-current derivative liabilities (Note 13) | 0 | 562 |
Other long-term liabilities (Note 6) | 158,331 | 166,983 |
Deferred income taxes (Note 8) | 801,398 | 695,776 |
Commitments and contingencies (Note 16) | 0 | 0 |
Shareholders' equity: | ' | ' |
Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued | 0 | 0 |
Common stock, $0.20 par value, 175,000,000 shares authorized, 49,107,004 and 48,581,948 shares issued as of December 31, 2013 and 2012, respectively | 9,659 | 9,594 |
Capital in excess of par value | 445,470 | 423,603 |
Accumulated other comprehensive income (net of tax of $0 and $4,892, respectively) (Note 15) | 0 | 7,587 |
Retained earnings | 1,718,263 | 1,533,517 |
Total shareholders' equity | 2,173,392 | 1,974,301 |
Total liabilities and shareholders' equity | $4,022,390 | $3,761,120 |
Consolidated_Balance_Sheets_Pa
Consolidated Balance Sheets (Parenthetical) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, except Share data, unless otherwise specified | ||
Statement of Financial Position [Abstract] | ' | ' |
Accounts receivable, allowance for doubtful accounts | $5,342 | $5,343 |
Preferred stock, par value | $1 | $1 |
Preferred stock, shares authorized | 5,000,000 | 5,000,000 |
Preferred stock, issued | 0 | 0 |
Common stock, par value | $0.20 | $0.20 |
Common stock, shares authorized | 175,000,000 | 175,000,000 |
Common stock, shares issued | 49,107,004 | 48,581,948 |
Accumulated other comprehensive income, tax | $0 | $4,892 |
Consolidated_Statements_of_Inc
Consolidated Statements of Income (USD $) | 12 Months Ended | ||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Revenues | ' | ' | ' |
Oil and natural gas | $649,718 | $567,944 | $514,614 |
Contract drilling | 414,778 | 529,719 | 484,651 |
Gas gathering and processing | 287,354 | 217,460 | 208,238 |
Total revenues | 1,351,850 | 1,315,123 | 1,207,503 |
Oil and natural gas | ' | ' | ' |
Operating costs | 184,001 | 150,212 | 131,271 |
Depreciation, depletion, and amortization | 226,498 | 211,347 | 183,350 |
Impairment of oil and natural gas properties (Note 2) | 0 | 283,606 | 0 |
Contract drilling | ' | ' | ' |
Operating costs | 247,280 | 289,524 | 269,899 |
Depreciation | 71,194 | 81,007 | 79,667 |
Gas gathering and processing | ' | ' | ' |
Operating costs | 243,406 | 187,292 | 174,859 |
Depreciation, amortization, and impairment | 33,191 | 24,388 | 16,101 |
General and administrative | 38,323 | 33,086 | 30,055 |
(Gain) loss on disposition of assets | -17,076 | -253 | 595 |
Total expenses | 1,026,817 | 1,260,209 | 885,797 |
Income from operations | 325,033 | 54,914 | 321,706 |
Other income (expense): | ' | ' | ' |
Interest, net | -15,015 | -14,137 | -4,167 |
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net | -8,374 | -1,243 | 1,702 |
Other | -175 | -132 | -239 |
Total other expense | -23,564 | -15,512 | -2,704 |
Income before income taxes | 301,469 | 39,402 | 319,002 |
Income tax expense (benefit): | ' | ' | ' |
Current | 15,991 | 696 | -2,416 |
Deferred | 100,732 | 15,530 | 125,551 |
Total income taxes | 116,723 | 16,226 | 123,135 |
Net income | $184,746 | $23,176 | $195,867 |
Net income per common share: | ' | ' | ' |
Basic | $3.83 | $0.48 | $4.11 |
Diluted | $3.80 | $0.48 | $4.08 |
Consolidated_Statements_of_Com
Consolidated Statements of Comprehensive Income (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Net income | $184,746 | $23,176 | $195,867 |
Change in value of derivative instruments used as cash flow hedges, net of tax of ($4,717), $12,094, and $18,412 | -7,349 | 18,635 | 29,384 |
Reclassification - derivative settlements, net of tax of ($249), ($20,171), and ($1,146) | -354 | -31,682 | -1,819 |
Ineffective portion of derivatives, net of tax of $74, $1,008, and ($1,061) | 116 | 1,608 | -1,688 |
Total comprehensive income | $177,159 | $11,737 | $221,744 |
Consolidated_Statements_of_Com1
Consolidated Statements of Comprehensive Income Consolidated Statements of Comprehensive Income (Parenthetical) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Statement of Comprehensive Income Parenthetical [Abstract] | ' | ' | ' |
Change in value of derivative instruments used as cash flow hedges, tax | ($4,717) | $12,094 | $18,412 |
Reclassification - derivative settlements, tax | -249 | -20,171 | -1,146 |
Ineffective portion of derivatives, tax | $74 | $1,008 | ($1,061) |
Consolidated_Statements_of_Cha
Consolidated Statements of Changes in Shareholders' Equity (USD $) | Total | Common Stock | Capital In Excess of Par Value | Accumulated Other Comprehensive Income | Retained Earnings [Member] |
In Thousands, unless otherwise specified | |||||
Beginning balances at Dec. 31, 2010 | ' | ' | ' | ' | ' |
Comprehensive income: | ' | ' | ' | ' | ' |
Net income | $195,867 | $0 | $0 | $0 | $195,867 |
Other comprehensive income, net of tax | 25,877 | 0 | 0 | 25,877 | 0 |
Total comprehensive income | 221,744 | ' | ' | ' | ' |
Activity in employee compensation plans | 14,656 | 48 | 14,608 | 0 | 0 |
Ending balances at Dec. 31, 2011 | 1,947,017 | 9,541 | 408,109 | 19,026 | 1,510,341 |
Comprehensive income: | ' | ' | ' | ' | ' |
Net income | 23,176 | 0 | 0 | 0 | 23,176 |
Other comprehensive income, net of tax | -11,439 | 0 | 0 | -11,439 | 0 |
Total comprehensive income | 11,737 | ' | ' | ' | ' |
Activity in employee compensation plans | 15,547 | 53 | 15,494 | 0 | 0 |
Ending balances at Dec. 31, 2012 | 1,974,301 | 9,594 | 423,603 | 7,587 | 1,533,517 |
Comprehensive income: | ' | ' | ' | ' | ' |
Net income | 184,746 | 0 | 0 | 0 | 184,746 |
Other comprehensive income, net of tax | -7,587 | 0 | 0 | -7,587 | 0 |
Total comprehensive income | 177,159 | ' | ' | ' | ' |
Activity in employee compensation plans | 21,932 | 65 | 21,867 | 0 | 0 |
Ending balances at Dec. 31, 2013 | $2,173,392 | $9,659 | $445,470 | $0 | $1,718,263 |
Consolidated_Statements_of_Cha1
Consolidated Statements of Changes in Shareholders' Equity (Parenthetical) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Activity in employee compensation plans (shares) | 525,056 | 430,506 | 241,011 |
Other comprehensive income, tax | ($4,892) | ($7,069) | $16,205 |
Consolidated_Statements_of_Cas
Consolidated Statements of Cash Flows (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
OPERATING ACTIVITIES: | ' | ' | ' |
Net income | $184,746 | $23,176 | $195,867 |
Adjustments to reconcile net income (loss) to net cash provided (used) by operating activities: | ' | ' | ' |
Depreciation, depletion, amortization, and impairment | 333,907 | 319,021 | 280,451 |
Impairment of oil and natural gas properties (Note 2) | 0 | 283,606 | 0 |
(Gain) loss on derivatives | 5,449 | 53,096 | -159 |
Derivatives settled | 1,161 | -51,853 | -2,254 |
(Gain) loss on disposition of assets | -17,076 | -253 | 595 |
Deferred tax expense | 100,732 | 15,530 | 125,551 |
Employee stock compensation plans | 21,317 | 16,956 | 14,303 |
Bad debt expense | 0 | 90 | 260 |
ARO liability accretion | 5,450 | 4,615 | 3,838 |
Other, net | 2,250 | 781 | 294 |
Changes in operating assets and liabilities increasing (decreasing) cash: | ' | ' | ' |
Accounts receivable | 2,967 | 13,994 | -38,731 |
Materials and supplies | -2,435 | -361 | -1,886 |
Prepaid expenses and other | 1,813 | -3,466 | 22,672 |
Accounts payable | 15,715 | 10,187 | -1,064 |
Accrued liabilities | 17,198 | 6,911 | 9,245 |
Contract advances | 1,137 | -1,119 | -527 |
Net cash provided by operating activities | 674,331 | 690,911 | 608,455 |
INVESTING ACTIVITIES: | ' | ' | ' |
Capital expeditures | -703,984 | -762,381 | -728,551 |
Producing property and other acquisitions | 0 | -598,485 | -50,013 |
Proceeds from disposition of property and equipment | 120,910 | 281,824 | 10,328 |
Other | 3,894 | 0 | 0 |
Net cash used in investing activities | -579,180 | -1,079,042 | -768,236 |
FINANCING ACTIVITIES: | ' | ' | ' |
Borrowings under line of credit | 222,500 | 735,300 | 441,500 |
Payments under line of credit | -293,600 | -714,200 | -554,500 |
Proceeds from issuance of senior subordinated notes, net of debt issuance costs and discount | 0 | 386,274 | 243,950 |
Proceeds from exercise of stock options | 574 | 215 | 679 |
Tax benefit from stock options | 8 | 121 | 1,174 |
Increase (decrease) in book overdrafts (Note 2) | -7,014 | -19,440 | 26,454 |
Net cash provided by (used in) financing activities | -77,532 | 388,270 | 159,257 |
Net increase (decrease) in cash and cash equivalents | 17,619 | 139 | -524 |
Cash and cash equivalents, beginning of year | 974 | 835 | 1,359 |
Cash and cash equivalents, end of year | 18,593 | 974 | 835 |
Supplemental disclosure of cash flow information: | ' | ' | ' |
Interest paid (net of capitalization) | 12,485 | 14,880 | 3,470 |
Income taxes | 9,100 | 5,116 | 655 |
Changes in accounts payable and accrued liabilites related to purchases of property, plant, and equipment | -6,550 | -4,753 | -28,036 |
Non-cash additions to oil and natural gas properties related to asset retirement obligations | ($17,952) | $45,097 | $23,345 |
Organization
Organization | 12 Months Ended |
Dec. 31, 2013 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ' |
Organization | ' |
Unless the context clearly indicates otherwise, references in this report to “Unit”, “Company”, “we”, “our”, “us”, or like terms refer to Unit Corporation and its subsidiaries. | |
We are primarily engaged in the land contract drilling of natural gas and oil wells, the exploration, development, acquisition, and production of oil and natural gas properties, and the buying, selling, gathering, processing, and treating of natural gas. Our operations are located principally in the United States and are organized in the following three reporting segments: (1) Oil and Natural Gas, (2) Contract Drilling, and (3) Mid-Stream. | |
Oil and Natural Gas. Carried out by our subsidiary, Unit Petroleum Company, we explore, develop, acquire, and produce oil and natural gas properties for our own account. Our producing oil and natural gas properties, unproved properties, and related assets are located mainly in Oklahoma and Texas, and to a lesser extent, in Arkansas, Colorado, Kansas, Louisiana, Mississippi, Montana, New Mexico, North Dakota, Pennsylvania, and Wyoming. | |
Historically, our contract drilling segment experienced more demand for natural gas drilling as opposed to drilling for oil and NGLs. With the current natural gas market, operators have been focusing on drilling for oil and NGLs. | |
Contract Drilling. Carried out by our subsidiary, Unit Drilling Company and its subsidiary Unit Texas Drilling, L.L.C., we drill onshore oil and natural gas wells for our own account as well as for a wide range of other oil and natural gas companies. Our drilling operations are mainly located in Oklahoma, Texas, Louisiana, Kansas, Wyoming, Colorado, Utah, Montana, and North Dakota. | |
Mid-Stream. Carried out by our subsidiary, Superior Pipeline Company, L.L.C. and its subsidiaries, we buy, sell, gather, transport, process, and treat natural gas for our own account and for third parties. Mid-stream operations are performed in Oklahoma, Texas, Kansas, Pennsylvania, and West Virginia. |
Summary_Of_Significant_Account
Summary Of Significant Accounting Policies | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
Accounting Policies [Abstract] | ' | ||||||||
Summary Of Significant Accounting Policies | ' | ||||||||
Principles of Consolidation. The consolidated financial statements include the accounts of Unit Corporation and its subsidiaries. Our investment in limited partnerships is accounted for on the proportionate consolidation method, whereby our share of the partnerships’ assets, liabilities, revenues, and expenses are included in the appropriate classification in the accompanying consolidated financial statements. | |||||||||
Certain amounts in the accompanying consolidated financial statements for prior periods have been reclassified to conform to current year presentation. Certain financial statement captions were expanded or combined with no impact to consolidated net income or shareholders' equity. | |||||||||
Accounting Estimates. The preparation of financial statements in conformity with generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and 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. Actual results could differ from those estimates. | |||||||||
Drilling Contracts. We recognize revenues and expenses generated from “daywork” drilling contracts as the services are performed, since we do not bear the risk of completion of the well. Under “footage” and “turnkey” contracts, we bear the risk of completion of the well; therefore, revenues and expenses are recognized when the well is substantially completed. Under this method, substantial completion is determined when the well bore reaches the negotiated depth as stated in the contract. The entire amount of a loss, if any, is recorded when the loss is determinable. The costs of uncompleted drilling contracts include expenses incurred to date on “footage” or “turnkey” contracts, which are still in process at the end of the period, and are included in other current assets. Typically, any one of these three types of contracts can be used for the drilling of one well which can take from 20 to 90 days. At December 31, 2013, all of our contracts were daywork contracts of which 23 were multi-well and had durations which ranged from six months to three years, 22 of which expire in 2014 and one expiring in 2015. These longer term contracts may contain a fixed rate for the duration of the contract or provide for the periodic renegotiation of the rate within a specific range from the existing rate. | |||||||||
Cash Equivalents and Book Overdrafts. We include as cash equivalents all investments with maturities at date of purchase of three months or less which are readily convertible into known amounts of cash. Book overdrafts are checks that have been issued before the end of the period, but not presented to our bank for payment before the end of the period. There were no book overdrafts at December 31, 2013. At December 31, 2012, book overdrafts were $7.0 million and included in accounts payable. | |||||||||
Accounts Receivable. Accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of our customers, and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been unsuccessful. | |||||||||
Financial Instruments and Concentrations of Credit Risk and Non-performance Risk. Financial instruments, which potentially subject us to concentrations of credit risk, consist primarily of trade receivables with a variety of oil and natural gas companies. We do not generally require collateral related to receivables. Our credit risk is considered to be limited due to the large number of customers comprising our customer base. Below are the third-party customers that accounted for more than 10% of our segment’s revenues: | |||||||||
2013 | 2012 | 2011 | |||||||
Oil and Natural Gas: | |||||||||
Valero Energy Corporation | 25 | % | 26 | % | 18 | % | |||
Sunoco Partners Marketing | 8 | % | 8 | % | 10 | % | |||
Drilling: | |||||||||
QEP Resources, Inc. | 18 | % | 15 | % | 22 | % | |||
Kodiak Oil and Gas Corp. | 10 | % | 10 | % | 6 | % | |||
Mid-Stream: | |||||||||
ONEOK, Inc. | 50 | % | 54 | % | 54 | % | |||
Tenaska Resources, LLC | 16 | % | 7 | % | 1 | % | |||
Gavilon, LLC | — | % | 10 | % | 19 | % | |||
We had a concentration of cash of $52.1 million and $40.4 million at December 31, 2013 and 2012, respectively with one bank. | |||||||||
The use of derivative transactions also involves the risk that the counterparties will be unable to meet the financial terms of the transactions. We considered this non-performance risk with regard to our counterparties and our own non-performance risk in our derivative valuation at December 31, 2013 and determined there was no material risk at that time. At December 31, 2013, the fair values of the net assets (liabilities) we had with each of the counterparties with respect to all of our commodity derivative transactions are listed in the table below: | |||||||||
31-Dec-13 | |||||||||
(In millions) | |||||||||
Canadian Imperial Bank of Commerce | $ | 0.5 | |||||||
Scotiabank | (0.3 | ) | |||||||
Bank of Montreal | (5.2 | ) | |||||||
Total assets (liabilities) | $ | (5.0 | ) | ||||||
Property and Equipment. Drilling equipment, natural gas gathering and processing equipment, transportation equipment, and other property and equipment are carried at cost. Renewals and improvements are capitalized while repairs and maintenance are expensed. Depreciation of drilling equipment is recorded using the units-of-production method based on estimated useful lives starting at 15 years , including a minimum provision of 20% of the active rate when the equipment is idle. We use the composite method of depreciation for drill pipe and collars and calculate the depreciation by footage actually drilled compared to total estimated remaining footage. Depreciation of other property and equipment is computed using the straight-line method over the estimated useful lives of the assets ranging from 3 to 15 years. | |||||||||
Realization of the carrying value of property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset including disposal value if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets. Changes in such estimates could cause us to reduce the carrying value of property and equipment. In December 2012, our mid-stream segment had a $1.2 million write down of its Erick system. There was no volume from the wells connected to this system, the compressor and related surface equipment have been removed from this location and there is no future activity anticipated from this gathering system. No significant impairments were recorded in 2013 or 2011. | |||||||||
When property and equipment components are disposed of, the cost and the related accumulated depreciation are removed from the accounts and any resulting gain or loss is generally reflected in operations. For dispositions of drill pipe and drill collars, an average cost for the appropriate feet of drill pipe and drill collars is removed from the asset account and charged to accumulated depreciation and proceeds, if any, are credited to accumulated depreciation. | |||||||||
We record an asset and a liability equal to the present value of the expected future asset retirement obligation (ARO) associated with our oil and gas properties. The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by accreting an interest charge. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense. | |||||||||
Capitalized Interest. During 2013, 2012, and 2011, interest of approximately $33.7 million, $18.9 million, and $11.5 million, respectively, was capitalized based on the net book value associated with unproved properties not being amortized, the construction of additional drilling rigs, and the construction of gas gathering systems. Interest is being capitalized using a weighted average interest rate based on our outstanding borrowings. | |||||||||
Goodwill. Goodwill represents the excess of the cost of acquisitions over the fair value of the net assets acquired. Goodwill is not amortized, but an impairment test is performed at least annually to determine whether the fair value has decreased and is performed additionally when events indicate an impairment may have occurred. Goodwill is all related to our contract drilling segment, and accordingly, the impairment test is generally based on the estimated discounted future net cash flows of our drilling segment, utilizing discount rates and other factors in determining the fair value of our drilling segment. Inputs in our estimated discounted future net cash flows include rig utilization, day rates, gross margin percentages, and terminal value (these are all considered level 3 inputs). No goodwill impairment was recorded for the years ended December 31, 2013, 2012, or 2011. There were no additions to goodwill in 2013, 2012, or 2011. Goodwill of $3.9 million is deductible for tax purposes. | |||||||||
Intangible Assets. Intangible assets are capitalized and amortized over the estimated period benefited. Such amounts are reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. No intangible asset impairment was recorded for the years ended December 31, 2013, 2012, or 2011. Amortization of $0.7 million, $1.2 million and $1.2 million was recorded in 2013, 2012, and 2011, respectively. Accumulated amortization for 2013 and 2012 was $18.0 million and $17.3 million, respectively. Our intangible assets became fully amortized in 2013, so no amortization is expected to be recorded in 2014. | |||||||||
Oil and Natural Gas Operations. We account for our oil and natural gas exploration and development activities using the full cost method of accounting prescribed by the SEC. Accordingly, all productive and non-productive costs incurred in connection with the acquisition, exploration and development of our oil, NGLs, and natural gas reserves, including directly related overhead costs and related asset retirement costs, are capitalized and amortized on a units-of-production method based on proved oil and natural gas reserves. Directly related overhead costs of $21.5 million, $17.6 million, and $15.6 million were capitalized in 2013, 2012, and 2011, respectively. Independent petroleum engineers annually audit our internal evaluation of our reserves. The average rates used for depreciation, depletion, and amortization (DD&A) were $13.32, $14.70, and $15.06 per Boe in 2013, 2012, and 2011, respectively. The calculation of DD&A includes estimated future expenditures to be incurred in developing proved reserves and estimated dismantlement and abandonment costs, net of estimated salvage values. Our unproved properties totaling $545.6 million are excluded from the DD&A calculation. | |||||||||
No gains or losses are recognized on the sale, conveyance or other disposition of oil and natural gas properties unless a significant reserve amount to our total reserves is involved. | |||||||||
Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties. | |||||||||
Under the full cost rules, at the end of each quarter, we review the carrying value of our oil and natural gas properties. The full cost ceiling is based principally on the estimated future discounted net cash flows from our oil and natural gas properties discounted at 10%. We use the unweighted arithmetic average of the commodity prices existing on the first day of each of the 12 months before the end of the reporting period to calculate discounted future revenues, unless prices were otherwise determined under contractual arrangements. In the event the unamortized cost of oil and natural gas properties being amortized exceeds the full cost ceiling, as defined by the SEC, the excess is charged to expense in the period during which such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible. | |||||||||
For the quarter ended June 30, 2012, the 12-month average commodity prices, including the discounted value of our cash flow hedges, decreased significantly, resulting in a non-cash ceiling test write down of $115.9 million pre-tax ($72.1 million, net of tax). Our qualifying cash flow hedges used in the ceiling test determination at June 30, 2012, consisted of swaps and collars, covering production of 2.9 MMBoe in 2012 and 4.5 MMBoe in 2013. The effect of those hedges on the June 30, 2012 ceiling test was a $32.5 million pre-tax increase in the discounted net cash flows of our oil and natural gas properties. | |||||||||
For the quarter ended December 31, 2012, the 12-month average commodity prices, including the discounted value of our cash flow hedges, decreased further, resulting in an additional non-cash ceiling test write down of $167.7 million pre-tax ($104.4 million, net of tax). Our qualifying cash flow hedges used in the ceiling test determination at December 31, 2012, consisted of swaps and collars covering 6.9 MMBoe in 2013. The effect of those hedges on the December 31, 2012 ceiling test was a $29.8 million pre-tax increase in the discounted net cash flows of our oil and natural gas properties. Our oil and natural gas hedging is discussed in Note 13 of the Notes to our Consolidated Financial Statements. | |||||||||
At December 31, 2013, using the existing 12-month average commodity prices, we were not required to record a ceiling test write-down. All cash flow hedges expired at December 31, 2013 and did not effect the ceiling test determination. | |||||||||
If there are declines in the 12-month average prices, we may be required to record a write-down in future periods. | |||||||||
Our contract drilling segment provides drilling services for our exploration and production segment. Depending on their timing some of the drilling services performed on our properties are also deemed to be associated with the acquisition of an ownership interest in the property. Revenues and expenses for such services are eliminated in our income statement, with any profit recognized as a reduction in our investment in our oil and natural gas properties. The contracts for these services are issued under the same conditions and rates as the contracts entered into with unrelated third parties. We eliminated revenue of $64.3 million, $49.6 million, and $52.2 million for 2013, 2012, and 2011, respectively from our contract drilling segment and eliminated the associated operating expense of $46.9 million, $34.1 million, and $32.6 million during 2013, 2012, and 2011, respectively, yielding $17.4 million, $15.5 million, and $19.6 million during 2013, 2012, and 2011, respectively, as a reduction to the carrying value of our oil and natural gas properties. | |||||||||
Gas Gathering and Processing Revenue. Our gathering and processing segment recognizes revenue from the gathering and processing of natural gas and NGLs in the period the service is provided based on contractual terms. | |||||||||
Insurance. We are self-insured for certain losses relating to workers’ compensation, control of well and employee medical benefits. Insured policies for other coverage contain deductibles or retentions per occurrence that range from $50,000 to $1.5 million. We have purchased stop-loss coverage in order to limit, to the extent feasible, per occurrence and aggregate exposure to certain types of claims. However, there is no assurance that the insurance coverage will adequately protect us against liability from all potential consequences. We have elected to use an ERISA governed occupational injury benefit plan to cover all Texas drilling operations in lieu of covering them under Texas Workers’ Compensation. If insurance coverage becomes more expensive, we may choose to self-insure, decrease our limits, raise our deductibles or any combination of these rather than pay higher premiums. | |||||||||
Hedging Activities. All derivatives are recognized on the balance sheet and measured at fair value. Derivatives that are designated as a cash flow hedge are measured by the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, at each reporting period. The effective portion of the gain (loss) on the derivative instrument is recognized in other comprehensive income as a component of equity and subsequently reclassified into earnings when the forecasted transaction affects earnings. The ineffective portion of a derivative’s change in fair value is required to be recognized in earnings immediately. Derivatives that are not designated for hedge treatment are recorded at fair value with gains (losses) recognized in earnings in the period of change. In August 2012, we determined on a prospective basis, to enter into economic hedges without electing cash flow hedge accounting. Our cash flow hedges (that existed before August 2012) expired in December 2013. | |||||||||
We do not engage in derivative transactions for speculative purposes. We document our risk management strategy, and for the cash flow hedges, we tested the hedge effectiveness at the inception of and during the term of each hedge. | |||||||||
Limited Partnerships. Unit Petroleum Company is a general partner in 16 oil and natural gas limited partnerships sold privately and publicly. Some of our officers, directors, and employees own the interests in most of these partnerships. We share in each partnership’s revenues and costs in accordance with formulas set out in each of the limited partnership agreement. The partnerships also reimburse us for certain administrative costs incurred on behalf of the partnerships. | |||||||||
Income Taxes. Measurement of current and deferred income tax liabilities and assets is based on provisions of enacted tax law; the effects of future changes in tax laws or rates are not included in the measurement. Valuation allowances are established where necessary to reduce deferred tax assets to the amount expected to be realized. Income tax expense is the tax payable for the year and the change during that year in deferred tax assets and liabilities. | |||||||||
The accounting for uncertainty in income taxes prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a return. Guidance is also provided on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. We have no unrecognized tax benefits and we do not expect any significant changes in unrecognized tax benefits in the next twelve months. | |||||||||
Natural Gas Balancing. We use the sales method for recording natural gas sales. This method allows for recognition of revenue, which may be more or less than its share of pro-rata production from certain wells. We estimate our December 31, 2013 balancing position to be approximately 5.2 Bcf on under-produced properties and approximately 4.5 Bcf on over-produced properties. We have recorded a receivable of $2.0 million on certain wells where we estimate that insufficient reserves are available for us to recover the under-production from future production volumes. We have also recorded a liability of $3.8 million on certain properties where we believe there are insufficient reserves available to allow the under-produced owners to recover their under-production from future production volumes. Our policy is to expense the pro-rata share of lease operating costs from all wells as incurred. Such expenses relating to the balancing position on wells in which we have imbalances are not material. | |||||||||
Employee and Director Stock Based Compensation. We recognize in our financial statements the cost of employee services received in exchange for awards of equity instruments based on the grant date fair value of those awards. The amount of our equity compensation cost relating to employees directly involved in exploration activities of our oil and natural gas segment is capitalized to our oil and natural gas properties. Amounts not capitalized to our oil and natural gas properties are recognized in general and administrative expense and operating costs of our business segments. We utilize the Black-Scholes option pricing model to measure the fair value of stock options and stock appreciation rights (SARs). The value of our restricted stock grants is based on the closing stock price on the date of the grants. | |||||||||
Impact of Financial Accounting Pronouncements. | |||||||||
Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. In July 2013, ASU 2013-11 was issued because GAAP does not include explicit guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The amendment provides explicit guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The amendments in this Update are effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. Early adoption is permitted. The amendments should be applied prospectively to all unrecognized tax benefits that exist at the effective date. Retrospective application is permitted. We anticipate there will be no effect on our financial position or results of operations when adopted. | |||||||||
Inclusion of the Fed Funds Effective Swap Rate (or Overnight Index Swap Rate) as a Benchmark Interest Rate for Hedge Accounting Purposes. The FASB has issued ASU 2013-10, the amendments in this update permit the Fed Funds Effective Swap Rate (OIS) to be used as a U.S. benchmark interest rate for hedge accounting purposes under Topic 815, in addition to U.S. Treasury and LIBOR. The amendments also remove the restriction on using different benchmark rates for similar hedges. The amendments are effective prospectively for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013. We do not have any interest rate hedges at this time. | |||||||||
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. In February 2013, the FASB issued ASU 2013-02 to address the presentation of comprehensive income related to ASU 2011-05. The standard requires that companies present, either in a single note or parenthetically on the face of the financial statements, the effect of significant amounts reclassified from each component of accumulated other comprehensive income based on its source (e.g., the release due to cash flow hedges from interest rate contracts) and the income statement line items affected by the reclassification (e.g., interest income or interest expense). The amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2012. We chose to present the information in a single note (Note 15 of the Notes to our Consolidated Financial Statements). | |||||||||
Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities. In January 2013, the FASB issued ASU 2013-01 to limit the scope of balance sheet offsetting disclosures contained in previously issued guidance in ASU 2011-11—Disclosures about Offsetting Assets and Liabilities. Specifically, ASU 2011-11 applies only to derivatives, repurchase agreements and reverse purchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with specific criteria contained in the FASB Accounting Standards or subject to a master netting arrangement or similar agreement. | |||||||||
Unlike IFRS, GAAP allows companies the option to present net in their balance sheets derivatives that are subject to a legally enforceable netting arrangement with the same party where rights of set-off are only available in the event of default or bankruptcy. To address these differences between IFRS and GAAP, the FASB and the IASB (the Boards) issued an exposure draft that proposed new criteria for netting that were narrower than the current conditions currently in GAAP. Nevertheless, in response to feedback from their respective stakeholders, the Boards decided to retain their existing offsetting models. Instead, the Boards have issued common disclosure requirements related to offsetting arrangements to allow investors to better compare financial statements prepared in accordance with IFRS or GAAP. The amendments in this ASU require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. An entity is required to apply the amendments for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. An entity should provide the disclosures required by those amendments retrospectively for all comparative periods presented. Derivatives subject to a master netting agreement are the only transactions in this accounting standard that affect us. We provide the effect of netting on our financial position in Note 14 of the Notes to our Consolidated Financial Statements. |
Acquisitions_and_Divestitures
Acquisitions and Divestitures | 12 Months Ended | |||||||
Dec. 31, 2013 | ||||||||
Acquisitions and divestitures [Abstract] | ' | |||||||
Acquisitions and Divestitures | ' | |||||||
On July 20, 2011, we acquired certain producing properties from an unaffiliated seller for approximately $12.3 million in cash, after post-closing adjustments, consisting of 30 operated wells and 59 non-operated well interests located in Beaver, Harper, and Ellis Counties,Oklahoma and Lipscomb County, Texas. The purchase price allocation was $8.4 million for proved properties and $3.9 million for acreage. The acquisition also included in excess of 12,000 net acres held by production available for future development. | ||||||||
On August 31, 2011, we acquired certain producing oil and gas properties for $30.5 million in cash, from an unaffiliated seller. Included in the acquisition were more than 500 wells located principally in the Oklahoma Arkoma Woodford and Hartshorne Coal plays along with other properties located throughout Oklahoma and Texas. The acquisition also included approximately 55,000 net acres of which 96% was held by production. | ||||||||
On September 17, 2012, we closed on the acquisition of certain oil and natural gas assets from Noble Energy, Inc. (Noble). After final closing adjustments, the acquisition included approximately 83,000 net acres primarily in the Granite Wash, Cleveland, and various other plays in western Oklahoma and the Texas Panhandle. The adjusted amount paid was $592.6 million. | ||||||||
As of the effective date of the Noble acquisition (April 1, 2012), the estimated proved reserves of the acquired properties were 44 million barrels of oil equivalent (MMBoe). The acquisition added approximately 24,000 net acres to our Granite Wash core area in the Texas Panhandle with significant resource potential including approximately 600 horizontal drilling locations. The total acreage acquired in other plays in western Oklahoma and the Texas Panhandle was approximately 59,000 net acres and is characterized by high working interest and operatorship, 95% of which was held by production. We also received four gathering systems as part of the transaction and other miscellaneous assets. | ||||||||
The Noble acquisition was accounted for using the acquisition method under ASC 805, Business Combinations, which required that the acquired assets and liabilities be recorded at their fair values as of the acquisition date. The following table summarizes the adjusted purchase price and the estimated values of assets acquired and liabilities assumed. It was based on information available to us at the time these consolidated financial statements were prepared and we believe these estimates are reasonable(in thousands): | ||||||||
Adjusted Purchase Price | ||||||||
Total consideration given | $ | 592,627 | ||||||
Adjusted Allocation of Purchase Price | ||||||||
Oil and natural gas properties included in the full cost pool: | ||||||||
Proved oil and natural gas properties | $ | 260,799 | ||||||
Unproved oil and natural gas properties | 353,343 | |||||||
Total oil and natural gas properties included in the full cost pool (1) | 614,142 | |||||||
Gas gathering and processing equipment and other | 25,163 | |||||||
Asset retirement obligation | (46,678 | ) | ||||||
Fair value of net assets acquired | $ | 592,627 | ||||||
(1) We used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. | ||||||||
Pro Forma Financial Information | ||||||||
The following unaudited pro forma financial information is presented to reflect the operations of the acquired assets as if the acquisition had been completed on January 1, 2011. The unaudited pro forma financial information was derived from the historical accounting records of the seller adjusted for estimated transaction costs, depreciation, depletion and amortization, ceiling test impact, general and administrative expenses, capitalized interest, and interest on the $400.0 million of Notes issued along with additional borrowings under our credit agreement to finance the acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of our expected future results of operations. The pro forma results of operations do not include any cost savings or other synergies that resulted, or may result, from the acquisition or any estimated costs that will be incurred to integrate these assets. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors. | ||||||||
Twelve months ended December 31, | ||||||||
2012 | 2011 | |||||||
(In thousands, except per share amounts) | ||||||||
Pro forma: | ||||||||
Revenues | $ | 1,376,393 | $ | 1,336,227 | ||||
Net income | $ | 83,940 | $ | 229,272 | ||||
Net income per common share: | ||||||||
Basic | $ | 1.75 | $ | 4.81 | ||||
Diluted | $ | 1.74 | $ | 4.78 | ||||
From September 17, 2012, the date of the acquisition, through December 31, 2012, the portion of our revenues that were attributable to Noble were $21.4 million with a net loss of $0.8 million. | ||||||||
2012 Divestitures | ||||||||
We completed the following divestitures in 2012, the proceeds all of which reduced the net book value of the full cost pool with no gain or loss recognized: | ||||||||
•In September 2012, we sold our interest in certain Bakken properties. The proceeds, net of related expenses were $226.6 million. | ||||||||
•In September 2012, we sold certain oil and natural gas assets located in Brazos and Madison Counties, Texas, for approximately $44.1 million. | ||||||||
2012 Other | ||||||||
In conjunction with the acquisition and divestitures completed in the third quarter 2012, we took the necessary steps to secure like-kind exchange tax treatment for the transactions under Section 1031 of the Internal Revenue Code. | ||||||||
2013 Divestitures and Assets Held for Sale | ||||||||
In August 2013, we sold additional Bakken property interests. The proceeds, net of related expenses, were $57.1 million. In addition, we had other non-core asset sales with proceeds, net of related expenses, of $21.7 million for 2013. Proceeds from these dispositions reduced the net book value of the full cost pool with no gain or loss recognized. | ||||||||
During 2013, we sold five 2,000-3,000 horsepower drilling rigs to unaffiliated third-parties for a gain of $16.5 million. Four of our idle drilling rigs were classified as assets held for sale at December 31, 2013 and were sold to an unaffiliated third-party in the first quarter of 2014. The proceeds for the sale of these assets, less costs to sell, is expected to exceed the approximate $15.6 million net book value of the drilling rigs, both in the aggregate and for each drilling rig with an estimated gain of $10.4 million. |
Earnings_Per_Share
Earnings Per Share | 12 Months Ended | |||||||||||
Dec. 31, 2013 | ||||||||||||
Earnings Per Share [Abstract] | ' | |||||||||||
Earnings Per Share | ' | |||||||||||
The following data shows the amounts used in computing earnings per share: | ||||||||||||
Income | Weighted | Per-Share | ||||||||||
(Numerator) | Shares | Amount | ||||||||||
(Denominator) | ||||||||||||
(In thousands except per share amounts) | ||||||||||||
For the year ended December 31, 2013: | ||||||||||||
Basic earnings per common share | $ | 184,746 | 48,218 | $ | 3.83 | |||||||
Effect of dilutive stock options, restricted stock, and SARs | — | 354 | (0.03 | ) | ||||||||
Diluted earnings per common share | $ | 184,746 | 48,572 | $ | 3.8 | |||||||
For the year ended December 31, 2012: | ||||||||||||
Basic earnings per common share | $ | 23,176 | 47,909 | $ | 0.48 | |||||||
Effect of dilutive stock options, restricted stock, and SARs | — | 245 | — | |||||||||
Diluted earnings per common share | $ | 23,176 | 48,154 | $ | 0.48 | |||||||
For the year ended December 31, 2011: | ||||||||||||
Basic earnings per common share | $ | 195,867 | 47,658 | $ | 4.11 | |||||||
Effect of dilutive stock options, restricted stock, and SARs | — | 293 | (0.03 | ) | ||||||||
Diluted earnings per common share | $ | 195,867 | 47,951 | $ | 4.08 | |||||||
The following options and their average exercise prices were not included in the computation of diluted earnings per share because the option exercise prices were greater than the average market price of our common stock for the years ended December 31: | ||||||||||||
2013 | 2012 | 2011 | ||||||||||
Options and SARs | 149,665 | 250,901 | 105,000 | |||||||||
Average exercise price | $ | 58.41 | $ | 52.72 | $ | 61.24 | ||||||
Accrued_Liabilities
Accrued Liabilities | 12 Months Ended | |||||||
Dec. 31, 2013 | ||||||||
Accrued Liabilities [Abstract] | ' | |||||||
Accrued Liabilities | ' | |||||||
Accrued liabilities consisted of the following as of December 31: | ||||||||
2013 | 2012 | |||||||
(In thousands) | ||||||||
Employee costs | $ | 27,633 | $ | 24,632 | ||||
Lease operating expenses | 16,073 | 10,903 | ||||||
Interest payable | 6,504 | 6,568 | ||||||
Deposits on assets held for sale | 3,750 | — | ||||||
Taxes | 2,313 | 7,308 | ||||||
Hedge settlements | 416 | 160 | ||||||
Other | 7,674 | 4,527 | ||||||
Total accrued liabilities | $ | 64,363 | $ | 54,098 | ||||
LongTerm_Debt_And_Other_LongTe
Long-Term Debt And Other Long-Term Liabilities | 12 Months Ended | |||||||
Dec. 31, 2013 | ||||||||
Long-term debt and other long-term liabilites [Abstract] | ' | |||||||
Long-term Debt | ' | |||||||
Long-Term Debt | ||||||||
Long-term debt consisted of the following as of December 31: | ||||||||
2013 | 2012 | |||||||
(In thousands) | ||||||||
Credit agreement with an average interest rates of 2.9% at December 31, 2012 | $ | — | $ | 71,100 | ||||
6.625% senior subordinated notes due 2021, net of unamortized discount of $4.3 million and $4.7 million at December 31, 2013 and 2012, respectively | 645,696 | 645,259 | ||||||
Total long-term debt | $ | 645,696 | $ | 716,359 | ||||
Credit Agreement. Under our Senior Credit Agreement (credit agreement), the amount available to be borrowed is the lesser of the amount we elect (from time to time) as the commitment amount ($500.0 million) or the value of the borrowing base as determined by the lenders ($800.0 million), but in either event not to exceed the maximum credit agreement amount of $900.0 million. We are charged a commitment fee ranging from 0.375 to 0.50 of 1% on the amount available but not borrowed. The rate varies based on the amount borrowed as a percentage of the amount of the total borrowing base. The credit agreement matures as of September 13, 2016. In connection with this new amendment, we paid $1.5 million in origination, agency, syndication, and other related fees when the credit agreement was amended on September 5, 2012. We are amortizing these fees over the life of the credit agreement. | ||||||||
The amount of the borrowing base, which is subject to redetermination by the lenders on April 1st and October 1st of each year, is based primarily on a percentage of the discounted future value of our oil and natural gas reserves. There was no change to the borrowing base as of the October 1, 2013 redetermination. We or the lenders may request a onetime special redetermination of the borrowing base between each scheduled redetermination. In addition, we may request a redetermination following the completion of an acquisition that meets the requirements set forth in the credit agreement. | ||||||||
At our election, any part of the outstanding debt under the credit agreement may be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest is computed as the sum of the LIBOR base for the applicable term plus 1.75% to 2.50% depending on the level of debt as a percentage of the borrowing base and is payable at the end of each term, or every 90 days, whichever is less. Borrowings not under LIBOR bear interest at the Prime Rate, which cannot be less than LIBOR plus 1.00%. Interest is payable at the end of each month, and the principal may be repaid in whole or in part at anytime, without a premium or penalty. At December 31, 2013, we had no outstanding borrowings under our credit agreement. | ||||||||
We can use borrowings for financing general working capital requirements for (a) exploration, development, production and acquisition of oil and gas properties, (b) acquisitions and operation of mid-stream assets, (c) issuance of standby letters of credit, (d) contract drilling services, and (e) general corporate purposes. | ||||||||
The credit agreement prohibits, among other things: | ||||||||
• | the payment of dividends (other than stock dividends) during any fiscal year in excess of 30% of our consolidated net income for the preceding fiscal year; | |||||||
• | the incurrence of additional debt with certain limited exceptions; and | |||||||
• | the creation or existence of mortgages or liens, other than those in the ordinary course of business, on any of our properties, except in favor of our lenders. | |||||||
The credit agreement also requires that we have at the end of each quarter: | ||||||||
• | a current ratio (as defined in the credit agreement) of not less than 1 to 1; and | |||||||
• | a leverage ratio of funded debt to consolidated EBITDA (as defined in the credit agreement) for the most recently ended rolling four fiscal quarters of no greater than 4 to 1. | |||||||
As of December 31, 2013, we were in compliance with the covenants contained in the credit agreement. | ||||||||
6.625% Senior Subordinated Notes. On May 18, 2011, we completed the sale of $250.0 million aggregate principal amount of registered senior subordinated notes due 2021 (the 2011 Notes) which bear interest at a rate of 6.625% per year. The Notes were issued at par and mature on May 15, 2021. We received net proceeds of approximately $244.0 million after deducting fees of approximately $6.0 million. Those fees are being amortized as deferred financing costs over the life of the Notes. We used the net proceeds to repay outstanding borrowings under our credit agreement, which was $220.3 million on May 18, 2011. The remaining proceeds were used for general working capital purposes. | ||||||||
On July 24, 2012, we completed the sale of $400.0 million aggregate principal amount of unregistered senior subordinated notes (the 2012 Notes) due May 15, 2021, which will bear interest at a rate of 6.625% per year. The 2012 Notes were sold at 98.75% of par plus accrued interest from May 15, 2012. We used the net proceeds from the offering to partially finance the acquisition of oil and natural gas properties from Noble. We incurred $8.7 million of fees that are being amortized as debt issuance cost over the life of the 2012 Notes. | ||||||||
On November 13, 2012, we registered with the SEC on Form S-4 an offer to exchange the 2012 Notes for additional notes with materially identical terms to our existing 2011 Notes, which were registered under the Securities Act. On January 7, 2013, the exchange of the 2012 Notes was completed. The notes issued in exchange for the 2012 Notes are now registered and treated as a single series of debt securities with the 2011 Notes, bringing the total to $650.0 million aggregate principal amount of 6.625% senior subordinated notes (the Notes). The interest is payable semi-annually (in arrears) on May 15 and November 15 of each year, and the Notes will mature on May 15, 2021. | ||||||||
The Notes are guaranteed by our 100% owned domestic direct and indirect subsidiaries (the Guarantors). Unit, as the parent company, has no independent assets or operations. The guarantees registered under the registration statement are full and unconditional and joint and several, subject to certain automatic customary releases, including sale, disposition, or transfer of the capital stock or substantially all of the assets of a subsidiary guarantor, exercise of legal defeasance option or covenant defeasance option, and designation of a subsidiary guarantor as unrestricted in accordance with the Indenture. Any subsidiaries of Unit other than the Guarantors are minor. There are no significant restrictions on the ability of Unit to receive funds from its subsidiaries through dividends, loans, advances or otherwise. | ||||||||
The Notes are subject to an Indenture dated as of May 18, 2011, between us and Wilmington Trust, National Association (successor to Wilmington Trust FSB), as Trustee (the Trustee), as supplemented by the First Supplemental Indenture thereto dated as of May 18, 2011, between us, the Guarantors, and the Trustee, and as further supplemented by that the Second Supplemental Indenture thereto dated as of January 7, 2013, between us, the Guarantors and the Trustee, establishing the terms and providing for the issuance of the Notes (as supplemented, the 2011 Indenture). The discussion of the Notes in this report is qualified by and subject to the actual terms of the 2011 Indenture. | ||||||||
On and after May 15, 2016, we may redeem all or, from time to time, a part of the Notes at certain redemption prices, plus accrued and unpaid interest. Before May 15, 2014, we may on any one or more occasions redeem up to 35% of the original principal amount of the Notes with the net cash proceeds of one or more equity offerings at a redemption price of 106.625% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, provided that at least 65% of the original principal amount of the Notes remains outstanding after each redemption. In addition, at any time before May 15, 2016, we may redeem the Notes, in whole or in part, at a redemption price equal to 100% of the principal amount plus a “make whole” premium, plus accrued and unpaid interest, if any, to the redemption date. If a “change of control” occurs, subject to certain conditions, we must offer to repurchase from each holder all or any part of that holder’s Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued and unpaid interest, if any, to the date of purchase. The Indenture contains customary events of default. The Indenture contains covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to incur or guarantee additional indebtedness; pay dividends on our capital stock or redeem capital stock or subordinated indebtedness; transfer or sell assets; make investments; incur liens; enter into transactions with our affiliates; and merge or consolidate with other companies. We were in compliance with all covenants of the Notes as of December 31, 2013. | ||||||||
Other Long-Term Liabilities | ||||||||
Other long-term liabilities consisted of the following as of December 31: | ||||||||
2013 | 2012 | |||||||
(In thousands) | ||||||||
ARO liability | $ | 133,657 | $ | 146,159 | ||||
Workers’ compensation | 20,041 | 18,517 | ||||||
Separation benefit plans | 9,382 | 7,972 | ||||||
Gas balancing liability | 3,775 | 3,838 | ||||||
Deferred compensation plan | 3,589 | 2,779 | ||||||
170,444 | 179,265 | |||||||
Less current portion | 12,113 | 12,282 | ||||||
Total other long-term liabilities | $ | 158,331 | $ | 166,983 | ||||
Estimated annual principal payments under the terms of debt and other long-term liabilities from 2014 through 2018 are $12.1 million, $2.8 million, $40.4 million, $4.2 million, and $3.5 million, respectively. |
Asset_Retirement_Obligations
Asset Retirement Obligations | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
Asset Retirement Obligation Disclosure [Abstract] | ' | ||||||||
Asset Retirement Obligations | ' | ||||||||
We are required to record the estimated fair value of the liabilities relating to the future retirement of our long-lived assets (AROs). Our oil and natural gas wells are plugged and abandoned when the oil and natural gas reserves in those wells are depleted or the wells are no longer able to produce. The plugging and abandonment liability for a well is recorded in the period in which the obligation is incurred (at the time the well is drilled or acquired). None of our assets are restricted for purposes of settling these AROs. All of our AROs relate to plugging costs associated with our oil and gas wells. | |||||||||
The following table shows certain information about our AROs for the periods indicated: | |||||||||
2013 | 2012 | ||||||||
(In thousands) | |||||||||
ARO liability, January 1: | $ | 146,159 | $ | 96,446 | |||||
Accretion of discount | 5,450 | 4,615 | |||||||
Liability incurred | 4,857 | 56,650 | (1) | ||||||
Liability settled | (4,751 | ) | (2,788 | ) | |||||
Liability sold | (2,622 | ) | (1,258 | ) | |||||
Revision of estimates (2) | (15,436 | ) | (7,506 | ) | |||||
ARO liability, December 31: | 133,657 | 146,159 | |||||||
Less current portion | 2,954 | 2,953 | |||||||
Total long-term ARO liability | $ | 130,703 | $ | 143,206 | |||||
_________________________ | |||||||||
-1 | The liability incurred increased $46.7 million related to the Noble properties acquired in September 2012. | ||||||||
-2 | Plugging liability estimates were revised in both 2013 and 2012 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments as well as changes in estimated timing of cash flows. |
Income_Taxes
Income Taxes | 12 Months Ended | |||||||||||
Dec. 31, 2013 | ||||||||||||
Income Tax Disclosure [Abstract] | ' | |||||||||||
Income Taxes | ' | |||||||||||
A reconciliation of income tax expense, computed by applying the federal statutory rate to pre-tax income to our effective income tax expense is as follows: | ||||||||||||
2013 | 2012 | 2011 | ||||||||||
(In thousands) | ||||||||||||
Income tax expense computed by applying the statutory rate | $ | 105,514 | $ | 13,791 | $ | 111,651 | ||||||
State income tax, net of federal benefit | 8,290 | 1,084 | 8,941 | |||||||||
Statutory depletion and other | 2,919 | 1,351 | 2,543 | |||||||||
Income tax expense | $ | 116,723 | $ | 16,226 | $ | 123,135 | ||||||
For the periods indicated, the total provision for income taxes consisted of the following: | ||||||||||||
2013 | 2012 | 2011 | ||||||||||
(In thousands) | ||||||||||||
Current taxes: | ||||||||||||
Federal | $ | 15,845 | $ | 2,084 | $ | (3,159 | ) | |||||
State | 146 | (1,388 | ) | 743 | ||||||||
15,991 | 696 | (2,416 | ) | |||||||||
Deferred taxes: | ||||||||||||
Federal | 87,839 | 13,768 | 109,363 | |||||||||
State | 12,893 | 1,762 | 16,188 | |||||||||
100,732 | 15,530 | 125,551 | ||||||||||
Total provision | $ | 116,723 | $ | 16,226 | $ | 123,135 | ||||||
Deferred tax assets and liabilities are comprised of the following at December 31: | ||||||||||||
2013 | 2012 | |||||||||||
(In thousands) | ||||||||||||
Deferred tax assets: | ||||||||||||
Allowance for losses and nondeductible accruals | $ | 77,285 | $ | 74,890 | ||||||||
Net operating loss carryforward | 61,055 | 56,020 | ||||||||||
Alternative minimum tax credit carryforward | 17,258 | 1,972 | ||||||||||
155,598 | 132,882 | |||||||||||
Deferred tax liability: | ||||||||||||
Depreciation, depletion, amortization and impairment | (943,411 | ) | (819,893 | ) | ||||||||
Net deferred tax liability | (787,813 | ) | (687,011 | ) | ||||||||
Current deferred tax asset | 13,585 | 8,765 | ||||||||||
Non-current—deferred tax liability | $ | (801,398 | ) | $ | (695,776 | ) | ||||||
Realization of the deferred tax assets are dependent on generating sufficient future taxable income. Although realization is not assured, management believes it is more likely than not that the deferred tax asset will be realized. The amount of the deferred tax asset considered realizable, however, could be reduced in the near-term if estimates of future taxable income are reduced. At December 31, 2013, we have federal net operating loss carryforwards of approximately $146.5 million which expire from 2015 to 2033. |
Employee_Benefit_Plans
Employee Benefit Plans | 12 Months Ended |
Dec. 31, 2013 | |
Employee benefit plans [Abstract] | ' |
Employee Benefit Plans | ' |
Under our 401(k) Employee Thrift Plan, employees who meet specified service requirements may contribute a percentage of their total compensation, up to a specified maximum, to the plan. We may match each employee’s contribution, up to a specified maximum, in full or on a partial basis. We made discretionary contributions under the plan of 111,995, 95,598, and 71,742 shares of common stock and recognized expense of $6.0 million, $5.5 million, and $4.3 million in 2013, 2012, and 2011, respectively. | |
We provide a salary deferral plan (Deferral Plan) which allows participants to defer the recognition of salary for income tax purposes until actual distribution of benefits which occurs at either termination of employment, death or certain defined unforeseeable emergency hardships. The liability recorded under the Deferral Plan at December 31, 2013 and 2012 was $3.6 million and $2.8 million, respectively. We recognized payroll expense and recorded a liability at the time of deferral. | |
Effective January 1, 1997, we adopted a separation benefit plan (Separation Plan). The Separation Plan allows eligible employees whose employment is involuntarily terminated or, in the case of an employee who has completed 20 years of service, voluntarily or involuntarily terminated, to receive benefits equivalent to four weeks salary for every whole year of service completed up to a maximum of 104 weeks. To receive payments, the recipient must waive any claims against us in exchange for receiving the separation benefits. On October 28, 1997, we adopted a Separation Benefit Plan for Senior Management (Senior Plan). The Senior Plan provides certain officers and key executives of Unit with benefits generally equivalent to the Separation Plan. The Compensation Committee of the Board of Directors has absolute discretion in the selection of the individuals covered in this plan. On May 5, 2004 we also adopted the Special Separation Benefit Plan (Special Plan). This plan is identical to the Separation Benefit Plan with the exception that the benefits under the plan vest on the earliest of a participant’s reaching the age of 65 or serving 20 years with the company. | |
On December 31, 2008, we amended all three Plans to be in compliance with Section 409A of the Internal Revenue Code of 1986, as amended. The key amendments to the Plans address, among other things, when distributions may be made, the timing of payments, and the circumstances under which employees become eligible to receive benefits. None of the amendments materially increase the benefits, grants or awards issuable under the Plans. We recognized expense of $2.4 million, $2.2 million, and $1.9 million in 2013, 2012, and 2011, respectively, for benefits associated with anticipated payments from these separation plans. | |
We have entered into key employee change of control contracts with three of our current executive officers. These severance contracts have an initial three-year term that is automatically extended for one year on each anniversary, unless a notice not to extend is given by us. If a change of control of the company, as defined in the contracts, occurs during the term of the severance contract, then the contract becomes operative for a fixed three-year period. The severance contracts generally provide that the executive’s terms and conditions for employment (including position, work location, compensation, and benefits) will not be adversely changed during the three-year period after a change of control. If the executive’s employment is terminated (other than for cause, death, or disability), the executive terminates for good reason during such three-year period, or the executive terminates employment for any reason during the 30-day period following the first anniversary of the change of control, and on certain terminations prior to a change of control or in connection with or in anticipation of a change of control, the executive is generally entitled to receive, in addition to certain other benefits, any earned but unpaid compensation; up to 2.9 times the executive’s base salary plus annual bonus (based on historic annual bonus); and the company matching contributions that would have been made had the executive continued to participate in the company’s 401(k) plan for up to an additional three years. | |
The severance contract provides that the executive is entitled to receive a payment in an amount sufficient to make the executive whole for any excise tax on excess parachute payments imposed under Section 4999 of the Code. As a condition to receipt of these severance benefits, the executive must remain in the employ of the company prior to change of control and render services commensurate with his position. |
Transactions_With_Related_Part
Transactions With Related Parties | 12 Months Ended | |||||||||||
Dec. 31, 2013 | ||||||||||||
Related Party Transactions [Abstract] | ' | |||||||||||
Transactions With Related Parties | ' | |||||||||||
Unit Petroleum Company serves as the general partner of 16 oil and gas limited partnerships. Three were formed for investment by third parties and 13 (the employee partnerships) were formed to allow certain of our qualified employees and our directors to participate in Unit Petroleum’s oil and gas exploration and production operations. The partnerships for the third party investments were formed in 1984 and 1986. Employee partnerships have been formed for each year beginning with 1984 and ending with 2011. Interests in the employee partnerships were offered to the employees of Unit and its subsidiaries whose annual base compensation was at least a specified amount ($36,000 for 2011) and to the directors of Unit. | ||||||||||||
The employee partnerships formed in 1984 through 1990 were consolidated into a single consolidating partnership in 1993 and the employee partnerships formed in 1991 through 1999 were also consolidated into the consolidating partnership in 2002. The consolidation of the 1991 through the 1999 employee partnerships was done by the general partners under the authority contained in the respective partnership agreements and did not involve any vote, consent or approval by the limited partners. The employee partnerships have each had a set percentage (ranging from 1% to 15%) of our interest in most of the oil and natural gas wells we drill or acquire for our own account during the particular year for which the partnership was formed. The total interest the employees have in our oil and natural gas wells by participating in these partnerships does not exceed one percent. | ||||||||||||
Amounts received in the years ended December 31, from both public and private Partnerships for which Unit is a general partner are as follows: | ||||||||||||
2013 | 2012 | 2011 | ||||||||||
(In thousands) | ||||||||||||
Contract drilling | $ | 16 | $ | 246 | $ | 352 | ||||||
Well supervision and other fees | $ | 470 | $ | 434 | $ | 396 | ||||||
General and administrative expense reimbursement | $ | 36 | $ | 39 | $ | 610 | ||||||
Related party transactions for contract drilling and well supervision fees are the related party’s share of such costs. These costs are billed to related parties on the same basis as billings to unrelated parties for such services. General and administrative reimbursements are both direct general and administrative expense incurred on the related party’s behalf and indirect expenses allocated to the related parties. Such allocations are based on the related party’s level of activity and are considered by management to be reasonable. | ||||||||||||
One of our directors, G. Bailey Peyton IV, also serves as the President and a significant investor in Upland Resources, L.L.C., a small independent oil and natural gas exploration company, and as Manager of Peyton Royalties, LP, a family-controlled limited partnership that owns royalty rights in wells in the Texas and Oklahoma Panhandles. In the ordinary course of business, there were no wells drilled for Upland Resources, L.L.C. during 2013 or 2011 and the Company drilled three wells during 2012, under its usual standard dayrate contracts, in which Upland Resources, L.L.C. was a participant, for which the Company received payments of approximately $1.6 million from Upland Resources, L.L.C. The Company also paid royalties during 2013 and 2012, primarily due to its status as successor in interest to prior transactions and as operator of the wells involved and, in some cases, as lessee, with respect to certain wells in which Mr. Peyton, members of Mr. Peyton's family, and Peyton Royalties, LP have an interest. Such payments totaled approximately $1.4 million, $1.2 million, and $0.7 million during 2013, 2012, and 2011, respectively. Our Audit Committee and the board, in accordance with the Policy, have determined that these arrangements are in the best interest of the Company. |
Shareholder_Rights_Plan
Shareholder Rights Plan | 12 Months Ended |
Dec. 31, 2013 | |
Shareholder Rights Plan [Abstract] | ' |
Shareholder Rights Plan | ' |
We maintain a Shareholder Rights Plan (the Plan) designed to deter coercive or unfair takeover tactics, to prevent a person or group from gaining control of us without offering fair value to all our shareholders and to deter other abusive takeover tactics, which are not in the best interest of shareholders. | |
Under the terms of the Plan, each share of common stock is accompanied by one right, which given certain acquisition and business combination criteria, entitles the shareholder to purchase from us one one-hundredth of a newly issued share of Series A Participating Cumulative Preferred Stock at a price subject to adjustment by us or to purchase from an acquiring company certain shares of its common stock or the surviving company’s common stock at 50% of its value. | |
The rights become exercisable 10 days after we learn that an acquiring person (as defined in the Plan) has acquired 15% or more of the outstanding common stock of Unit or 10 business days after the commencement of a tender offer, which would result in a person owning 15% or more of our shares. We can redeem the rights for $0.01 per right at any date before the earlier of (i) the close of business on the 10th day following the time we learn that a person has become an acquiring person or (ii) May 19, 2015 (the “Expiration Date”). The rights will expire on the Expiration Date, unless redeemed earlier by Unit. |
StockBased_Compensation
Stock-Based Compensation | 12 Months Ended | |||||||||||
Dec. 31, 2013 | ||||||||||||
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | ' | |||||||||||
Stock-Based Compensation | ' | |||||||||||
For restricted stock awards and stock options, we had: | ||||||||||||
2013 | 2012 | 2011 | ||||||||||
(In millions) | ||||||||||||
Recognized stock compensation expense | $ | 16.1 | $ | 11.4 | $ | 10 | ||||||
Capitalized stock compensation cost for our oil and natural gas properties | 3.5 | 2.7 | 2.5 | |||||||||
Tax benefit on stock based compensation | 6.2 | 4.5 | 3.9 | |||||||||
The remaining unrecognized compensation cost related to unvested awards at December 31, 2013 is approximately $14.2 million with $2.4 million of this amount anticipated to be capitalized. The weighted average period of time over which this cost will be recognized is 0.8 years. | ||||||||||||
At our annual meeting of stockholders held on May 2, 2012, our stockholders approved the Unit Corporation Stock and Incentive Compensation Plan Amended and Restated May 2, 2012 (the amended plan). The amended plan allows us to grant stock-based and cash-based compensation to our employees (including employees of subsidiaries) as well as non-employee directors. The amended plan succeeds the Non-employee Directors' 2000 Stock Option Plan (the option plan), and no new awards will be issued under the option plan. | ||||||||||||
The amended plan allows for the issuance of 3.3 million shares of common stock with 2.0 million shares being the maximum number of shares that can be issued as “incentive stock options.” Awards under this plan may be granted in any one or a combination of the following: | ||||||||||||
• | incentive stock options under Section 422 of the Internal Revenue Code; | |||||||||||
• | non-qualified stock options; | |||||||||||
• | performance shares; | |||||||||||
• | performance units; | |||||||||||
• | restricted stock; | |||||||||||
• | restricted stock units; | |||||||||||
• | stock appreciation rights; | |||||||||||
• | cash based awards; and | |||||||||||
• | other stock-based awards. | |||||||||||
This plan also contains various limits as to the amount of awards that can be given to an employee in any fiscal year. All awards are generally subject to the minimum vesting periods, as determined by our Compensation Committee and included in the award agreement. | ||||||||||||
The table below shows the estimates of the fair value of stock options granted to our non-employee directors under the option plan in 2011 using the Black-Scholes model and applying the estimated values also presented in the table: | ||||||||||||
2011 | ||||||||||||
Options granted | 31,500 | |||||||||||
Estimated fair value (in millions) | $ | 0.7 | ||||||||||
Estimate of stock volatility | 0.48 | |||||||||||
Estimated dividend yield | — | % | ||||||||||
Risk free interest rate | 2 | % | ||||||||||
Expected life range based on prior experience (in years) | 5 | |||||||||||
Forfeiture rate | — | % | ||||||||||
Expected volatilities are based on the historical volatility of our stock. We use historical data to estimate option exercise and termination rates within the model and aggregate groups that have similar historical exercise behavior for valuation purposes. To date, we have not paid dividends on our stock. The risk free interest rate is computed from the United States Treasury Strips rate using the term over which it is anticipated the grant will be exercised. | ||||||||||||
SARs | ||||||||||||
Activity pertaining to SARs granted under the Unit Corporation Stock and Incentive Compensation Plan is as follows: | ||||||||||||
Number of | Weighted | |||||||||||
Shares | Average | |||||||||||
Grant Date | ||||||||||||
Price | ||||||||||||
Outstanding at January 1, 2011 | 145,901 | $ | 46.59 | |||||||||
Granted | — | — | ||||||||||
Exercised | — | — | ||||||||||
Forfeited | — | — | ||||||||||
Outstanding at December 31, 2011 | 145,901 | 46.59 | ||||||||||
Granted | — | — | ||||||||||
Exercised | — | — | ||||||||||
Forfeited | — | — | ||||||||||
Outstanding at December 31, 2012 | 145,901 | 46.59 | ||||||||||
Granted | — | — | ||||||||||
Exercised | — | — | ||||||||||
Forfeited | — | — | ||||||||||
Outstanding at December 31, 2013 | 145,901 | $ | 46.59 | |||||||||
There were no SARs granted in 2013, 2012, or 2011. The SARs expire after 10 years from the date of the grant. In 2013 and 2012, no shares vested. In 2011, 33,745 shares vested. The aggregate intrinsic value of the 145,901 shares outstanding at December 31, 2013 was $0.7 million with a weighted average remaining contractual term of 3.6 years. | ||||||||||||
Restricted Stock | ||||||||||||
Activity pertaining to restricted stock awards granted under the amended plan is as follows: | ||||||||||||
Employees | Number of | Weighted | ||||||||||
Shares | Average | |||||||||||
Grant Date | ||||||||||||
Price | ||||||||||||
Nonvested at January 1, 2011 | 446,125 | $ | 47.39 | |||||||||
Granted | 211,050 | 55.91 | ||||||||||
Vested | (190,262 | ) | 43.32 | |||||||||
Forfeited | (18,952 | ) | 44.55 | |||||||||
Nonvested at December 31, 2011 | 447,961 | 47.44 | ||||||||||
Granted | 376,445 | 47.37 | ||||||||||
Vested | (220,788 | ) | 45.66 | |||||||||
Forfeited | (14,091 | ) | 45.37 | |||||||||
Nonvested at December 31, 2012 | 589,527 | 48.11 | ||||||||||
Granted | 453,549 | 48.2 | ||||||||||
Vested | (248,003 | ) | 46.46 | |||||||||
Forfeited | (18,330 | ) | 47.85 | |||||||||
Nonvested at December 31, 2013 | 776,743 | $ | 48.7 | |||||||||
Non-Employee Directors | Number of | Weighted | ||||||||||
Shares | Average | |||||||||||
Grant Date | ||||||||||||
Price | ||||||||||||
Nonvested at December 31, 2011 | — | $ | — | |||||||||
Granted | 24,606 | 40.23 | ||||||||||
Vested | — | — | ||||||||||
Forfeited | — | — | ||||||||||
Nonvested at December 31, 2012 | 24,606 | $ | 40.23 | |||||||||
Granted | 21,128 | 41.65 | ||||||||||
Vested | (10,030 | ) | 40.23 | |||||||||
Forfeited | — | — | ||||||||||
Nonvested at December 31, 2013 | 35,704 | $ | 41.07 | |||||||||
The restricted stock awards vest in periods ranging from 2 to 3 years, except for a portion of those granted to certain executive officers. As to those executive officers, 30% of the shares granted, or 57,405 shares in 2013, 46,441 shares in 2012, and 20,062 shares in 2011 (the performance shares), will cliff vest in the first half of 2016, 2015, and 2014, respectively. The actual number of performance shares that vest in 2014, 2015, and 2016 will be based on the company’s achievement of certain performance criteria over a three-year period, and will range from 0% to 150% of the restricted shares granted as performance shares. Based on the performance criteria, the participants will receive 65.25% of the 2011 performance based shares and are estimated to receive the targeted amount (or 100%) of the 2012 and 2013 performance shares. | ||||||||||||
The fair value of the restricted stock granted in 2013, 2012, and 2011 at the grant date was $21.3 million, $16.9 million, and $10.8 million, respectively. The aggregate intrinsic value of the 248,003 shares of restricted stock on their 2013 vesting date was $11.3 million. The aggregate intrinsic value of the 776,743 shares outstanding subject to vesting at December 31, 2013 was $40.1 million with a weighted average remaining life of 1.0 year. | ||||||||||||
Employee Stock Option Plan | ||||||||||||
The Stock Option Plan, provided the granting of options for up to 2,700,000 shares of common stock to officers and employees. The option plan permitted the issuance of qualified or nonqualified stock options. Options granted typically became exercisable at the rate of 20% per year one year after being granted and expire after 10 years from the original grant date. The exercise price for options granted under this plan was the fair market value of the common stock on the date of the grant. In 2006, as a result of the approval of the adoption of the Unit Corporation Stock and Incentive Compensation Plan, no further awards were made under this plan. | ||||||||||||
Activity pertaining to the Stock Option Plan is as follows: | ||||||||||||
Number of | Weighted | |||||||||||
Shares | Average | |||||||||||
Exercise | ||||||||||||
Price | ||||||||||||
Outstanding at January 1, 2011 | 184,765 | $ | 31.11 | |||||||||
Granted | — | — | ||||||||||
Exercised | (42,285 | ) | 28.29 | |||||||||
Forfeited | (3,500 | ) | 53.9 | |||||||||
Outstanding at December 31, 2011 | 138,980 | 31.39 | ||||||||||
Granted | — | — | ||||||||||
Exercised | (18,850 | ) | 20.38 | |||||||||
Forfeited | (2,100 | ) | 37.83 | |||||||||
Outstanding at December 31, 2012 | 118,030 | 33.03 | ||||||||||
Granted | — | — | ||||||||||
Exercised | (48,110 | ) | 26.09 | |||||||||
Forfeited | (1,000 | ) | 37.83 | |||||||||
Outstanding at December 31, 2013 | 68,920 | $ | 37.81 | |||||||||
There were no shares that vested in 2013, 2012, or 2011. The intrinsic value of options exercised in 2013 was $1.1 million. Total cash received from the options exercised in 2013 was $0.1 million. | ||||||||||||
Outstanding and Exercisable Options at December 31, 2013 | ||||||||||||
Exercise Prices | Number of Shares | Weighted Average Remaining Contractual Life | Weighted Average Exercise Price | |||||||||
$37.69 - $37.83 | 68,920 | 1.0 year | $37.81 | |||||||||
Options for 68,920, 118,030, and 138,980 shares were exercisable with weighted average exercise prices of $37.81, $33.03, and $31.39 at December 31, 2013, 2012, and 2011, respectively. The aggregate intrinsic value of the 68,920 shares outstanding subject to options at December 31, 2013 was $1.0 million with a weighted average remaining contractual term of 1.0 year. | ||||||||||||
Non-Employee Directors' Stock Option Plan | ||||||||||||
Under the Unit Corporation 2000 Non-Employee Directors’ Stock Option Plan, on the first business day following each annual meeting of shareholders, each person who was then a member of our Board of Directors and who was not then an employee of the company or any of its subsidiaries was granted an option to purchase 3,500 shares of common stock. The option price for each stock option was the fair market value of the common stock on the date the stock options were granted. The term of each option is 10 years and cannot be increased and no stock options were to be exercised during the first six months of its term except in case of death. As mentioned above, on May 2, 2012, our stockholders approved the amended plan which succeeds this plan, and no new awards will be issued under the non-employee director option plan. | ||||||||||||
Activity pertaining to the Directors’ Plan is as follows: | ||||||||||||
Number of | Weighted | |||||||||||
Shares | Average | |||||||||||
Exercise | ||||||||||||
Price | ||||||||||||
Outstanding at January 1, 2011 | 178,500 | $ | 48.77 | |||||||||
Granted | 31,500 | 53.81 | ||||||||||
Exercised | (10,500 | ) | 21.96 | |||||||||
Forfeited | — | — | ||||||||||
Outstanding at December 31, 2011 | 199,500 | 48.37 | ||||||||||
Granted | — | — | ||||||||||
Exercised | (7,000 | ) | 20.28 | |||||||||
Forfeited | — | — | ||||||||||
Outstanding at December 31, 2012 | 192,500 | 49.39 | ||||||||||
Granted | — | — | ||||||||||
Exercised | (17,500 | ) | 32.53 | |||||||||
Forfeited | (3,500 | ) | 20.46 | |||||||||
Outstanding at December 31, 2013 | 171,500 | $ | 51.7 | |||||||||
The total grant date fair value of the 31,500 shares vesting in 2011 was $0.7 million. The intrinsic value of the 17,500 options exercised in 2013 was $0.2 million. Total cash received from options exercised in 2013 was $0.6 million. | ||||||||||||
Outstanding and Exercisable | ||||||||||||
Options at December 31, 2013 | ||||||||||||
Weighted | Number of | Weighted | Weighted | |||||||||
Average | Shares | Average | Average | |||||||||
Exercise | Remaining | Exercise | ||||||||||
Price | Contractual | Price | ||||||||||
Life | ||||||||||||
$28.23 - $41.21 | 66,500 | 4.6 years | $ | 36.64 | ||||||||
$53.81 - $73.26 | 105,000 | 4.5 years | $ | 61.24 | ||||||||
Options for 171,500, 192,500, and 199,500 shares were exercisable with weighted average exercise prices of $51.70, $49.39, and $48.37 at December 31, 2013, 2012, and 2011, respectively. The aggregate intrinsic value of the shares outstanding subject to options at December 31, 2013 was $1.0 million with a weighted average remaining contractual term of 4.6 years. |
Derivatives
Derivatives | 12 Months Ended | ||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ' | ||||||||||||||||||
Derivatives | ' | ||||||||||||||||||
Commodity Derivatives | |||||||||||||||||||
We have entered into various types of derivative transactions covering some of our projected natural gas, NGLs, and oil production. These transactions are intended to reduce our exposure to market price volatility by setting the price(s) we will receive for that production. Our decisions on the price(s), type, and quantity of our production hedged is based, in part, on our view of current and future market conditions. As of December 31, 2013, our derivative transactions consisted of the following types of hedges: | |||||||||||||||||||
• | Swaps. We receive or pay a fixed price for the hedged commodity and pay or receive a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty. | ||||||||||||||||||
• | Collars. A collar contains a fixed floor price (put) and a ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, no payments are due from either party. | ||||||||||||||||||
We have documented policies and procedures to monitor and control the use of derivative instruments. We do not engage in derivative transactions for speculative purposes. In August 2012, we determined on a prospective basis, to enter into economic hedges without electing cash flow hedge accounting. Therefore, the change in fair value, on all commodity derivatives entered into after that determination, will be reflected in the income statement and not in accumulated other comprehensive income (OCI). | |||||||||||||||||||
At December 31, 2013, the following non-designated hedges were outstanding: | |||||||||||||||||||
Term | Commodity | Hedged Volume | Weighted Average | Hedged Market | |||||||||||||||
Fixed Price for Swaps | |||||||||||||||||||
Jan’14 – Dec’14 | Natural gas – swap | 80,000 MMBtu/day | $4.24 | IF – NYMEX (HH) | |||||||||||||||
Jan’14 – Dec’14 | Natural gas – collar | 10,000 MMBtu/day | $3.75-4.37 | IF – NYMEX (HH) | |||||||||||||||
Jan’14 – Jun’14 | Crude oil – swap | 500 Bbl/day | $100.03 | WTI – NYMEX | |||||||||||||||
Jan’14 – Dec’14 | Crude oil – swap | 3,000 Bbl/day | $91.77 | WTI – NYMEX | |||||||||||||||
Jan’14 – Dec’14 | Crude oil – collar | 4,000 Bbl/day | $90.00-96.08 | WTI – NYMEX | |||||||||||||||
Subsequent to December 31, 2013, the following non-designated hedges were entered into: | |||||||||||||||||||
Term | Commodity | Hedged Volume | Weighted Average | Hedged Market | |||||||||||||||
Fixed Price for Swaps | |||||||||||||||||||
Mar'14 | Natural gas – basis swap | 30,000 MMBtu/day | ($0.10) | NGPL-TXOK | |||||||||||||||
Mar'14 | Natural gas – basis swap | 60,000 MMBtu/day | ($0.03) | NGPL-Midcon | |||||||||||||||
The following tables present the fair values of our derivative transactions and the location within our balance sheets where those values are recorded at December 31: | |||||||||||||||||||
Derivative Assets | |||||||||||||||||||
Fair Value | |||||||||||||||||||
Balance Sheet Location | 2013 | 2012 | |||||||||||||||||
(In thousands) | |||||||||||||||||||
Derivatives designated as hedging instruments | |||||||||||||||||||
Commodity derivatives: | |||||||||||||||||||
Current | Current derivative assets | $ | — | $ | 13,674 | ||||||||||||||
Long-term | Non-current derivative assets | — | — | ||||||||||||||||
Total derivatives designated as hedging instruments | — | 13,674 | |||||||||||||||||
Derivatives not designated as hedging instruments | |||||||||||||||||||
Commodity derivatives: | |||||||||||||||||||
Current | Current derivative assets | 515 | 2,878 | ||||||||||||||||
Long-term | Non-current derivative assets | — | — | ||||||||||||||||
Total derivatives not designated as hedging instruments | 515 | 2,878 | |||||||||||||||||
Total derivative assets | $ | 515 | $ | 16,552 | |||||||||||||||
Derivative Liabilities | |||||||||||||||||||
Fair Value | |||||||||||||||||||
Balance Sheet Location | 2013 | 2012 | |||||||||||||||||
(In thousands) | |||||||||||||||||||
Derivatives designated as hedging instruments | |||||||||||||||||||
Commodity derivatives: | |||||||||||||||||||
Current | Current derivative liabilities | $ | — | $ | 1,005 | ||||||||||||||
Long-term | Non-current derivative liabilities | — | — | ||||||||||||||||
Total derivatives designated as hedging instruments | — | 1,005 | |||||||||||||||||
Derivatives not designated as hedging instruments | |||||||||||||||||||
Commodity derivatives: | |||||||||||||||||||
Current | Current derivative liabilities | 5,561 | 943 | ||||||||||||||||
Long-term | Non-current derivative liabilities | — | 562 | ||||||||||||||||
Total derivatives not designated as hedging instruments | 5,561 | 1,505 | |||||||||||||||||
Total derivative liabilities | $ | 5,561 | $ | 2,510 | |||||||||||||||
If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty in our balance sheets. | |||||||||||||||||||
We recognized in accumulated other comprehensive income (OCI) the effective portion of any changes in fair value and reclassified the recognized gains (losses) on the sales to oil and natural gas revenue as the underlying transactions were settled. All cash flow hedges expired as of December 31, 2013, therefore we had no balance in accumulated OCI at December 31, 2013 and at December 31, 2012, we had a gain of $7.6 million, net of tax. | |||||||||||||||||||
For our economic hedges that we elected not to apply cash flow accounting to, any changes in their fair value occurring before their maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net in our consolidated statements of income. Changes in the fair value of derivatives that were designated as cash flow hedges, to the extent they were effective in offsetting cash flows attributable to the hedged risk, were recorded in OCI until the hedged item was recognized into earnings. When the hedged item was recognized into earnings, it was reported in oil and natural gas revenues. Any change in fair value that resulted from ineffectiveness was recognized in gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net. | |||||||||||||||||||
Effect of Derivative Instruments on the Consolidated Balance Sheets (cash flow hedges) for the year ended December 31: | |||||||||||||||||||
Derivatives in Cash Flow Hedging Relationships | Amount of Gain or (Loss) | ||||||||||||||||||
Recognized in | |||||||||||||||||||
Accumulated OCI on Derivative | |||||||||||||||||||
(Effective Portion) (1) | |||||||||||||||||||
2013 | 2012 | ||||||||||||||||||
(In thousands) | |||||||||||||||||||
Commodity derivatives | $ | — | $ | 7,587 | |||||||||||||||
_________________________ | |||||||||||||||||||
-1 | Net of taxes. | ||||||||||||||||||
Effect of derivative instruments on the Consolidated Statements of Income (cash flow hedges) for the year ended December 31: | |||||||||||||||||||
Derivative Instrument | Location of Gain or (Loss) Reclassified | Amount of Gain or (Loss) | Amount of Gain or (Loss) | ||||||||||||||||
from Accumulated | Reclassified from | Recognized in Income (2) | |||||||||||||||||
OCI into Income & | Accumulated | ||||||||||||||||||
Location of Gain or (Loss) Recognized in | OCI into Income (1) | ||||||||||||||||||
Income | |||||||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||||||
(In thousands) | |||||||||||||||||||
Commodity derivatives | Oil and natural gas revenue (1) | $ | 603 | $ | 51,853 | $ | — | $ | — | ||||||||||
Commodity derivatives | Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net (2) | — | — | (190 | ) | (2,616 | ) | ||||||||||||
Total | $ | 603 | $ | 51,853 | $ | (190 | ) | $ | (2,616 | ) | |||||||||
_________________________ | |||||||||||||||||||
-1 | Effective portion of gain (loss). | ||||||||||||||||||
-2 | Ineffective portion of gain (loss). | ||||||||||||||||||
Effect of Derivative Instruments on the Consolidated Statements of Income (derivatives not designated as hedging instruments) for the year ended December 31: | |||||||||||||||||||
Location of Gain or (Loss) | Amount of Gain or (Loss) | ||||||||||||||||||
Recognized in Income on | Recognized in Income on | ||||||||||||||||||
Derivative | Derivative | ||||||||||||||||||
Derivatives Not Designated as Hedging Instruments | 2013 | 2012 | |||||||||||||||||
(In thousands) | |||||||||||||||||||
Commodity derivatives | Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net (1) | $ | (8,184 | ) | $ | 1,373 | |||||||||||||
Total | $ | (8,184 | ) | $ | 1,373 | ||||||||||||||
_________________________ | |||||||||||||||||||
-1 | Amount settled during the period is a loss of $(1,764) and $0, respectively. |
Fair_Value_Measurements
Fair Value Measurements | 12 Months Ended | |||||||||||||||
Dec. 31, 2013 | ||||||||||||||||
Fair Value Disclosures [Abstract] | ' | |||||||||||||||
Fair Value Measurements | ' | |||||||||||||||
Fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants (in either case, an exit price). To estimate an exit price, a three-level hierarchy is used prioritizing the valuation techniques used to measure fair value into three levels with the highest priority given to Level 1 and the lowest priority given to Level 3. The levels are summarized as follows: | ||||||||||||||||
• | Level 1—unadjusted quoted prices in active markets for identical assets and liabilities. | |||||||||||||||
• | Level 2—significant observable pricing inputs other than quoted prices included within level 1 that are either directly or indirectly observable as of the reporting date. Essentially, inputs (variables used in the pricing models) that are derived principally from or corroborated by observable market data. | |||||||||||||||
• | Level 3—generally unobservable inputs which are developed based on the best information available and may include our own internal data. | |||||||||||||||
The inputs available to us determine the valuation technique we use to measure the fair values of our financial instruments. | ||||||||||||||||
The following tables set forth our recurring fair value measurements: | ||||||||||||||||
31-Dec-13 | ||||||||||||||||
Level 2 | Level 3 | Effect of Netting | Total | |||||||||||||
(In thousands) | ||||||||||||||||
Financial assets (liabilities): | ||||||||||||||||
Commodity derivatives: | ||||||||||||||||
Assets | $ | 1,978 | $ | 20 | $ | (1,483 | ) | $ | 515 | |||||||
Liabilities | (4,429 | ) | (2,615 | ) | 1,483 | (5,561 | ) | |||||||||
$ | (2,451 | ) | $ | (2,595 | ) | $ | — | $ | (5,046 | ) | ||||||
31-Dec-12 | ||||||||||||||||
Level 2 | Level 3 | Effect of Netting | Total | |||||||||||||
(In thousands) | ||||||||||||||||
Financial assets (liabilities): | ||||||||||||||||
Commodity derivatives: | ||||||||||||||||
Assets | $ | 18,555 | $ | — | $ | (2,003 | ) | $ | 16,552 | |||||||
Liabilities | (3,918 | ) | (595 | ) | 2,003 | (2,510 | ) | |||||||||
$ | 14,637 | $ | (595 | ) | $ | — | $ | 14,042 | ||||||||
All of our counterparties are subject to master netting arrangements. If a legal right of set-off exists, we net the value of the derivative transactions we have with the same counterparty. We are not required to post any cash collateral with our counterparties and no collateral has been posted as of December 31, 2013. | ||||||||||||||||
Certain natural gas fixed price swaps were transferred from Level 3 to Level 2 as of March 31, 2012 because of improvements in our ability to obtain and corroborate observable significant inputs to assess the fair value. Our policy is to recognize transfers either in or out of fair value hierarchy levels as of the end of the quarterly reporting period in which the event or change in circumstances causing the transfer occurred. | ||||||||||||||||
The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above. | ||||||||||||||||
Level 2 Fair Value Measurements | ||||||||||||||||
Commodity Derivatives. We measure the fair values of our crude oil and natural gas swaps using estimated internal discounted cash flow calculations based on the NYMEX futures index. | ||||||||||||||||
Level 3 Fair Value Measurements | ||||||||||||||||
Commodity Derivatives. The fair values of our natural gas and crude oil collars are estimated using internal discounted cash flow calculations based on forward price curves, quotes obtained from brokers for contracts with similar terms, or quotes obtained from counterparties to the agreements. | ||||||||||||||||
The following tables are reconciliations of our level 3 fair value measurements: | ||||||||||||||||
Net Derivatives | ||||||||||||||||
For the Year Ended, | ||||||||||||||||
31-Dec-13 | 31-Dec-12 | |||||||||||||||
(In thousands) | ||||||||||||||||
Beginning of period | $ | (595 | ) | $ | 33,615 | |||||||||||
Total gains or losses: | ||||||||||||||||
Included in earnings (1) | (2,637 | ) | 24,484 | |||||||||||||
Included in other comprehensive income (loss) | — | (11,641 | ) | |||||||||||||
Settlements | 637 | (25,129 | ) | |||||||||||||
Transfers out of Level 3 into Level 2 | — | (21,924 | ) | |||||||||||||
End of period | $ | (2,595 | ) | $ | (595 | ) | ||||||||||
Total gains (losses) for the period included in earnings attributable to the change in unrealized loss relating to assets still held at end of period | $ | (2,000 | ) | $ | (645 | ) | ||||||||||
_________________________ | ||||||||||||||||
-1 | Commodity sales collars are reported in the consolidated statements of income in oil and gas revenues (for cash flow hedges), and gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net, respectively. | |||||||||||||||
The following table provides quantitative information about our Level 3 unobservable inputs at December 31, 2013: | ||||||||||||||||
Commodity (1) | Fair Value | Valuation Technique | Unobservable Input | Range | ||||||||||||
(In thousands) | ||||||||||||||||
Oil collars | $ | (2,246 | ) | Discounted cash flow | Forward commodity price curve | $0.20-$5.29 | ||||||||||
Natural gas collar | $ | (349 | ) | Discounted cash flow | Forward commodity price curve | $0.00-$0.39 | ||||||||||
_________________________ | ||||||||||||||||
-1 | The commodity contracts detailed in this category include non-exchange-traded natural gas and crude oil collars that are valued based on NYMEX. The forward pricing range represents the low and high price expected to be received within the settlement period. | |||||||||||||||
Based on our valuation at December 31, 2013, we determined that the non-performance risk with regard to our counterparties was immaterial. | ||||||||||||||||
Fair Value of Other Financial Instruments | ||||||||||||||||
The following disclosure of the estimated fair value of financial instruments is made in accordance with accounting guidance for financial instruments. We have determined the estimated fair values by using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts. | ||||||||||||||||
At December 31, 2013, the carrying values on the consolidated balance sheets for cash and cash equivalents (classified as Level 1), accounts receivable, accounts payable, other current assets, and current liabilities approximate their fair value because of their short term nature. | ||||||||||||||||
Based on the borrowing rates currently available to us for credit agreement debt with similar terms and maturities and also considering the risk of our non-performance, long-term debt under our credit agreement at December 31, 2013 approximates its fair value. This debt would be classified as Level 2. | ||||||||||||||||
The carrying amounts of long-term debt, net of unamortized discount, associated with the Notes reported in the consolidated balance sheets at December 31, 2013 and December 31, 2012 were $645.7 million and $645.3 million, respectively. We estimate the fair value of these Notes using quoted marked prices at December 31, 2013 and December 31, 2012 were $688.2 million and $687.7 million, respectively. These Notes would be classified as Level 2. |
Accumulated_Other_Comprehensiv
Accumulated Other Comprehensive Income | 12 Months Ended | |||||||||||||
Dec. 31, 2013 | ||||||||||||||
Equity [Abstract] | ' | |||||||||||||
Accumulated other comprehensive income | ' | |||||||||||||
Changes in accumulated other comprehensive income (loss) by component, net of tax, are as follows: | ||||||||||||||
Net Gains (Losses) on Cash Flow Hedges | ||||||||||||||
2013 | 2012 | 2011 | ||||||||||||
(In thousands) | ||||||||||||||
Balance at January 1: | $ | 7,587 | $ | 19,026 | $ | (6,851 | ) | |||||||
Other comprehensive income before reclassification | (7,349 | ) | 18,635 | 29,384 | ||||||||||
Amounts reclassified from accumulated other comprehensive income | (238 | ) | (30,074 | ) | (3,507 | ) | ||||||||
New current-period other comprehensive income | (7,587 | ) | (11,439 | ) | 25,877 | |||||||||
Balance at December 31: | $ | — | $ | 7,587 | $ | 19,026 | ||||||||
Amounts reclassified from accumulated other comprehensive income (loss) into the consolidated statements of income for the year ended December 31: | ||||||||||||||
2013 | 2012 | 2011 | Affected Line Item in the Statement Where Net Income is Presented | |||||||||||
(In thousands) | ||||||||||||||
Net gains (loss) on cash flow hedges | ||||||||||||||
Commodity derivatives | $ | 603 | $ | 51,853 | $ | 2,965 | Oil and natural gas revenues | |||||||
Commodity derivatives | (190 | ) | (2,616 | ) | 2,749 | Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net | ||||||||
413 | 49,237 | 5,714 | Total before tax | |||||||||||
(175 | ) | (19,163 | ) | (2,207 | ) | Tax expense | ||||||||
Total reclassification for the period | $ | 238 | $ | 30,074 | $ | 3,507 | Net of tax | |||||||
Commitments_And_Contingencies
Commitments And Contingencies | 12 Months Ended |
Dec. 31, 2013 | |
Commitments and Contingencies Disclosure [Abstract] | ' |
Commitments And Contingencies | ' |
We lease office space or yards in Edmond, Oklahoma City, and Tulsa, Oklahoma; Houston, Texas; Englewood, Colorado; Pinedale, Wyoming; and Pittsburgh, Pennsylvania under the terms of operating leases expiring through September, 2017. Additionally, we have several compressor rentals, equipment leases, and lease space on short-term commitments to stack excess drilling rig equipment and production inventory. Future minimum rental payments under the terms of the leases are approximately $8.4 million, $3.4 million, $0.6 million, and $0.1 million in 2014 through 2017, respectively. Total rent expense incurred was $16.9 million, $14.0 million, and $8.5 million in 2013, 2012, and 2011, respectively. | |
The Unit 1984 Oil and Gas Limited Partnership and the 1986 Energy Income Limited Partnership agreements along with the employee oil and gas limited partnerships require, on the election of a limited partner, that we repurchase the limited partner’s interest at amounts to be determined by appraisal in the future. These repurchases in any one year are limited to 20% of the units outstanding. We made repurchases of $16,000 in 2013, 56,000 in 2012, and $22,000 in 2011. | |
We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. We also conduct periodic reviews, on a company-wide basis, to identify changes in our environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any possible remediation effort. As it relates to evaluations of purchased properties, depending on the extent of an identified environmental problem, we may exclude a property from the acquisition, require the seller to remediate the property to our satisfaction, or agree to assume liability for the remediation of the property. | |
We have not historically experienced any environmental liability while being a contract driller since the greatest portion of risk is borne by the operator. Any liabilities we have incurred have been small and have been resolved while the drilling rig is on the location and the cost has been included in the direct cost of drilling the well. | |
For the next twelve months, we have committed to purchase approximately $11.4 million of new drilling rig components, drill pipe, drill collars and related equipment and $0.6 million remaining towards a gas treating plant. | |
We are subject to various legal proceedings arising in the ordinary course of our various businesses none of which, in our opinion, will result in judgments which would have a material adverse effect on our financial position, operating results or cash flows. |
Industry_Segment_Information
Industry Segment Information | 12 Months Ended | |||||||||||
Dec. 31, 2013 | ||||||||||||
Segment Reporting [Abstract] | ' | |||||||||||
Industry Segment Information | ' | |||||||||||
We have three main business segments offering different products and services: | ||||||||||||
• | Oil and natural gas, | |||||||||||
• | Contract drilling, and | |||||||||||
• | Mid-stream | |||||||||||
The oil and natural gas segment is engaged in the development, acquisition, and production of oil and natural gas properties. The contract drilling segment is engaged in the land contract drilling of oil and natural gas wells and the mid-stream segment is engaged in the buying, selling, gathering, processing, and treating of natural gas. | ||||||||||||
We evaluate each segment’s performance based on its operating income, which is defined as operating revenues less operating expenses and depreciation, depletion, amortization, and impairment. Our oil and natural gas production outside the United States is not significant. | ||||||||||||
The following table provides certain information about the operations of each of our segments: | ||||||||||||
2013 | 2012 | 2011 | ||||||||||
(In thousands) | ||||||||||||
Revenues: | ||||||||||||
Oil and natural gas | $ | 649,718 | $ | 567,944 | $ | 514,614 | ||||||
Contract drilling | 479,091 | 579,368 | 536,872 | |||||||||
Elimination of inter-segment revenue | (64,313 | ) | (49,649 | ) | (52,221 | ) | ||||||
Contract drilling net of inter-segment revenue | 414,778 | 529,719 | 484,651 | |||||||||
Gas gathering and processing | 378,397 | 290,773 | 284,248 | |||||||||
Elimination of inter-segment revenue | (91,043 | ) | (73,313 | ) | (76,010 | ) | ||||||
Gas gathering and processing net of inter-segment revenue | 287,354 | 217,460 | 208,238 | |||||||||
Total revenues | $ | 1,351,850 | $ | 1,315,123 | $ | 1,207,503 | ||||||
Operating income: | ||||||||||||
Oil and natural gas | $ | 239,219 | $ | (77,221 | ) | (3) | $ | 199,993 | ||||
Contract drilling | 96,304 | 159,188 | 135,085 | |||||||||
Gas gathering and processing | 10,757 | 5,780 | (4) | 17,278 | ||||||||
Total operating income (1) | 346,280 | 87,747 | 352,356 | |||||||||
General and administrative expense | (38,323 | ) | (33,086 | ) | (30,055 | ) | ||||||
Gain (loss) on disposition of assets | 17,076 | 253 | (595 | ) | ||||||||
Interest expense, net | (15,015 | ) | (14,137 | ) | (4,167 | ) | ||||||
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net | (8,374 | ) | (1,243 | ) | 1,702 | |||||||
Other income (expense), net | (175 | ) | (132 | ) | (239 | ) | ||||||
Income before income taxes | $ | 301,469 | $ | 39,402 | $ | 319,002 | ||||||
Identifiable assets: | ||||||||||||
Oil and natural gas | $ | 2,441,792 | $ | 2,214,029 | $ | 1,820,492 | ||||||
Contract drilling | 1,042,661 | 1,079,736 | 1,118,666 | |||||||||
Gas gathering and processing | 473,717 | 413,708 | 247,763 | |||||||||
Total identifiable assets (2) | 3,958,170 | 3,707,473 | 3,186,921 | |||||||||
Corporate assets | 64,220 | 53,647 | 69,799 | |||||||||
Total assets | $ | 4,022,390 | $ | 3,761,120 | $ | 3,256,720 | ||||||
Capital expenditures: | ||||||||||||
Oil and natural gas (5) | $ | 531,233 | $ | 1,145,337 | $ | 588,158 | ||||||
Contract drilling | 64,325 | 77,520 | 162,208 | |||||||||
Gas gathering and processing | 96,085 | 183,162 | 79,355 | |||||||||
Other (5) | 4,483 | 11,083 | 2,688 | |||||||||
Total capital expenditures | $ | 696,126 | $ | 1,417,102 | $ | 832,409 | ||||||
Depreciation, depletion, amortization, and impairment: | ||||||||||||
Oil and natural gas | ||||||||||||
Depreciation, depletion and amortization | 226,498 | 211,347 | 183,350 | |||||||||
Impairment of oil and natural gas properties | — | 283,606 | (3) | — | ||||||||
Contract drilling | 71,194 | 81,007 | 79,667 | |||||||||
Gas gathering and processing | 33,191 | 24,388 | (4) | 16,101 | ||||||||
Other | 3,024 | 2,279 | 1,333 | |||||||||
Total depreciation, depletion, amortization, and impairment | $ | 333,907 | $ | 602,627 | $ | 280,451 | ||||||
_________________________ | ||||||||||||
-1 | Operating income is total operating revenues less operating expenses, depreciation, depletion, amortization, and impairment and does not include general corporate expenses, (gain) loss on disposition of assets, gain (loss) on non-designated hedges and hedge ineffectiveness, interest expense, other income (loss), or income taxes. | |||||||||||
-2 | Identifiable assets are those used in Unit’s operations in each industry segment. Corporate assets are principally cash and cash equivalents, short-term investments, corporate leasehold improvements, furniture and equipment. | |||||||||||
-3 | In June 2012 and December 2012, due to low 12-month average commodity prices, we incurred non-cash ceiling test write downs of our oil and natural gas properties of $115.9 million pre-tax ($72.1 million net of tax) and $167.7 million pre-tax ($104.4 million net of tax), respectively. | |||||||||||
-4 | Depreciation, depletion, amortization, and impairment for gas gathering and processing includes a $1.2 million write down of our Erick system. | |||||||||||
-5 | Reclassified salt water disposal capital expenditures out of other and into oil and natural gas of $16,988 and $8,103 for 2012 and 2011, respectively. |
Selected_Quarterly_Financial_I
Selected Quarterly Financial Information | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
Selected Quarterly Financial Information [Abstract] | ' | ||||||||||||||||
Selected Quarterly Financial Information | ' | ||||||||||||||||
Summarized unaudited quarterly financial information is as follows: | |||||||||||||||||
Three Months Ended | |||||||||||||||||
31-Mar | 30-Jun | September 30 | December 31 | ||||||||||||||
(In thousands except per share amounts) | |||||||||||||||||
2013 | |||||||||||||||||
Revenues | $ | 318,532 | $ | 340,421 | $ | 333,776 | $ | 359,121 | |||||||||
Gross profit | $ | 83,683 | $ | 90,823 | $ | 79,082 | $ | 92,692 | (1) | ||||||||
Net income | $ | 40,206 | $ | 59,007 | $ | 34,232 | $ | 51,301 | |||||||||
Net income per common share: | |||||||||||||||||
Basic | $ | 0.84 | $ | 1.22 | $ | 0.71 | $ | 1.06 | |||||||||
Diluted | $ | 0.83 | $ | 1.22 | $ | 0.7 | $ | 1.05 | |||||||||
2012 | |||||||||||||||||
Revenues | $ | 333,966 | $ | 327,785 | $ | 321,790 | $ | 331,582 | |||||||||
Gross profit (loss) | $ | 95,912 | $ | (22,253 | ) | $ | 95,921 | $ | (81,833 | ) | (1) | ||||||
Net income (loss) | $ | 52,439 | $ | (19,302 | ) | $ | 46,586 | $ | (56,547 | ) | |||||||
Net income (loss) per common share: | |||||||||||||||||
Basic | $ | 1.1 | $ | (0.40 | ) | $ | 0.97 | $ | (1.18 | ) | (2) | ||||||
Diluted | $ | 1.09 | $ | (0.40 | ) | $ | 0.97 | $ | (1.18 | ) | |||||||
_________________________ | |||||||||||||||||
-1 | Gross profit excludes general and administrative expense, interest expense, (gain) loss on disposition of assets, gain (loss) on non-designated hedges and hedge ineffectiveness, income taxes, and other income (loss). | ||||||||||||||||
-2 | Due to the effect of rounding the basic earnings per share for the year’s four quarters does not equal annual earnings per share. |
Supplemental_Oil_And_Gas_Discl
Supplemental Oil And Gas Disclosures | 12 Months Ended | |||||||||||||||||||
Dec. 31, 2013 | ||||||||||||||||||||
Supplemental Oil and Gas Disclosures [Abstract] | ' | |||||||||||||||||||
Supplemental Oil And Gas Disclosures | ' | |||||||||||||||||||
Our oil and gas operations are substantially located in the United States. We do have operations in Canada that are insignificant. The capitalized costs at year-end and costs incurred during the year were as follows: | ||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||
(In thousands) | ||||||||||||||||||||
Capitalized costs: | ||||||||||||||||||||
Proved properties | $ | 4,235,712 | $ | 3,822,381 | $ | 3,302,032 | ||||||||||||||
Unproved properties | 545,588 | 521,659 | 185,632 | |||||||||||||||||
4,781,300 | 4,344,040 | 3,487,664 | ||||||||||||||||||
Accumulated depreciation, depletion, amortization, and impairment | (2,439,458 | ) | (2,216,787 | ) | (1,724,312 | ) | ||||||||||||||
Net capitalized costs | $ | 2,341,842 | $ | 2,127,253 | $ | 1,763,352 | ||||||||||||||
Cost incurred: | ||||||||||||||||||||
Unproved properties acquired | $ | 76,304 | $ | 420,467 | $ | 70,999 | ||||||||||||||
Proved properties acquired | — | 225,669 | 50,013 | |||||||||||||||||
Exploration | 33,373 | 46,467 | 43,836 | |||||||||||||||||
Development | 424,314 | 390,649 | 391,862 | |||||||||||||||||
Asset retirement obligation | (17,951 | ) | 45,097 | 23,345 | ||||||||||||||||
Total costs incurred | $ | 516,040 | $ | 1,128,349 | $ | 580,055 | ||||||||||||||
The following table shows a summary of the oil and natural gas property costs not being amortized at December 31, 2013, by the year in which such costs were incurred: | ||||||||||||||||||||
2013 | 2012 | 2011 | 2010 and Prior | Total | ||||||||||||||||
(In thousands) | ||||||||||||||||||||
Unproved properties acquired and wells in progress | $ | 92,929 | $ | 412,623 | $ | 32,492 | $ | 7,544 | $ | 545,588 | ||||||||||
Unproved properties not subject to amortization relates to properties which are not individually significant and consist primarily of lease acquisition costs. The evaluation process associated with these properties has not been completed and therefore, the company is unable to estimate when these costs will be included in the amortization calculation. | ||||||||||||||||||||
The results of operations for producing activities are as follows: | ||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||
(In thousands) | ||||||||||||||||||||
Revenues | $ | 633,792 | $ | 557,003 | $ | 505,450 | ||||||||||||||
Production costs | (162,822 | ) | (131,389 | ) | (115,400 | ) | ||||||||||||||
Depreciation, depletion, amortization, and impairment | (222,672 | ) | (492,475 | ) | (181,960 | ) | ||||||||||||||
248,298 | (66,861 | ) | 208,090 | |||||||||||||||||
Income tax (expense) benefit | (96,091 | ) | 27,533 | (80,323 | ) | |||||||||||||||
Results of operations for producing activities (excluding corporate overhead and financing costs) | $ | 152,207 | $ | (39,328 | ) | $ | 127,767 | |||||||||||||
Estimated quantities of proved developed oil, NGLs, and natural gas reserves and changes in net quantities of proved developed and undeveloped oil, NGLs, and natural gas reserves were as follows: | ||||||||||||||||||||
Oil | NGLs | Natural Gas | ||||||||||||||||||
Bbls | Bbls | Mcf | ||||||||||||||||||
(In thousands) | ||||||||||||||||||||
2013 | ||||||||||||||||||||
Proved Developed and Undeveloped Reserves: | ||||||||||||||||||||
Beginning of Year | 21,998 | 35,166 | 555,647 | |||||||||||||||||
Revision of Previous Estimates | (2,113 | ) | 836 | 2,421 | ||||||||||||||||
Extensions and Discoveries | 4,678 | 7,273 | 68,611 | |||||||||||||||||
Infill Reserves in Existing Proved Fields | 2,299 | 1,945 | 21,573 | |||||||||||||||||
Purchases of Minerals in Place | — | — | 11 | |||||||||||||||||
Production | (3,360 | ) | (3,914 | ) | (56,757 | ) | ||||||||||||||
Sales | (1,737 | ) | (101 | ) | (9,722 | ) | ||||||||||||||
End of Year | 21,765 | 41,205 | 581,784 | |||||||||||||||||
Proved Developed Reserves: | ||||||||||||||||||||
Beginning of Year | 16,441 | 25,657 | 452,844 | |||||||||||||||||
End of Year | 15,594 | 30,437 | 464,234 | |||||||||||||||||
Proved Undeveloped Reserves: | ||||||||||||||||||||
Beginning of Year | 5,557 | 9,509 | 102,803 | |||||||||||||||||
End of Year | 6,171 | 10,768 | 117,550 | |||||||||||||||||
2012 | ||||||||||||||||||||
Proved Developed and Undeveloped Reserves: | ||||||||||||||||||||
Beginning of Year | 20,255 | 22,087 | 442,135 | |||||||||||||||||
Revision of Previous Estimates (1) | (1,747 | ) | (2,682 | ) | (55,110 | ) | ||||||||||||||
Extensions and Discoveries | 5,014 | 4,819 | 54,761 | |||||||||||||||||
Infill Reserves in Existing Proved Fields | 4,196 | 3,018 | 25,057 | |||||||||||||||||
Purchases of Minerals in Place | 2,830 | 11,098 | 141,494 | |||||||||||||||||
Production | (3,279 | ) | (2,796 | ) | (48,930 | ) | ||||||||||||||
Sales | (5,271 | ) | (378 | ) | (3,760 | ) | ||||||||||||||
End of Year | 21,998 | 35,166 | 555,647 | |||||||||||||||||
Proved Developed Reserves: | ||||||||||||||||||||
Beginning of Year | 15,618 | 16,649 | 372,311 | |||||||||||||||||
End of Year | 16,441 | 25,657 | 452,844 | |||||||||||||||||
Proved Undeveloped Reserves: | ||||||||||||||||||||
Beginning of Year | 4,637 | 5,438 | 69,824 | |||||||||||||||||
End of Year | 5,557 | 9,509 | 102,803 | |||||||||||||||||
2011 | ||||||||||||||||||||
Proved Developed and Undeveloped Reserves: | ||||||||||||||||||||
Beginning of Year | 17,494 | 16,117 | 420,486 | |||||||||||||||||
Revision of Previous Estimates (1) | 374 | 2,112 | (30,510 | ) | ||||||||||||||||
Extensions and Discoveries | 3,477 | 3,924 | 39,836 | |||||||||||||||||
Infill Reserves in Existing Proved Fields | 1,229 | 1,780 | 15,592 | |||||||||||||||||
Purchases of Minerals in Place | 192 | 393 | 40,835 | |||||||||||||||||
Production | (2,511 | ) | (2,239 | ) | (44,104 | ) | ||||||||||||||
Sales | — | — | — | |||||||||||||||||
End of Year | 20,255 | 22,087 | 442,135 | |||||||||||||||||
Proved Developed Reserves: | ||||||||||||||||||||
Beginning of Year | 12,773 | 12,088 | 346,928 | |||||||||||||||||
End of Year | 15,618 | 16,649 | 372,311 | |||||||||||||||||
Proved Undeveloped Reserves: | ||||||||||||||||||||
Beginning of Year | 4,721 | 4,029 | 73,558 | |||||||||||||||||
End of Year | 4,637 | 5,438 | 69,824 | |||||||||||||||||
_________________________ | ||||||||||||||||||||
-1 | Natural gas revisions of previous estimates decreased primarily due to a decline in natural gas prices. | |||||||||||||||||||
Estimates of oil, NGLs, and natural gas reserves require extensive judgments of reservoir engineering data. Assigning monetary values to such estimates does not reduce the subjectivity and changing nature of such reserve estimates. Indeed the uncertainties inherent in the disclosure are compounded by applying additional estimates of the rates and timing of production and the costs that will be incurred in developing and producing the reserves. The information set forth in this report is, therefore, subjective and, since judgments are involved, may not be comparable to estimates submitted by other oil and natural gas producers. In addition, since prices and costs do not remain static, and no price or cost escalations or de-escalations have been considered, the results are not necessarily indicative of the estimated fair market value of estimated proved reserves, nor of estimated future cash flows. | ||||||||||||||||||||
The standardized measure of discounted future net cash flows (SMOG) was calculated using 12-month average prices and year-end costs and statutory tax rates, adjusted for permanent differences that relate to existing proved oil, NGLs, and natural gas reserves. SMOG as of December 31 is as follows: | ||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||
(In thousands) | ||||||||||||||||||||
Future cash flows | $ | 5,573,119 | $ | 4,522,351 | $ | 4,583,629 | ||||||||||||||
Future production costs | (1,734,985 | ) | (1,405,773 | ) | (1,277,856 | ) | ||||||||||||||
Future development costs | (571,170 | ) | (431,673 | ) | (340,992 | ) | ||||||||||||||
Future income tax expenses | (1,044,608 | ) | (762,519 | ) | (952,736 | ) | ||||||||||||||
Future net cash flows | 2,222,356 | 1,922,386 | 2,012,045 | |||||||||||||||||
10% annual discount for estimated timing of cash flows | (996,380 | ) | (842,430 | ) | (924,136 | ) | ||||||||||||||
Standardized measure of discounted future net cash flows relating to proved oil, NGLs, and natural gas reserves | $ | 1,225,976 | $ | 1,079,956 | $ | 1,087,909 | ||||||||||||||
The principal sources of changes in the standardized measure of discounted future net cash flows were as follows: | ||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||
(In thousands) | ||||||||||||||||||||
Sales and transfers of oil and natural gas produced, net of production costs | $ | (470,970 | ) | $ | (425,626 | ) | $ | (389,339 | ) | |||||||||||
Net changes in prices and production costs | 188,826 | (321,099 | ) | 115,852 | ||||||||||||||||
Revisions in quantity estimates and changes in production timing | (10,650 | ) | (148,648 | ) | (38,336 | ) | ||||||||||||||
Extensions, discoveries and improved recovery, less related costs | 426,377 | 432,058 | 401,134 | |||||||||||||||||
Changes in estimated future development costs | 26,629 | 51,587 | 37,742 | |||||||||||||||||
Previously estimated cost incurred during the period | 96,457 | 104,377 | 45,327 | |||||||||||||||||
Purchases of minerals in place | 9 | 283,774 | 58,567 | |||||||||||||||||
Sales of minerals in place | (43,435 | ) | (112,359 | ) | (29 | ) | ||||||||||||||
Accretion of discount | 147,579 | 157,842 | 128,492 | |||||||||||||||||
Net change in income taxes | (170,091 | ) | 94,678 | (60,675 | ) | |||||||||||||||
Other—net | (44,711 | ) | (124,537 | ) | (65,912 | ) | ||||||||||||||
Net change | 146,020 | (7,953 | ) | 232,823 | ||||||||||||||||
Beginning of year | 1,079,956 | 1,087,909 | 855,086 | |||||||||||||||||
End of year | $ | 1,225,976 | $ | 1,079,956 | $ | 1,087,909 | ||||||||||||||
Certain information concerning the assumptions used in computing SMOG and their inherent limitations are discussed below. We believe this information is essential for a proper understanding and assessment of the data presented. | ||||||||||||||||||||
The assumptions used to compute SMOG do not necessarily reflect our expectations of actual revenues to be derived from those reserves nor their present worth. Assigning monetary values to the reserve quantity estimation process does not reduce the subjective and ever-changing nature of reserve estimates. Additional subjectivity occurs when determining present values because the rate of producing the reserves must be estimated. In addition to difficulty inherent in predicting the future, variations from the expected production rate could result from factors outside of our control, such as unintentional delays in development, environmental concerns or changes in prices or regulatory controls. Also, the reserve valuation assumes that all reserves will be disposed of by production. However, other factors such as the sale of reserves in place could affect the amount of cash eventually realized. | ||||||||||||||||||||
The December 31, 2013, future cash flows were computed by applying the unescalated 12-month average prices of $96.94 per barrel for oil, $41.03 per barrel for NGLs, and $3.67 per Mcf for natural gas, then adjusted for price differentials, relating to proved reserves and to the year-end quantities of those reserves. Future price changes are considered only to the extent provided by contractual arrangements in existence at year-end. | ||||||||||||||||||||
Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil, NGLs, and natural gas reserves at the end of the year, based on continuation of existing economic conditions. | ||||||||||||||||||||
Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the future pretax net cash flows relating to proved oil, NGLs, and natural gas reserves less the tax basis of our properties. The future income tax expenses also give effect to permanent differences and tax credits and allowances relating to our proved oil, NGLs, and natural gas reserves. | ||||||||||||||||||||
Care should be exercised in the use and interpretation of the above data. As production occurs over the next several years, the results shown may be significantly different as changes in production performance, petroleum prices and costs are likely to occur. |
Schedule_II_Valuation_And_Qual
Schedule II - Valuation And Qualifying Accounts And Reserves | 12 Months Ended | |||||||||||||||
Dec. 31, 2013 | ||||||||||||||||
Valuation and Qualifying Accounts [Abstract] | ' | |||||||||||||||
Valuation And Qualifying Accounts And Reserves | ' | |||||||||||||||
Allowance for Doubtful Accounts: | ||||||||||||||||
Description | Balance at | Additions | Deductions | Balance at | ||||||||||||
Beginning | Charged to | & Net | End of | |||||||||||||
of Period | Costs & | Write-Offs | Period | |||||||||||||
Expenses | ||||||||||||||||
(In thousands) | ||||||||||||||||
Year ended December 31, 2013 | $ | 5,343 | $ | — | $ | (1 | ) | $ | 5,342 | |||||||
Year ended December 31, 2012 | $ | 5,343 | $ | 90 | $ | (90 | ) | $ | 5,343 | |||||||
Year ended December 31, 2011 | $ | 5,083 | $ | 260 | $ | — | $ | 5,343 | ||||||||
Summary_Of_Significant_Account1
Summary Of Significant Accounting Policies (Policy) | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
Accounting Policies [Abstract] | ' | ||||||||
Principles Of Consolidation | ' | ||||||||
The consolidated financial statements include the accounts of Unit Corporation and its subsidiaries. Our investment in limited partnerships is accounted for on the proportionate consolidation method, whereby our share of the partnerships’ assets, liabilities, revenues, and expenses are included in the appropriate classification in the accompanying consolidated financial statements. | |||||||||
Certain amounts in the accompanying consolidated financial statements for prior periods have been reclassified to conform to current year presentation. Certain financial statement captions were expanded or combined with no impact to consolidated net income or shareholders' equity. | |||||||||
Accounting Estimates | ' | ||||||||
The preparation of financial statements in conformity with generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and 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. Actual results could differ from those estimates. | |||||||||
Drilling Contracts | ' | ||||||||
We recognize revenues and expenses generated from “daywork” drilling contracts as the services are performed, since we do not bear the risk of completion of the well. Under “footage” and “turnkey” contracts, we bear the risk of completion of the well; therefore, revenues and expenses are recognized when the well is substantially completed. Under this method, substantial completion is determined when the well bore reaches the negotiated depth as stated in the contract. The entire amount of a loss, if any, is recorded when the loss is determinable. The costs of uncompleted drilling contracts include expenses incurred to date on “footage” or “turnkey” contracts, which are still in process at the end of the period, and are included in other current assets. Typically, any one of these three types of contracts can be used for the drilling of one well which can take from 20 to 90 days. At December 31, 2013, all of our contracts were daywork contracts of which 23 were multi-well and had durations which ranged from six months to three years, 22 of which expire in 2014 and one expiring in 2015. These longer term contracts may contain a fixed rate for the duration of the contract or provide for the periodic renegotiation of the rate within a specific range from the existing rate. | |||||||||
Cash Equivalents And Book Overdrafts | ' | ||||||||
We include as cash equivalents all investments with maturities at date of purchase of three months or less which are readily convertible into known amounts of cash. Book overdrafts are checks that have been issued before the end of the period, but not presented to our bank for payment before the end of the period. There were no book overdrafts at December 31, 2013. At December 31, 2012, book overdrafts were $7.0 million and included in accounts payable. | |||||||||
Accounts Receivable | ' | ||||||||
Accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of our customers, and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been unsuccessful. | |||||||||
Financial Instruments And Concentrations Of Credit Risk And Non-Performance Risk | ' | ||||||||
Financial instruments, which potentially subject us to concentrations of credit risk, consist primarily of trade receivables with a variety of oil and natural gas companies. We do not generally require collateral related to receivables. Our credit risk is considered to be limited due to the large number of customers comprising our customer base. Below are the third-party customers that accounted for more than 10% of our segment’s revenues: | |||||||||
2013 | 2012 | 2011 | |||||||
Oil and Natural Gas: | |||||||||
Valero Energy Corporation | 25 | % | 26 | % | 18 | % | |||
Sunoco Partners Marketing | 8 | % | 8 | % | 10 | % | |||
Drilling: | |||||||||
QEP Resources, Inc. | 18 | % | 15 | % | 22 | % | |||
Kodiak Oil and Gas Corp. | 10 | % | 10 | % | 6 | % | |||
Mid-Stream: | |||||||||
ONEOK, Inc. | 50 | % | 54 | % | 54 | % | |||
Tenaska Resources, LLC | 16 | % | 7 | % | 1 | % | |||
Gavilon, LLC | — | % | 10 | % | 19 | % | |||
We had a concentration of cash of $52.1 million and $40.4 million at December 31, 2013 and 2012, respectively with one bank. | |||||||||
The use of derivative transactions also involves the risk that the counterparties will be unable to meet the financial terms of the transactions. We considered this non-performance risk with regard to our counterparties and our own non-performance risk in our derivative valuation at December 31, 2013 and determined there was no material risk at that time. At December 31, 2013, the fair values of the net assets (liabilities) we had with each of the counterparties with respect to all of our commodity derivative transactions are listed in the table below: | |||||||||
31-Dec-13 | |||||||||
(In millions) | |||||||||
Canadian Imperial Bank of Commerce | $ | 0.5 | |||||||
Scotiabank | (0.3 | ) | |||||||
Bank of Montreal | (5.2 | ) | |||||||
Total assets (liabilities) | $ | (5.0 | ) | ||||||
Property And Equipment | ' | ||||||||
Drilling equipment, natural gas gathering and processing equipment, transportation equipment, and other property and equipment are carried at cost. Renewals and improvements are capitalized while repairs and maintenance are expensed. Depreciation of drilling equipment is recorded using the units-of-production method based on estimated useful lives starting at 15 years , including a minimum provision of 20% of the active rate when the equipment is idle. We use the composite method of depreciation for drill pipe and collars and calculate the depreciation by footage actually drilled compared to total estimated remaining footage. Depreciation of other property and equipment is computed using the straight-line method over the estimated useful lives of the assets ranging from 3 to 15 years. | |||||||||
Realization of the carrying value of property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset including disposal value if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets. Changes in such estimates could cause us to reduce the carrying value of property and equipment. In December 2012, our mid-stream segment had a $1.2 million write down of its Erick system. There was no volume from the wells connected to this system, the compressor and related surface equipment have been removed from this location and there is no future activity anticipated from this gathering system. No significant impairments were recorded in 2013 or 2011. | |||||||||
When property and equipment components are disposed of, the cost and the related accumulated depreciation are removed from the accounts and any resulting gain or loss is generally reflected in operations. For dispositions of drill pipe and drill collars, an average cost for the appropriate feet of drill pipe and drill collars is removed from the asset account and charged to accumulated depreciation and proceeds, if any, are credited to accumulated depreciation. | |||||||||
We record an asset and a liability equal to the present value of the expected future asset retirement obligation (ARO) associated with our oil and gas properties. The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by accreting an interest charge. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense. | |||||||||
Capitalized Interest | ' | ||||||||
During 2013, 2012, and 2011, interest of approximately $33.7 million, $18.9 million, and $11.5 million, respectively, was capitalized based on the net book value associated with unproved properties not being amortized, the construction of additional drilling rigs, and the construction of gas gathering systems. Interest is being capitalized using a weighted average interest rate based on our outstanding borrowings. | |||||||||
Goodwill | ' | ||||||||
Goodwill represents the excess of the cost of acquisitions over the fair value of the net assets acquired. Goodwill is not amortized, but an impairment test is performed at least annually to determine whether the fair value has decreased and is performed additionally when events indicate an impairment may have occurred. Goodwill is all related to our contract drilling segment, and accordingly, the impairment test is generally based on the estimated discounted future net cash flows of our drilling segment, utilizing discount rates and other factors in determining the fair value of our drilling segment. Inputs in our estimated discounted future net cash flows include rig utilization, day rates, gross margin percentages, and terminal value (these are all considered level 3 inputs). No goodwill impairment was recorded for the years ended December 31, 2013, 2012, or 2011. There were no additions to goodwill in 2013, 2012, or 2011. Goodwill of $3.9 million is deductible for tax purposes. | |||||||||
Intangible Assets | ' | ||||||||
Intangible assets are capitalized and amortized over the estimated period benefited. Such amounts are reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. No intangible asset impairment was recorded for the years ended December 31, 2013, 2012, or 2011. Amortization of $0.7 million, $1.2 million and $1.2 million was recorded in 2013, 2012, and 2011, respectively. Accumulated amortization for 2013 and 2012 was $18.0 million and $17.3 million, respectively. Our intangible assets became fully amortized in 2013, so no amortization is expected to be recorded in 2014. | |||||||||
Oil And Natural Gas Operations | ' | ||||||||
We account for our oil and natural gas exploration and development activities using the full cost method of accounting prescribed by the SEC. Accordingly, all productive and non-productive costs incurred in connection with the acquisition, exploration and development of our oil, NGLs, and natural gas reserves, including directly related overhead costs and related asset retirement costs, are capitalized and amortized on a units-of-production method based on proved oil and natural gas reserves. Directly related overhead costs of $21.5 million, $17.6 million, and $15.6 million were capitalized in 2013, 2012, and 2011, respectively. Independent petroleum engineers annually audit our internal evaluation of our reserves. The average rates used for depreciation, depletion, and amortization (DD&A) were $13.32, $14.70, and $15.06 per Boe in 2013, 2012, and 2011, respectively. The calculation of DD&A includes estimated future expenditures to be incurred in developing proved reserves and estimated dismantlement and abandonment costs, net of estimated salvage values. Our unproved properties totaling $545.6 million are excluded from the DD&A calculation. | |||||||||
No gains or losses are recognized on the sale, conveyance or other disposition of oil and natural gas properties unless a significant reserve amount to our total reserves is involved. | |||||||||
Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties. | |||||||||
Under the full cost rules, at the end of each quarter, we review the carrying value of our oil and natural gas properties. The full cost ceiling is based principally on the estimated future discounted net cash flows from our oil and natural gas properties discounted at 10%. We use the unweighted arithmetic average of the commodity prices existing on the first day of each of the 12 months before the end of the reporting period to calculate discounted future revenues, unless prices were otherwise determined under contractual arrangements. In the event the unamortized cost of oil and natural gas properties being amortized exceeds the full cost ceiling, as defined by the SEC, the excess is charged to expense in the period during which such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible. | |||||||||
For the quarter ended June 30, 2012, the 12-month average commodity prices, including the discounted value of our cash flow hedges, decreased significantly, resulting in a non-cash ceiling test write down of $115.9 million pre-tax ($72.1 million, net of tax). Our qualifying cash flow hedges used in the ceiling test determination at June 30, 2012, consisted of swaps and collars, covering production of 2.9 MMBoe in 2012 and 4.5 MMBoe in 2013. The effect of those hedges on the June 30, 2012 ceiling test was a $32.5 million pre-tax increase in the discounted net cash flows of our oil and natural gas properties. | |||||||||
For the quarter ended December 31, 2012, the 12-month average commodity prices, including the discounted value of our cash flow hedges, decreased further, resulting in an additional non-cash ceiling test write down of $167.7 million pre-tax ($104.4 million, net of tax). Our qualifying cash flow hedges used in the ceiling test determination at December 31, 2012, consisted of swaps and collars covering 6.9 MMBoe in 2013. The effect of those hedges on the December 31, 2012 ceiling test was a $29.8 million pre-tax increase in the discounted net cash flows of our oil and natural gas properties. Our oil and natural gas hedging is discussed in Note 13 of the Notes to our Consolidated Financial Statements. | |||||||||
At December 31, 2013, using the existing 12-month average commodity prices, we were not required to record a ceiling test write-down. All cash flow hedges expired at December 31, 2013 and did not effect the ceiling test determination. | |||||||||
If there are declines in the 12-month average prices, we may be required to record a write-down in future periods. | |||||||||
Our contract drilling segment provides drilling services for our exploration and production segment. Depending on their timing some of the drilling services performed on our properties are also deemed to be associated with the acquisition of an ownership interest in the property. Revenues and expenses for such services are eliminated in our income statement, with any profit recognized as a reduction in our investment in our oil and natural gas properties. The contracts for these services are issued under the same conditions and rates as the contracts entered into with unrelated third parties. We eliminated revenue of $64.3 million, $49.6 million, and $52.2 million for 2013, 2012, and 2011, respectively from our contract drilling segment and eliminated the associated operating expense of $46.9 million, $34.1 million, and $32.6 million during 2013, 2012, and 2011, respectively, yielding $17.4 million, $15.5 million, and $19.6 million during 2013, 2012, and 2011, respectively, as a reduction to the carrying value of our oil and natural gas properties. | |||||||||
Gas Gathering And Processing Revenue | ' | ||||||||
Our gathering and processing segment recognizes revenue from the gathering and processing of natural gas and NGLs in the period the service is provided based on contractual terms. | |||||||||
Insurance | ' | ||||||||
We are self-insured for certain losses relating to workers’ compensation, control of well and employee medical benefits. Insured policies for other coverage contain deductibles or retentions per occurrence that range from $50,000 to $1.5 million. We have purchased stop-loss coverage in order to limit, to the extent feasible, per occurrence and aggregate exposure to certain types of claims. However, there is no assurance that the insurance coverage will adequately protect us against liability from all potential consequences. We have elected to use an ERISA governed occupational injury benefit plan to cover all Texas drilling operations in lieu of covering them under Texas Workers’ Compensation. If insurance coverage becomes more expensive, we may choose to self-insure, decrease our limits, raise our deductibles or any combination of these rather than pay higher premiums. | |||||||||
Hedging Activities | ' | ||||||||
All derivatives are recognized on the balance sheet and measured at fair value. Derivatives that are designated as a cash flow hedge are measured by the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, at each reporting period. The effective portion of the gain (loss) on the derivative instrument is recognized in other comprehensive income as a component of equity and subsequently reclassified into earnings when the forecasted transaction affects earnings. The ineffective portion of a derivative’s change in fair value is required to be recognized in earnings immediately. Derivatives that are not designated for hedge treatment are recorded at fair value with gains (losses) recognized in earnings in the period of change. In August 2012, we determined on a prospective basis, to enter into economic hedges without electing cash flow hedge accounting. Our cash flow hedges (that existed before August 2012) expired in December 2013. | |||||||||
We do not engage in derivative transactions for speculative purposes. We document our risk management strategy, and for the cash flow hedges, we tested the hedge effectiveness at the inception of and during the term of each hedge. | |||||||||
Limited Partnerships | ' | ||||||||
Unit Petroleum Company is a general partner in 16 oil and natural gas limited partnerships sold privately and publicly. Some of our officers, directors, and employees own the interests in most of these partnerships. We share in each partnership’s revenues and costs in accordance with formulas set out in each of the limited partnership agreement. The partnerships also reimburse us for certain administrative costs incurred on behalf of the partnerships. | |||||||||
Income Taxes | ' | ||||||||
Measurement of current and deferred income tax liabilities and assets is based on provisions of enacted tax law; the effects of future changes in tax laws or rates are not included in the measurement. Valuation allowances are established where necessary to reduce deferred tax assets to the amount expected to be realized. Income tax expense is the tax payable for the year and the change during that year in deferred tax assets and liabilities. | |||||||||
The accounting for uncertainty in income taxes prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a return. Guidance is also provided on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. We have no unrecognized tax benefits and we do not expect any significant changes in unrecognized tax benefits in the next twelve months. | |||||||||
Natural Gas Balancing | ' | ||||||||
We use the sales method for recording natural gas sales. This method allows for recognition of revenue, which may be more or less than its share of pro-rata production from certain wells. We estimate our December 31, 2013 balancing position to be approximately 5.2 Bcf on under-produced properties and approximately 4.5 Bcf on over-produced properties. We have recorded a receivable of $2.0 million on certain wells where we estimate that insufficient reserves are available for us to recover the under-production from future production volumes. We have also recorded a liability of $3.8 million on certain properties where we believe there are insufficient reserves available to allow the under-produced owners to recover their under-production from future production volumes. Our policy is to expense the pro-rata share of lease operating costs from all wells as incurred. Such expenses relating to the balancing position on wells in which we have imbalances are not material. | |||||||||
Employee And Director Stock Based Compensation | ' | ||||||||
We recognize in our financial statements the cost of employee services received in exchange for awards of equity instruments based on the grant date fair value of those awards. The amount of our equity compensation cost relating to employees directly involved in exploration activities of our oil and natural gas segment is capitalized to our oil and natural gas properties. Amounts not capitalized to our oil and natural gas properties are recognized in general and administrative expense and operating costs of our business segments. We utilize the Black-Scholes option pricing model to measure the fair value of stock options and stock appreciation rights (SARs). The value of our restricted stock grants is based on the closing stock price on the date of the grants. | |||||||||
Impact of Financial Accounting Pronouncements | ' | ||||||||
Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. In July 2013, ASU 2013-11 was issued because GAAP does not include explicit guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The amendment provides explicit guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The amendments in this Update are effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. Early adoption is permitted. The amendments should be applied prospectively to all unrecognized tax benefits that exist at the effective date. Retrospective application is permitted. We anticipate there will be no effect on our financial position or results of operations when adopted. | |||||||||
Inclusion of the Fed Funds Effective Swap Rate (or Overnight Index Swap Rate) as a Benchmark Interest Rate for Hedge Accounting Purposes. The FASB has issued ASU 2013-10, the amendments in this update permit the Fed Funds Effective Swap Rate (OIS) to be used as a U.S. benchmark interest rate for hedge accounting purposes under Topic 815, in addition to U.S. Treasury and LIBOR. The amendments also remove the restriction on using different benchmark rates for similar hedges. The amendments are effective prospectively for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013. We do not have any interest rate hedges at this time. | |||||||||
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. In February 2013, the FASB issued ASU 2013-02 to address the presentation of comprehensive income related to ASU 2011-05. The standard requires that companies present, either in a single note or parenthetically on the face of the financial statements, the effect of significant amounts reclassified from each component of accumulated other comprehensive income based on its source (e.g., the release due to cash flow hedges from interest rate contracts) and the income statement line items affected by the reclassification (e.g., interest income or interest expense). The amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2012. We chose to present the information in a single note (Note 15 of the Notes to our Consolidated Financial Statements). | |||||||||
Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities. In January 2013, the FASB issued ASU 2013-01 to limit the scope of balance sheet offsetting disclosures contained in previously issued guidance in ASU 2011-11—Disclosures about Offsetting Assets and Liabilities. Specifically, ASU 2011-11 applies only to derivatives, repurchase agreements and reverse purchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with specific criteria contained in the FASB Accounting Standards or subject to a master netting arrangement or similar agreement. | |||||||||
Unlike IFRS, GAAP allows companies the option to present net in their balance sheets derivatives that are subject to a legally enforceable netting arrangement with the same party where rights of set-off are only available in the event of default or bankruptcy. To address these differences between IFRS and GAAP, the FASB and the IASB (the Boards) issued an exposure draft that proposed new criteria for netting that were narrower than the current conditions currently in GAAP. Nevertheless, in response to feedback from their respective stakeholders, the Boards decided to retain their existing offsetting models. Instead, the Boards have issued common disclosure requirements related to offsetting arrangements to allow investors to better compare financial statements prepared in accordance with IFRS or GAAP. The amendments in this ASU require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. An entity is required to apply the amendments for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. An entity should provide the disclosures required by those amendments retrospectively for all comparative periods presented. Derivatives subject to a master netting agreement are the only transactions in this accounting standard that affect us. We provide the effect of netting on our financial position in Note 14 of the Notes to our Consolidated Financial Statements. |
Summary_Of_Significant_Account2
Summary Of Significant Accounting Policies (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
Accounting Policies [Abstract] | ' | ||||||||
Schedule of Segment's Revenue | ' | ||||||||
Below are the third-party customers that accounted for more than 10% of our segment’s revenues: | |||||||||
2013 | 2012 | 2011 | |||||||
Oil and Natural Gas: | |||||||||
Valero Energy Corporation | 25 | % | 26 | % | 18 | % | |||
Sunoco Partners Marketing | 8 | % | 8 | % | 10 | % | |||
Drilling: | |||||||||
QEP Resources, Inc. | 18 | % | 15 | % | 22 | % | |||
Kodiak Oil and Gas Corp. | 10 | % | 10 | % | 6 | % | |||
Mid-Stream: | |||||||||
ONEOK, Inc. | 50 | % | 54 | % | 54 | % | |||
Tenaska Resources, LLC | 16 | % | 7 | % | 1 | % | |||
Gavilon, LLC | — | % | 10 | % | 19 | % | |||
Schedule Of Fair Values Of The Net Assets (Liabilities) | ' | ||||||||
At December 31, 2013, the fair values of the net assets (liabilities) we had with each of the counterparties with respect to all of our commodity derivative transactions are listed in the table below: | |||||||||
31-Dec-13 | |||||||||
(In millions) | |||||||||
Canadian Imperial Bank of Commerce | $ | 0.5 | |||||||
Scotiabank | (0.3 | ) | |||||||
Bank of Montreal | (5.2 | ) | |||||||
Total assets (liabilities) | $ | (5.0 | ) |
Acquisitions_and_Divestitures_
Acquisitions and Divestitures (Tables) | 12 Months Ended | |||||||
Dec. 31, 2013 | ||||||||
Acquisitions and divestitures [Abstract] | ' | |||||||
Schedule of Purchase Price Allocation | ' | |||||||
The Noble acquisition was accounted for using the acquisition method under ASC 805, Business Combinations, which required that the acquired assets and liabilities be recorded at their fair values as of the acquisition date. The following table summarizes the adjusted purchase price and the estimated values of assets acquired and liabilities assumed. It was based on information available to us at the time these consolidated financial statements were prepared and we believe these estimates are reasonable(in thousands): | ||||||||
Adjusted Purchase Price | ||||||||
Total consideration given | $ | 592,627 | ||||||
Adjusted Allocation of Purchase Price | ||||||||
Oil and natural gas properties included in the full cost pool: | ||||||||
Proved oil and natural gas properties | $ | 260,799 | ||||||
Unproved oil and natural gas properties | 353,343 | |||||||
Total oil and natural gas properties included in the full cost pool (1) | 614,142 | |||||||
Gas gathering and processing equipment and other | 25,163 | |||||||
Asset retirement obligation | (46,678 | ) | ||||||
Fair value of net assets acquired | $ | 592,627 | ||||||
(1) We used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. | ||||||||
Pro Forma Results | ' | |||||||
The following unaudited pro forma financial information is presented to reflect the operations of the acquired assets as if the acquisition had been completed on January 1, 2011. The unaudited pro forma financial information was derived from the historical accounting records of the seller adjusted for estimated transaction costs, depreciation, depletion and amortization, ceiling test impact, general and administrative expenses, capitalized interest, and interest on the $400.0 million of Notes issued along with additional borrowings under our credit agreement to finance the acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of our expected future results of operations. The pro forma results of operations do not include any cost savings or other synergies that resulted, or may result, from the acquisition or any estimated costs that will be incurred to integrate these assets. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors. | ||||||||
Twelve months ended December 31, | ||||||||
2012 | 2011 | |||||||
(In thousands, except per share amounts) | ||||||||
Pro forma: | ||||||||
Revenues | $ | 1,376,393 | $ | 1,336,227 | ||||
Net income | $ | 83,940 | $ | 229,272 | ||||
Net income per common share: | ||||||||
Basic | $ | 1.75 | $ | 4.81 | ||||
Diluted | $ | 1.74 | $ | 4.78 | ||||
Earnings_Per_Share_Earnings_Pe
Earnings Per Share Earnings Per Share (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2013 | ||||||||||||
Earnings Per Share [Abstract] | ' | |||||||||||
Schedule of Earnings Per Share [Table Text Block] | ' | |||||||||||
The following data shows the amounts used in computing earnings per share: | ||||||||||||
Income | Weighted | Per-Share | ||||||||||
(Numerator) | Shares | Amount | ||||||||||
(Denominator) | ||||||||||||
(In thousands except per share amounts) | ||||||||||||
For the year ended December 31, 2013: | ||||||||||||
Basic earnings per common share | $ | 184,746 | 48,218 | $ | 3.83 | |||||||
Effect of dilutive stock options, restricted stock, and SARs | — | 354 | (0.03 | ) | ||||||||
Diluted earnings per common share | $ | 184,746 | 48,572 | $ | 3.8 | |||||||
For the year ended December 31, 2012: | ||||||||||||
Basic earnings per common share | $ | 23,176 | 47,909 | $ | 0.48 | |||||||
Effect of dilutive stock options, restricted stock, and SARs | — | 245 | — | |||||||||
Diluted earnings per common share | $ | 23,176 | 48,154 | $ | 0.48 | |||||||
For the year ended December 31, 2011: | ||||||||||||
Basic earnings per common share | $ | 195,867 | 47,658 | $ | 4.11 | |||||||
Effect of dilutive stock options, restricted stock, and SARs | — | 293 | (0.03 | ) | ||||||||
Diluted earnings per common share | $ | 195,867 | 47,951 | $ | 4.08 | |||||||
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share [Table Text Block] | ' | |||||||||||
The following options and their average exercise prices were not included in the computation of diluted earnings per share because the option exercise prices were greater than the average market price of our common stock for the years ended December 31: | ||||||||||||
2013 | 2012 | 2011 | ||||||||||
Options and SARs | 149,665 | 250,901 | 105,000 | |||||||||
Average exercise price | $ | 58.41 | $ | 52.72 | $ | 61.24 | ||||||
Accrued_Liabilities_Tables
Accrued Liabilities (Tables) | 12 Months Ended | |||||||
Dec. 31, 2013 | ||||||||
Accrued Liabilities [Abstract] | ' | |||||||
Accrued Liabilities | ' | |||||||
Accrued liabilities consisted of the following as of December 31: | ||||||||
2013 | 2012 | |||||||
(In thousands) | ||||||||
Employee costs | $ | 27,633 | $ | 24,632 | ||||
Lease operating expenses | 16,073 | 10,903 | ||||||
Interest payable | 6,504 | 6,568 | ||||||
Deposits on assets held for sale | 3,750 | — | ||||||
Taxes | 2,313 | 7,308 | ||||||
Hedge settlements | 416 | 160 | ||||||
Other | 7,674 | 4,527 | ||||||
Total accrued liabilities | $ | 64,363 | $ | 54,098 | ||||
LongTerm_Debt_And_Other_LongTe1
Long-Term Debt And Other Long-Term Liabilities (Tables) | 12 Months Ended | |||||||
Dec. 31, 2013 | ||||||||
Long-term debt and other long-term liabilites [Abstract] | ' | |||||||
Long Term Debt | ' | |||||||
Long-term debt consisted of the following as of December 31: | ||||||||
2013 | 2012 | |||||||
(In thousands) | ||||||||
Credit agreement with an average interest rates of 2.9% at December 31, 2012 | $ | — | $ | 71,100 | ||||
6.625% senior subordinated notes due 2021, net of unamortized discount of $4.3 million and $4.7 million at December 31, 2013 and 2012, respectively | 645,696 | 645,259 | ||||||
Total long-term debt | $ | 645,696 | $ | 716,359 | ||||
Other Long Term Liabilities | ' | |||||||
Other long-term liabilities consisted of the following as of December 31: | ||||||||
2013 | 2012 | |||||||
(In thousands) | ||||||||
ARO liability | $ | 133,657 | $ | 146,159 | ||||
Workers’ compensation | 20,041 | 18,517 | ||||||
Separation benefit plans | 9,382 | 7,972 | ||||||
Gas balancing liability | 3,775 | 3,838 | ||||||
Deferred compensation plan | 3,589 | 2,779 | ||||||
170,444 | 179,265 | |||||||
Less current portion | 12,113 | 12,282 | ||||||
Total other long-term liabilities | $ | 158,331 | $ | 166,983 | ||||
Asset_Retirement_Obligations_T
Asset Retirement Obligations (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
Asset Retirement Obligation Disclosure [Abstract] | ' | ||||||||
Schedule Of Asset Retirement Obligations | ' | ||||||||
The following table shows certain information about our AROs for the periods indicated: | |||||||||
2013 | 2012 | ||||||||
(In thousands) | |||||||||
ARO liability, January 1: | $ | 146,159 | $ | 96,446 | |||||
Accretion of discount | 5,450 | 4,615 | |||||||
Liability incurred | 4,857 | 56,650 | (1) | ||||||
Liability settled | (4,751 | ) | (2,788 | ) | |||||
Liability sold | (2,622 | ) | (1,258 | ) | |||||
Revision of estimates (2) | (15,436 | ) | (7,506 | ) | |||||
ARO liability, December 31: | 133,657 | 146,159 | |||||||
Less current portion | 2,954 | 2,953 | |||||||
Total long-term ARO liability | $ | 130,703 | $ | 143,206 | |||||
_________________________ | |||||||||
-1 | The liability incurred increased $46.7 million related to the Noble properties acquired in September 2012. | ||||||||
-2 | Plugging liability estimates were revised in both 2013 and 2012 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments as well as changes in estimated timing of cash flows. |
Income_Taxes_Tables
Income Taxes (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2013 | ||||||||||||
Income Tax Disclosure [Abstract] | ' | |||||||||||
Reconciliation Of Income Tax Expense | ' | |||||||||||
A reconciliation of income tax expense, computed by applying the federal statutory rate to pre-tax income to our effective income tax expense is as follows: | ||||||||||||
2013 | 2012 | 2011 | ||||||||||
(In thousands) | ||||||||||||
Income tax expense computed by applying the statutory rate | $ | 105,514 | $ | 13,791 | $ | 111,651 | ||||||
State income tax, net of federal benefit | 8,290 | 1,084 | 8,941 | |||||||||
Statutory depletion and other | 2,919 | 1,351 | 2,543 | |||||||||
Income tax expense | $ | 116,723 | $ | 16,226 | $ | 123,135 | ||||||
Schedule Of Total Provision For Income Taxes | ' | |||||||||||
For the periods indicated, the total provision for income taxes consisted of the following: | ||||||||||||
2013 | 2012 | 2011 | ||||||||||
(In thousands) | ||||||||||||
Current taxes: | ||||||||||||
Federal | $ | 15,845 | $ | 2,084 | $ | (3,159 | ) | |||||
State | 146 | (1,388 | ) | 743 | ||||||||
15,991 | 696 | (2,416 | ) | |||||||||
Deferred taxes: | ||||||||||||
Federal | 87,839 | 13,768 | 109,363 | |||||||||
State | 12,893 | 1,762 | 16,188 | |||||||||
100,732 | 15,530 | 125,551 | ||||||||||
Total provision | $ | 116,723 | $ | 16,226 | $ | 123,135 | ||||||
Schedule Of Deferred Tax Assets And Liabilities | ' | |||||||||||
Deferred tax assets and liabilities are comprised of the following at December 31: | ||||||||||||
2013 | 2012 | |||||||||||
(In thousands) | ||||||||||||
Deferred tax assets: | ||||||||||||
Allowance for losses and nondeductible accruals | $ | 77,285 | $ | 74,890 | ||||||||
Net operating loss carryforward | 61,055 | 56,020 | ||||||||||
Alternative minimum tax credit carryforward | 17,258 | 1,972 | ||||||||||
155,598 | 132,882 | |||||||||||
Deferred tax liability: | ||||||||||||
Depreciation, depletion, amortization and impairment | (943,411 | ) | (819,893 | ) | ||||||||
Net deferred tax liability | (787,813 | ) | (687,011 | ) | ||||||||
Current deferred tax asset | 13,585 | 8,765 | ||||||||||
Non-current—deferred tax liability | $ | (801,398 | ) | $ | (695,776 | ) |
Transactions_With_Related_Part1
Transactions With Related Parties (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2013 | ||||||||||||
Related Party Transactions [Abstract] | ' | |||||||||||
Schedule Of Amount Received In Public And Private Partnerships | ' | |||||||||||
Amounts received in the years ended December 31, from both public and private Partnerships for which Unit is a general partner are as follows: | ||||||||||||
2013 | 2012 | 2011 | ||||||||||
(In thousands) | ||||||||||||
Contract drilling | $ | 16 | $ | 246 | $ | 352 | ||||||
Well supervision and other fees | $ | 470 | $ | 434 | $ | 396 | ||||||
General and administrative expense reimbursement | $ | 36 | $ | 39 | $ | 610 | ||||||
StockBased_Compensation_Tables
Stock-Based Compensation (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2013 | ||||||||||||
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | ' | |||||||||||
Schedule Of Restricted Stock Awards Stock Options And SAR | ' | |||||||||||
For restricted stock awards and stock options, we had: | ||||||||||||
2013 | 2012 | 2011 | ||||||||||
(In millions) | ||||||||||||
Recognized stock compensation expense | $ | 16.1 | $ | 11.4 | $ | 10 | ||||||
Capitalized stock compensation cost for our oil and natural gas properties | 3.5 | 2.7 | 2.5 | |||||||||
Tax benefit on stock based compensation | 6.2 | 4.5 | 3.9 | |||||||||
Estimated Fair Value Of The Stock Options Granted | ' | |||||||||||
The table below shows the estimates of the fair value of stock options granted to our non-employee directors under the option plan in 2011 using the Black-Scholes model and applying the estimated values also presented in the table: | ||||||||||||
2011 | ||||||||||||
Options granted | 31,500 | |||||||||||
Estimated fair value (in millions) | $ | 0.7 | ||||||||||
Estimate of stock volatility | 0.48 | |||||||||||
Estimated dividend yield | — | % | ||||||||||
Risk free interest rate | 2 | % | ||||||||||
Expected life range based on prior experience (in years) | 5 | |||||||||||
Forfeiture rate | — | % | ||||||||||
Activity Pertaining to Stock Appreciation Rights | ' | |||||||||||
Activity pertaining to SARs granted under the Unit Corporation Stock and Incentive Compensation Plan is as follows: | ||||||||||||
Number of | Weighted | |||||||||||
Shares | Average | |||||||||||
Grant Date | ||||||||||||
Price | ||||||||||||
Outstanding at January 1, 2011 | 145,901 | $ | 46.59 | |||||||||
Granted | — | — | ||||||||||
Exercised | — | — | ||||||||||
Forfeited | — | — | ||||||||||
Outstanding at December 31, 2011 | 145,901 | 46.59 | ||||||||||
Granted | — | — | ||||||||||
Exercised | — | — | ||||||||||
Forfeited | — | — | ||||||||||
Outstanding at December 31, 2012 | 145,901 | 46.59 | ||||||||||
Granted | — | — | ||||||||||
Exercised | — | — | ||||||||||
Forfeited | — | — | ||||||||||
Outstanding at December 31, 2013 | 145,901 | $ | 46.59 | |||||||||
Activity Pertaining To Restricted Stock Awards | ' | |||||||||||
Activity pertaining to restricted stock awards granted under the amended plan is as follows: | ||||||||||||
Employees | Number of | Weighted | ||||||||||
Shares | Average | |||||||||||
Grant Date | ||||||||||||
Price | ||||||||||||
Nonvested at January 1, 2011 | 446,125 | $ | 47.39 | |||||||||
Granted | 211,050 | 55.91 | ||||||||||
Vested | (190,262 | ) | 43.32 | |||||||||
Forfeited | (18,952 | ) | 44.55 | |||||||||
Nonvested at December 31, 2011 | 447,961 | 47.44 | ||||||||||
Granted | 376,445 | 47.37 | ||||||||||
Vested | (220,788 | ) | 45.66 | |||||||||
Forfeited | (14,091 | ) | 45.37 | |||||||||
Nonvested at December 31, 2012 | 589,527 | 48.11 | ||||||||||
Granted | 453,549 | 48.2 | ||||||||||
Vested | (248,003 | ) | 46.46 | |||||||||
Forfeited | (18,330 | ) | 47.85 | |||||||||
Nonvested at December 31, 2013 | 776,743 | $ | 48.7 | |||||||||
Non-Employee Directors | Number of | Weighted | ||||||||||
Shares | Average | |||||||||||
Grant Date | ||||||||||||
Price | ||||||||||||
Nonvested at December 31, 2011 | — | $ | — | |||||||||
Granted | 24,606 | 40.23 | ||||||||||
Vested | — | — | ||||||||||
Forfeited | — | — | ||||||||||
Nonvested at December 31, 2012 | 24,606 | $ | 40.23 | |||||||||
Granted | 21,128 | 41.65 | ||||||||||
Vested | (10,030 | ) | 40.23 | |||||||||
Forfeited | — | — | ||||||||||
Nonvested at December 31, 2013 | 35,704 | $ | 41.07 | |||||||||
Activity Pertaining to the Stock Option Plan | ' | |||||||||||
Activity pertaining to the Stock Option Plan is as follows: | ||||||||||||
Number of | Weighted | |||||||||||
Shares | Average | |||||||||||
Exercise | ||||||||||||
Price | ||||||||||||
Outstanding at January 1, 2011 | 184,765 | $ | 31.11 | |||||||||
Granted | — | — | ||||||||||
Exercised | (42,285 | ) | 28.29 | |||||||||
Forfeited | (3,500 | ) | 53.9 | |||||||||
Outstanding at December 31, 2011 | 138,980 | 31.39 | ||||||||||
Granted | — | — | ||||||||||
Exercised | (18,850 | ) | 20.38 | |||||||||
Forfeited | (2,100 | ) | 37.83 | |||||||||
Outstanding at December 31, 2012 | 118,030 | 33.03 | ||||||||||
Granted | — | — | ||||||||||
Exercised | (48,110 | ) | 26.09 | |||||||||
Forfeited | (1,000 | ) | 37.83 | |||||||||
Outstanding at December 31, 2013 | 68,920 | $ | 37.81 | |||||||||
Activity Pertaining to Nonemployee Director Stock Award Plan | ' | |||||||||||
Activity pertaining to the Directors’ Plan is as follows: | ||||||||||||
Number of | Weighted | |||||||||||
Shares | Average | |||||||||||
Exercise | ||||||||||||
Price | ||||||||||||
Outstanding at January 1, 2011 | 178,500 | $ | 48.77 | |||||||||
Granted | 31,500 | 53.81 | ||||||||||
Exercised | (10,500 | ) | 21.96 | |||||||||
Forfeited | — | — | ||||||||||
Outstanding at December 31, 2011 | 199,500 | 48.37 | ||||||||||
Granted | — | — | ||||||||||
Exercised | (7,000 | ) | 20.28 | |||||||||
Forfeited | — | — | ||||||||||
Outstanding at December 31, 2012 | 192,500 | 49.39 | ||||||||||
Granted | — | — | ||||||||||
Exercised | (17,500 | ) | 32.53 | |||||||||
Forfeited | (3,500 | ) | 20.46 | |||||||||
Outstanding at December 31, 2013 | 171,500 | $ | 51.7 | |||||||||
Shares Authorized Under Stock Option Plans By Exercise Price Range | ' | |||||||||||
Outstanding and Exercisable Options at December 31, 2013 | ||||||||||||
Exercise Prices | Number of Shares | Weighted Average Remaining Contractual Life | Weighted Average Exercise Price | |||||||||
$37.69 - $37.83 | 68,920 | 1.0 year | $37.81 | |||||||||
Outstanding and Exercisable | ||||||||||||
Options at December 31, 2013 | ||||||||||||
Weighted | Number of | Weighted | Weighted | |||||||||
Average | Shares | Average | Average | |||||||||
Exercise | Remaining | Exercise | ||||||||||
Price | Contractual | Price | ||||||||||
Life | ||||||||||||
$28.23 - $41.21 | 66,500 | 4.6 years | $ | 36.64 | ||||||||
$53.81 - $73.26 | 105,000 | 4.5 years | $ | 61.24 | ||||||||
Derivatives_Tables
Derivatives (Tables) | 12 Months Ended | ||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ' | ||||||||||||||||||
Schedule of Non-designated Hedges Outstanding | ' | ||||||||||||||||||
At December 31, 2013, the following non-designated hedges were outstanding: | |||||||||||||||||||
Term | Commodity | Hedged Volume | Weighted Average | Hedged Market | |||||||||||||||
Fixed Price for Swaps | |||||||||||||||||||
Jan’14 – Dec’14 | Natural gas – swap | 80,000 MMBtu/day | $4.24 | IF – NYMEX (HH) | |||||||||||||||
Jan’14 – Dec’14 | Natural gas – collar | 10,000 MMBtu/day | $3.75-4.37 | IF – NYMEX (HH) | |||||||||||||||
Jan’14 – Jun’14 | Crude oil – swap | 500 Bbl/day | $100.03 | WTI – NYMEX | |||||||||||||||
Jan’14 – Dec’14 | Crude oil – swap | 3,000 Bbl/day | $91.77 | WTI – NYMEX | |||||||||||||||
Jan’14 – Dec’14 | Crude oil – collar | 4,000 Bbl/day | $90.00-96.08 | WTI – NYMEX | |||||||||||||||
Schedule Of Subsequent Non-designated Hedges | ' | ||||||||||||||||||
Subsequent to December 31, 2013, the following non-designated hedges were entered into: | |||||||||||||||||||
Term | Commodity | Hedged Volume | Weighted Average | Hedged Market | |||||||||||||||
Fixed Price for Swaps | |||||||||||||||||||
Mar'14 | Natural gas – basis swap | 30,000 MMBtu/day | ($0.10) | NGPL-TXOK | |||||||||||||||
Mar'14 | Natural gas – basis swap | 60,000 MMBtu/day | ($0.03) | NGPL-Midcon | |||||||||||||||
Fair Value Of Derivative Instruments And Locations In Balance Sheets | ' | ||||||||||||||||||
The following tables present the fair values of our derivative transactions and the location within our balance sheets where those values are recorded at December 31: | |||||||||||||||||||
Derivative Assets | |||||||||||||||||||
Fair Value | |||||||||||||||||||
Balance Sheet Location | 2013 | 2012 | |||||||||||||||||
(In thousands) | |||||||||||||||||||
Derivatives designated as hedging instruments | |||||||||||||||||||
Commodity derivatives: | |||||||||||||||||||
Current | Current derivative assets | $ | — | $ | 13,674 | ||||||||||||||
Long-term | Non-current derivative assets | — | — | ||||||||||||||||
Total derivatives designated as hedging instruments | — | 13,674 | |||||||||||||||||
Derivatives not designated as hedging instruments | |||||||||||||||||||
Commodity derivatives: | |||||||||||||||||||
Current | Current derivative assets | 515 | 2,878 | ||||||||||||||||
Long-term | Non-current derivative assets | — | — | ||||||||||||||||
Total derivatives not designated as hedging instruments | 515 | 2,878 | |||||||||||||||||
Total derivative assets | $ | 515 | $ | 16,552 | |||||||||||||||
Derivative Liabilities | |||||||||||||||||||
Fair Value | |||||||||||||||||||
Balance Sheet Location | 2013 | 2012 | |||||||||||||||||
(In thousands) | |||||||||||||||||||
Derivatives designated as hedging instruments | |||||||||||||||||||
Commodity derivatives: | |||||||||||||||||||
Current | Current derivative liabilities | $ | — | $ | 1,005 | ||||||||||||||
Long-term | Non-current derivative liabilities | — | — | ||||||||||||||||
Total derivatives designated as hedging instruments | — | 1,005 | |||||||||||||||||
Derivatives not designated as hedging instruments | |||||||||||||||||||
Commodity derivatives: | |||||||||||||||||||
Current | Current derivative liabilities | 5,561 | 943 | ||||||||||||||||
Long-term | Non-current derivative liabilities | — | 562 | ||||||||||||||||
Total derivatives not designated as hedging instruments | 5,561 | 1,505 | |||||||||||||||||
Total derivative liabilities | $ | 5,561 | $ | 2,510 | |||||||||||||||
Amount Of Gain Or (Loss) Recognized In Accumulated OCI On Derivative | ' | ||||||||||||||||||
Effect of Derivative Instruments on the Consolidated Balance Sheets (cash flow hedges) for the year ended December 31: | |||||||||||||||||||
Derivatives in Cash Flow Hedging Relationships | Amount of Gain or (Loss) | ||||||||||||||||||
Recognized in | |||||||||||||||||||
Accumulated OCI on Derivative | |||||||||||||||||||
(Effective Portion) (1) | |||||||||||||||||||
2013 | 2012 | ||||||||||||||||||
(In thousands) | |||||||||||||||||||
Commodity derivatives | $ | — | $ | 7,587 | |||||||||||||||
_________________________ | |||||||||||||||||||
-1 | Net of taxes. | ||||||||||||||||||
Gain Or Loss Of Reclassified Accumulated Other Comprehensive Income And Recognized Income | ' | ||||||||||||||||||
Effect of derivative instruments on the Consolidated Statements of Income (cash flow hedges) for the year ended December 31: | |||||||||||||||||||
Derivative Instrument | Location of Gain or (Loss) Reclassified | Amount of Gain or (Loss) | Amount of Gain or (Loss) | ||||||||||||||||
from Accumulated | Reclassified from | Recognized in Income (2) | |||||||||||||||||
OCI into Income & | Accumulated | ||||||||||||||||||
Location of Gain or (Loss) Recognized in | OCI into Income (1) | ||||||||||||||||||
Income | |||||||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||||||
(In thousands) | |||||||||||||||||||
Commodity derivatives | Oil and natural gas revenue (1) | $ | 603 | $ | 51,853 | $ | — | $ | — | ||||||||||
Commodity derivatives | Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net (2) | — | — | (190 | ) | (2,616 | ) | ||||||||||||
Total | $ | 603 | $ | 51,853 | $ | (190 | ) | $ | (2,616 | ) | |||||||||
_________________________ | |||||||||||||||||||
-1 | Effective portion of gain (loss). | ||||||||||||||||||
-2 | Ineffective portion of gain (loss). | ||||||||||||||||||
Effect Of Derivative Instruments Recognized In Statement Of Operations, Not Designated As Hedging Instruments | ' | ||||||||||||||||||
Effect of Derivative Instruments on the Consolidated Statements of Income (derivatives not designated as hedging instruments) for the year ended December 31: | |||||||||||||||||||
Location of Gain or (Loss) | Amount of Gain or (Loss) | ||||||||||||||||||
Recognized in Income on | Recognized in Income on | ||||||||||||||||||
Derivative | Derivative | ||||||||||||||||||
Derivatives Not Designated as Hedging Instruments | 2013 | 2012 | |||||||||||||||||
(In thousands) | |||||||||||||||||||
Commodity derivatives | Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net (1) | $ | (8,184 | ) | $ | 1,373 | |||||||||||||
Total | $ | (8,184 | ) | $ | 1,373 | ||||||||||||||
_________________________ | |||||||||||||||||||
-1 | Amount settled during the period is a loss of $(1,764) and $0, respectively. |
Fair_Value_Measurements_Tables
Fair Value Measurements (Tables) | 12 Months Ended | |||||||||||||||
Dec. 31, 2013 | ||||||||||||||||
Fair Value Disclosures [Abstract] | ' | |||||||||||||||
Recurring Fair Value Measurements | ' | |||||||||||||||
The following tables set forth our recurring fair value measurements: | ||||||||||||||||
31-Dec-13 | ||||||||||||||||
Level 2 | Level 3 | Effect of Netting | Total | |||||||||||||
(In thousands) | ||||||||||||||||
Financial assets (liabilities): | ||||||||||||||||
Commodity derivatives: | ||||||||||||||||
Assets | $ | 1,978 | $ | 20 | $ | (1,483 | ) | $ | 515 | |||||||
Liabilities | (4,429 | ) | (2,615 | ) | 1,483 | (5,561 | ) | |||||||||
$ | (2,451 | ) | $ | (2,595 | ) | $ | — | $ | (5,046 | ) | ||||||
31-Dec-12 | ||||||||||||||||
Level 2 | Level 3 | Effect of Netting | Total | |||||||||||||
(In thousands) | ||||||||||||||||
Financial assets (liabilities): | ||||||||||||||||
Commodity derivatives: | ||||||||||||||||
Assets | $ | 18,555 | $ | — | $ | (2,003 | ) | $ | 16,552 | |||||||
Liabilities | (3,918 | ) | (595 | ) | 2,003 | (2,510 | ) | |||||||||
$ | 14,637 | $ | (595 | ) | $ | — | $ | 14,042 | ||||||||
Reconciliations Of Level 3 Fair Value Measurements | ' | |||||||||||||||
The following tables are reconciliations of our level 3 fair value measurements: | ||||||||||||||||
Net Derivatives | ||||||||||||||||
For the Year Ended, | ||||||||||||||||
31-Dec-13 | 31-Dec-12 | |||||||||||||||
(In thousands) | ||||||||||||||||
Beginning of period | $ | (595 | ) | $ | 33,615 | |||||||||||
Total gains or losses: | ||||||||||||||||
Included in earnings (1) | (2,637 | ) | 24,484 | |||||||||||||
Included in other comprehensive income (loss) | — | (11,641 | ) | |||||||||||||
Settlements | 637 | (25,129 | ) | |||||||||||||
Transfers out of Level 3 into Level 2 | — | (21,924 | ) | |||||||||||||
End of period | $ | (2,595 | ) | $ | (595 | ) | ||||||||||
Total gains (losses) for the period included in earnings attributable to the change in unrealized loss relating to assets still held at end of period | $ | (2,000 | ) | $ | (645 | ) | ||||||||||
_________________________ | ||||||||||||||||
-1 | Commodity sales collars are reported in the consolidated statements of income in oil and gas revenues (for cash flow hedges), and gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net, respectively. | |||||||||||||||
Schedule Of Quantitative Information About Unobservable Inputs | ' | |||||||||||||||
The following table provides quantitative information about our Level 3 unobservable inputs at December 31, 2013: | ||||||||||||||||
Commodity (1) | Fair Value | Valuation Technique | Unobservable Input | Range | ||||||||||||
(In thousands) | ||||||||||||||||
Oil collars | $ | (2,246 | ) | Discounted cash flow | Forward commodity price curve | $0.20-$5.29 | ||||||||||
Natural gas collar | $ | (349 | ) | Discounted cash flow | Forward commodity price curve | $0.00-$0.39 | ||||||||||
_________________________ | ||||||||||||||||
-1 | The commodity contracts detailed in this category include non-exchange-traded natural gas and crude oil collars that are valued based on NYMEX. The forward pricing range represents the low and high price expected to be received within the settlement period. |
Accumulated_Other_Comprehensiv1
Accumulated Other Comprehensive Income (Tables) | 12 Months Ended | |||||||||||||
Dec. 31, 2013 | ||||||||||||||
Equity [Abstract] | ' | |||||||||||||
Changes in accumulated other comprehensive income | ' | |||||||||||||
Changes in accumulated other comprehensive income (loss) by component, net of tax, are as follows: | ||||||||||||||
Net Gains (Losses) on Cash Flow Hedges | ||||||||||||||
2013 | 2012 | 2011 | ||||||||||||
(In thousands) | ||||||||||||||
Balance at January 1: | $ | 7,587 | $ | 19,026 | $ | (6,851 | ) | |||||||
Other comprehensive income before reclassification | (7,349 | ) | 18,635 | 29,384 | ||||||||||
Amounts reclassified from accumulated other comprehensive income | (238 | ) | (30,074 | ) | (3,507 | ) | ||||||||
New current-period other comprehensive income | (7,587 | ) | (11,439 | ) | 25,877 | |||||||||
Balance at December 31: | $ | — | $ | 7,587 | $ | 19,026 | ||||||||
Schedule of accumulated other comprehensive income | ' | |||||||||||||
Amounts reclassified from accumulated other comprehensive income (loss) into the consolidated statements of income for the year ended December 31: | ||||||||||||||
2013 | 2012 | 2011 | Affected Line Item in the Statement Where Net Income is Presented | |||||||||||
(In thousands) | ||||||||||||||
Net gains (loss) on cash flow hedges | ||||||||||||||
Commodity derivatives | $ | 603 | $ | 51,853 | $ | 2,965 | Oil and natural gas revenues | |||||||
Commodity derivatives | (190 | ) | (2,616 | ) | 2,749 | Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net | ||||||||
413 | 49,237 | 5,714 | Total before tax | |||||||||||
(175 | ) | (19,163 | ) | (2,207 | ) | Tax expense | ||||||||
Total reclassification for the period | $ | 238 | $ | 30,074 | $ | 3,507 | Net of tax | |||||||
Industry_Segment_Information_T
Industry Segment Information (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2013 | ||||||||||||
Segment Reporting [Abstract] | ' | |||||||||||
Revenue From Different Segments | ' | |||||||||||
The following table provides certain information about the operations of each of our segments: | ||||||||||||
2013 | 2012 | 2011 | ||||||||||
(In thousands) | ||||||||||||
Revenues: | ||||||||||||
Oil and natural gas | $ | 649,718 | $ | 567,944 | $ | 514,614 | ||||||
Contract drilling | 479,091 | 579,368 | 536,872 | |||||||||
Elimination of inter-segment revenue | (64,313 | ) | (49,649 | ) | (52,221 | ) | ||||||
Contract drilling net of inter-segment revenue | 414,778 | 529,719 | 484,651 | |||||||||
Gas gathering and processing | 378,397 | 290,773 | 284,248 | |||||||||
Elimination of inter-segment revenue | (91,043 | ) | (73,313 | ) | (76,010 | ) | ||||||
Gas gathering and processing net of inter-segment revenue | 287,354 | 217,460 | 208,238 | |||||||||
Total revenues | $ | 1,351,850 | $ | 1,315,123 | $ | 1,207,503 | ||||||
Operating income: | ||||||||||||
Oil and natural gas | $ | 239,219 | $ | (77,221 | ) | (3) | $ | 199,993 | ||||
Contract drilling | 96,304 | 159,188 | 135,085 | |||||||||
Gas gathering and processing | 10,757 | 5,780 | (4) | 17,278 | ||||||||
Total operating income (1) | 346,280 | 87,747 | 352,356 | |||||||||
General and administrative expense | (38,323 | ) | (33,086 | ) | (30,055 | ) | ||||||
Gain (loss) on disposition of assets | 17,076 | 253 | (595 | ) | ||||||||
Interest expense, net | (15,015 | ) | (14,137 | ) | (4,167 | ) | ||||||
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net | (8,374 | ) | (1,243 | ) | 1,702 | |||||||
Other income (expense), net | (175 | ) | (132 | ) | (239 | ) | ||||||
Income before income taxes | $ | 301,469 | $ | 39,402 | $ | 319,002 | ||||||
Identifiable assets: | ||||||||||||
Oil and natural gas | $ | 2,441,792 | $ | 2,214,029 | $ | 1,820,492 | ||||||
Contract drilling | 1,042,661 | 1,079,736 | 1,118,666 | |||||||||
Gas gathering and processing | 473,717 | 413,708 | 247,763 | |||||||||
Total identifiable assets (2) | 3,958,170 | 3,707,473 | 3,186,921 | |||||||||
Corporate assets | 64,220 | 53,647 | 69,799 | |||||||||
Total assets | $ | 4,022,390 | $ | 3,761,120 | $ | 3,256,720 | ||||||
Capital expenditures: | ||||||||||||
Oil and natural gas (5) | $ | 531,233 | $ | 1,145,337 | $ | 588,158 | ||||||
Contract drilling | 64,325 | 77,520 | 162,208 | |||||||||
Gas gathering and processing | 96,085 | 183,162 | 79,355 | |||||||||
Other (5) | 4,483 | 11,083 | 2,688 | |||||||||
Total capital expenditures | $ | 696,126 | $ | 1,417,102 | $ | 832,409 | ||||||
Depreciation, depletion, amortization, and impairment: | ||||||||||||
Oil and natural gas | ||||||||||||
Depreciation, depletion and amortization | 226,498 | 211,347 | 183,350 | |||||||||
Impairment of oil and natural gas properties | — | 283,606 | (3) | — | ||||||||
Contract drilling | 71,194 | 81,007 | 79,667 | |||||||||
Gas gathering and processing | 33,191 | 24,388 | (4) | 16,101 | ||||||||
Other | 3,024 | 2,279 | 1,333 | |||||||||
Total depreciation, depletion, amortization, and impairment | $ | 333,907 | $ | 602,627 | $ | 280,451 | ||||||
_________________________ | ||||||||||||
-1 | Operating income is total operating revenues less operating expenses, depreciation, depletion, amortization, and impairment and does not include general corporate expenses, (gain) loss on disposition of assets, gain (loss) on non-designated hedges and hedge ineffectiveness, interest expense, other income (loss), or income taxes. | |||||||||||
-2 | Identifiable assets are those used in Unit’s operations in each industry segment. Corporate assets are principally cash and cash equivalents, short-term investments, corporate leasehold improvements, furniture and equipment. | |||||||||||
-3 | In June 2012 and December 2012, due to low 12-month average commodity prices, we incurred non-cash ceiling test write downs of our oil and natural gas properties of $115.9 million pre-tax ($72.1 million net of tax) and $167.7 million pre-tax ($104.4 million net of tax), respectively. | |||||||||||
-4 | Depreciation, depletion, amortization, and impairment for gas gathering and processing includes a $1.2 million write down of our Erick system. | |||||||||||
-5 | Reclassified salt water disposal capital expenditures out of other and into oil and natural gas of $16,988 and $8,103 for 2012 and 2011, respectively. |
Selected_Quarterly_Financial_I1
Selected Quarterly Financial Information (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
Selected Quarterly Financial Information [Abstract] | ' | ||||||||||||||||
Schedule Of Quarterly Financial Information | ' | ||||||||||||||||
Summarized unaudited quarterly financial information is as follows: | |||||||||||||||||
Three Months Ended | |||||||||||||||||
31-Mar | 30-Jun | September 30 | December 31 | ||||||||||||||
(In thousands except per share amounts) | |||||||||||||||||
2013 | |||||||||||||||||
Revenues | $ | 318,532 | $ | 340,421 | $ | 333,776 | $ | 359,121 | |||||||||
Gross profit | $ | 83,683 | $ | 90,823 | $ | 79,082 | $ | 92,692 | (1) | ||||||||
Net income | $ | 40,206 | $ | 59,007 | $ | 34,232 | $ | 51,301 | |||||||||
Net income per common share: | |||||||||||||||||
Basic | $ | 0.84 | $ | 1.22 | $ | 0.71 | $ | 1.06 | |||||||||
Diluted | $ | 0.83 | $ | 1.22 | $ | 0.7 | $ | 1.05 | |||||||||
2012 | |||||||||||||||||
Revenues | $ | 333,966 | $ | 327,785 | $ | 321,790 | $ | 331,582 | |||||||||
Gross profit (loss) | $ | 95,912 | $ | (22,253 | ) | $ | 95,921 | $ | (81,833 | ) | (1) | ||||||
Net income (loss) | $ | 52,439 | $ | (19,302 | ) | $ | 46,586 | $ | (56,547 | ) | |||||||
Net income (loss) per common share: | |||||||||||||||||
Basic | $ | 1.1 | $ | (0.40 | ) | $ | 0.97 | $ | (1.18 | ) | (2) | ||||||
Diluted | $ | 1.09 | $ | (0.40 | ) | $ | 0.97 | $ | (1.18 | ) | |||||||
_________________________ | |||||||||||||||||
-1 | Gross profit excludes general and administrative expense, interest expense, (gain) loss on disposition of assets, gain (loss) on non-designated hedges and hedge ineffectiveness, income taxes, and other income (loss). | ||||||||||||||||
-2 | Due to the effect of rounding the basic earnings per share for the year’s four quarters does not equal annual earnings per share. |
Supplemental_Oil_And_Gas_Discl1
Supplemental Oil And Gas Disclosures (Tables) | 12 Months Ended | |||||||||||||||||||
Dec. 31, 2013 | ||||||||||||||||||||
Supplemental Oil and Gas Disclosures [Abstract] | ' | |||||||||||||||||||
Schedule Of Capitalized Costs And Costs Incurred On Oil And Gas Properties | ' | |||||||||||||||||||
The capitalized costs at year-end and costs incurred during the year were as follows: | ||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||
(In thousands) | ||||||||||||||||||||
Capitalized costs: | ||||||||||||||||||||
Proved properties | $ | 4,235,712 | $ | 3,822,381 | $ | 3,302,032 | ||||||||||||||
Unproved properties | 545,588 | 521,659 | 185,632 | |||||||||||||||||
4,781,300 | 4,344,040 | 3,487,664 | ||||||||||||||||||
Accumulated depreciation, depletion, amortization, and impairment | (2,439,458 | ) | (2,216,787 | ) | (1,724,312 | ) | ||||||||||||||
Net capitalized costs | $ | 2,341,842 | $ | 2,127,253 | $ | 1,763,352 | ||||||||||||||
Cost incurred: | ||||||||||||||||||||
Unproved properties acquired | $ | 76,304 | $ | 420,467 | $ | 70,999 | ||||||||||||||
Proved properties acquired | — | 225,669 | 50,013 | |||||||||||||||||
Exploration | 33,373 | 46,467 | 43,836 | |||||||||||||||||
Development | 424,314 | 390,649 | 391,862 | |||||||||||||||||
Asset retirement obligation | (17,951 | ) | 45,097 | 23,345 | ||||||||||||||||
Total costs incurred | $ | 516,040 | $ | 1,128,349 | $ | 580,055 | ||||||||||||||
Schedule Of The Oil And Natural Gas Property Costs Not Being Amortized | ' | |||||||||||||||||||
The following table shows a summary of the oil and natural gas property costs not being amortized at December 31, 2013, by the year in which such costs were incurred: | ||||||||||||||||||||
2013 | 2012 | 2011 | 2010 and Prior | Total | ||||||||||||||||
(In thousands) | ||||||||||||||||||||
Unproved properties acquired and wells in progress | $ | 92,929 | $ | 412,623 | $ | 32,492 | $ | 7,544 | $ | 545,588 | ||||||||||
Results Of Operations For Producing Activities | ' | |||||||||||||||||||
The results of operations for producing activities are as follows: | ||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||
(In thousands) | ||||||||||||||||||||
Revenues | $ | 633,792 | $ | 557,003 | $ | 505,450 | ||||||||||||||
Production costs | (162,822 | ) | (131,389 | ) | (115,400 | ) | ||||||||||||||
Depreciation, depletion, amortization, and impairment | (222,672 | ) | (492,475 | ) | (181,960 | ) | ||||||||||||||
248,298 | (66,861 | ) | 208,090 | |||||||||||||||||
Income tax (expense) benefit | (96,091 | ) | 27,533 | (80,323 | ) | |||||||||||||||
Results of operations for producing activities (excluding corporate overhead and financing costs) | $ | 152,207 | $ | (39,328 | ) | $ | 127,767 | |||||||||||||
Schedule Of Proved Developed And Undeveloped Oil And Gas Reserve Quantities | ' | |||||||||||||||||||
Estimated quantities of proved developed oil, NGLs, and natural gas reserves and changes in net quantities of proved developed and undeveloped oil, NGLs, and natural gas reserves were as follows: | ||||||||||||||||||||
Oil | NGLs | Natural Gas | ||||||||||||||||||
Bbls | Bbls | Mcf | ||||||||||||||||||
(In thousands) | ||||||||||||||||||||
2013 | ||||||||||||||||||||
Proved Developed and Undeveloped Reserves: | ||||||||||||||||||||
Beginning of Year | 21,998 | 35,166 | 555,647 | |||||||||||||||||
Revision of Previous Estimates | (2,113 | ) | 836 | 2,421 | ||||||||||||||||
Extensions and Discoveries | 4,678 | 7,273 | 68,611 | |||||||||||||||||
Infill Reserves in Existing Proved Fields | 2,299 | 1,945 | 21,573 | |||||||||||||||||
Purchases of Minerals in Place | — | — | 11 | |||||||||||||||||
Production | (3,360 | ) | (3,914 | ) | (56,757 | ) | ||||||||||||||
Sales | (1,737 | ) | (101 | ) | (9,722 | ) | ||||||||||||||
End of Year | 21,765 | 41,205 | 581,784 | |||||||||||||||||
Proved Developed Reserves: | ||||||||||||||||||||
Beginning of Year | 16,441 | 25,657 | 452,844 | |||||||||||||||||
End of Year | 15,594 | 30,437 | 464,234 | |||||||||||||||||
Proved Undeveloped Reserves: | ||||||||||||||||||||
Beginning of Year | 5,557 | 9,509 | 102,803 | |||||||||||||||||
End of Year | 6,171 | 10,768 | 117,550 | |||||||||||||||||
2012 | ||||||||||||||||||||
Proved Developed and Undeveloped Reserves: | ||||||||||||||||||||
Beginning of Year | 20,255 | 22,087 | 442,135 | |||||||||||||||||
Revision of Previous Estimates (1) | (1,747 | ) | (2,682 | ) | (55,110 | ) | ||||||||||||||
Extensions and Discoveries | 5,014 | 4,819 | 54,761 | |||||||||||||||||
Infill Reserves in Existing Proved Fields | 4,196 | 3,018 | 25,057 | |||||||||||||||||
Purchases of Minerals in Place | 2,830 | 11,098 | 141,494 | |||||||||||||||||
Production | (3,279 | ) | (2,796 | ) | (48,930 | ) | ||||||||||||||
Sales | (5,271 | ) | (378 | ) | (3,760 | ) | ||||||||||||||
End of Year | 21,998 | 35,166 | 555,647 | |||||||||||||||||
Proved Developed Reserves: | ||||||||||||||||||||
Beginning of Year | 15,618 | 16,649 | 372,311 | |||||||||||||||||
End of Year | 16,441 | 25,657 | 452,844 | |||||||||||||||||
Proved Undeveloped Reserves: | ||||||||||||||||||||
Beginning of Year | 4,637 | 5,438 | 69,824 | |||||||||||||||||
End of Year | 5,557 | 9,509 | 102,803 | |||||||||||||||||
2011 | ||||||||||||||||||||
Proved Developed and Undeveloped Reserves: | ||||||||||||||||||||
Beginning of Year | 17,494 | 16,117 | 420,486 | |||||||||||||||||
Revision of Previous Estimates (1) | 374 | 2,112 | (30,510 | ) | ||||||||||||||||
Extensions and Discoveries | 3,477 | 3,924 | 39,836 | |||||||||||||||||
Infill Reserves in Existing Proved Fields | 1,229 | 1,780 | 15,592 | |||||||||||||||||
Purchases of Minerals in Place | 192 | 393 | 40,835 | |||||||||||||||||
Production | (2,511 | ) | (2,239 | ) | (44,104 | ) | ||||||||||||||
Sales | — | — | — | |||||||||||||||||
End of Year | 20,255 | 22,087 | 442,135 | |||||||||||||||||
Proved Developed Reserves: | ||||||||||||||||||||
Beginning of Year | 12,773 | 12,088 | 346,928 | |||||||||||||||||
End of Year | 15,618 | 16,649 | 372,311 | |||||||||||||||||
Proved Undeveloped Reserves: | ||||||||||||||||||||
Beginning of Year | 4,721 | 4,029 | 73,558 | |||||||||||||||||
End of Year | 4,637 | 5,438 | 69,824 | |||||||||||||||||
_________________________ | ||||||||||||||||||||
-1 | Natural gas revisions of previous estimates decreased primarily due to a decline in natural gas prices. | |||||||||||||||||||
Standardized Measure Of Discounted Future Cash Flows Relating To Proved Reserves Disclosure | ' | |||||||||||||||||||
The standardized measure of discounted future net cash flows (SMOG) was calculated using 12-month average prices and year-end costs and statutory tax rates, adjusted for permanent differences that relate to existing proved oil, NGLs, and natural gas reserves. SMOG as of December 31 is as follows: | ||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||
(In thousands) | ||||||||||||||||||||
Future cash flows | $ | 5,573,119 | $ | 4,522,351 | $ | 4,583,629 | ||||||||||||||
Future production costs | (1,734,985 | ) | (1,405,773 | ) | (1,277,856 | ) | ||||||||||||||
Future development costs | (571,170 | ) | (431,673 | ) | (340,992 | ) | ||||||||||||||
Future income tax expenses | (1,044,608 | ) | (762,519 | ) | (952,736 | ) | ||||||||||||||
Future net cash flows | 2,222,356 | 1,922,386 | 2,012,045 | |||||||||||||||||
10% annual discount for estimated timing of cash flows | (996,380 | ) | (842,430 | ) | (924,136 | ) | ||||||||||||||
Standardized measure of discounted future net cash flows relating to proved oil, NGLs, and natural gas reserves | $ | 1,225,976 | $ | 1,079,956 | $ | 1,087,909 | ||||||||||||||
Schedule Of Principal Sources Of Changes In Standardized Measure Of Discounted Future Net Cash Flows | ' | |||||||||||||||||||
The principal sources of changes in the standardized measure of discounted future net cash flows were as follows: | ||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||
(In thousands) | ||||||||||||||||||||
Sales and transfers of oil and natural gas produced, net of production costs | $ | (470,970 | ) | $ | (425,626 | ) | $ | (389,339 | ) | |||||||||||
Net changes in prices and production costs | 188,826 | (321,099 | ) | 115,852 | ||||||||||||||||
Revisions in quantity estimates and changes in production timing | (10,650 | ) | (148,648 | ) | (38,336 | ) | ||||||||||||||
Extensions, discoveries and improved recovery, less related costs | 426,377 | 432,058 | 401,134 | |||||||||||||||||
Changes in estimated future development costs | 26,629 | 51,587 | 37,742 | |||||||||||||||||
Previously estimated cost incurred during the period | 96,457 | 104,377 | 45,327 | |||||||||||||||||
Purchases of minerals in place | 9 | 283,774 | 58,567 | |||||||||||||||||
Sales of minerals in place | (43,435 | ) | (112,359 | ) | (29 | ) | ||||||||||||||
Accretion of discount | 147,579 | 157,842 | 128,492 | |||||||||||||||||
Net change in income taxes | (170,091 | ) | 94,678 | (60,675 | ) | |||||||||||||||
Other—net | (44,711 | ) | (124,537 | ) | (65,912 | ) | ||||||||||||||
Net change | 146,020 | (7,953 | ) | 232,823 | ||||||||||||||||
Beginning of year | 1,079,956 | 1,087,909 | 855,086 | |||||||||||||||||
End of year | $ | 1,225,976 | $ | 1,079,956 | $ | 1,087,909 | ||||||||||||||
Summary_Of_Significant_Account3
Summary Of Significant Accounting Policies (Schedule Of Segment's Revenues) (Details) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Valero Energy Corporation | Oil and Natural Gas [Member] | ' | ' | ' |
Revenue, Major Customer [Line Items] | ' | ' | ' |
Segment's revenues | 25.30% | 26.00% | 18.00% |
Sunoco Partners Marketing | Oil and Natural Gas [Member] | ' | ' | ' |
Revenue, Major Customer [Line Items] | ' | ' | ' |
Segment's revenues | 7.50% | 8.00% | 10.00% |
QEP Resources, Inc. | Drilling [Member] | ' | ' | ' |
Revenue, Major Customer [Line Items] | ' | ' | ' |
Segment's revenues | 18.00% | 15.00% | 22.00% |
Kodiak Oil and Gas Corp. | Drilling [Member] | ' | ' | ' |
Revenue, Major Customer [Line Items] | ' | ' | ' |
Segment's revenues | 10.00% | 10.00% | 6.00% |
ONEOK, Inc. | Mid-Stream [Member] | ' | ' | ' |
Revenue, Major Customer [Line Items] | ' | ' | ' |
Segment's revenues | 50.19% | 54.00% | 54.00% |
Tenaska Resources, LLC | Mid-Stream [Member] | ' | ' | ' |
Revenue, Major Customer [Line Items] | ' | ' | ' |
Segment's revenues | 16.37% | 7.00% | 1.38% |
Gavilon, LLC | Mid-Stream [Member] | ' | ' | ' |
Revenue, Major Customer [Line Items] | ' | ' | ' |
Segment's revenues | 0.00% | 10.00% | 19.00% |
Summary_Of_Significant_Account4
Summary Of Significant Accounting Policies (Schedule Of Fair Values Of The Net Assets (Liabilities)) (Details) (USD $) | Dec. 31, 2013 |
In Thousands, unless otherwise specified | |
Derivative Counterparty [Line Items] | ' |
Total assets (liabilities) | ($5,000) |
Canadian Imperial Bank of Commerce | ' |
Derivative Counterparty [Line Items] | ' |
Total assets (liabilities) | 500 |
Scotiabank | ' |
Derivative Counterparty [Line Items] | ' |
Total assets (liabilities) | -300 |
Bank of Montreal | ' |
Derivative Counterparty [Line Items] | ' |
Total assets (liabilities) | ($5,200) |
Summary_Of_Significant_Account5
Summary Of Significant Accounting Policies (Narrative) (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2012 | Jun. 30, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
contract | |||||
Unit | |||||
Summary Of Significant Accounting Policies [Line Items] | ' | ' | ' | ' | ' |
Number of daywork contracts | ' | ' | 23 | ' | ' |
Number of contracts, daywork expiring in one year | ' | ' | 22 | ' | ' |
Number of contracts, daywork expiring in two years | ' | ' | 1 | ' | ' |
Book overdrafts | $7,000,000 | ' | $0 | $7,000,000 | ' |
Concentration of cash | 40,400,000 | ' | 52,100,000 | 40,400,000 | ' |
Minimum depreciation percentage for idle drilling rigs | ' | ' | 20.00% | ' | ' |
Impairment of long-lived assets held-for-use | 1,200,000 | ' | 0 | 1,200,000 | 0 |
Goodwill impairment | ' | ' | 0 | 0 | 0 |
Additions to goodwill | ' | ' | 0 | 0 | 0 |
Goodwill deductible for tax purposes | ' | ' | 3,900,000 | ' | ' |
Intangible asset impairment | ' | ' | 0 | 0 | 0 |
Amortization on intangible assets | ' | ' | 700,000 | 1,200,000 | 1,200,000 |
Accumulated amortization on intangible assets | 17,300,000 | ' | 18,000,000 | 17,300,000 | ' |
Amortization to be recorded in 2014 on intangible assets | ' | ' | 0 | ' | ' |
Directly related overhead costs capitalized | 17,600,000 | ' | 21,500,000 | 17,600,000 | 15,600,000 |
Average rates used for depreciation, depletion and amortization per Boe | ' | ' | 13.32 | 14.7 | 15.06 |
Unproved properties not being amortized | 521,659,000 | ' | 545,588,000 | 521,659,000 | 185,632,000 |
Future discounted net cash flows discounted | ' | ' | 10.00% | ' | ' |
Impairment of oil and natural gas properties | 167,700,000 | 115,900,000 | 0 | 283,606,000 | 0 |
Non-cash ceiling test write-down net of tax | 104,400,000 | 72,100,000 | ' | ' | ' |
Effects of cash flow hedges | 29,800,000 | 32,500,000 | ' | ' | ' |
Revenues from transactions with operating segments of same entity | ' | ' | 64,300,000 | 49,600,000 | 52,200,000 |
Eliminated associated operating expense | ' | ' | 46,900,000 | 34,100,000 | 32,600,000 |
Eliminated yielding | ' | ' | 17,400,000 | 15,500,000 | 19,600,000 |
Number of partnerships | ' | ' | 16 | ' | ' |
Minimum [Member] | ' | ' | ' | ' | ' |
Summary Of Significant Accounting Policies [Line Items] | ' | ' | ' | ' | ' |
Number of days for drilling of one well | ' | ' | '20 days | ' | ' |
Duration length of contracts | ' | ' | '0 years 6 months | ' | ' |
Insurance coverage | ' | ' | 50,000 | ' | ' |
Maximum [Member] | ' | ' | ' | ' | ' |
Summary Of Significant Accounting Policies [Line Items] | ' | ' | ' | ' | ' |
Number of days for drilling of one well | ' | ' | '90 days | ' | ' |
Duration length of contracts | ' | ' | '3 years | ' | ' |
Insurance coverage | ' | ' | 1,500,000 | ' | ' |
Under-Produced Properties [Member] | ' | ' | ' | ' | ' |
Summary Of Significant Accounting Policies [Line Items] | ' | ' | ' | ' | ' |
Natural gas balancing (MMcf) | ' | ' | 5,200 | ' | ' |
Over-Produced Properties [Member] | ' | ' | ' | ' | ' |
Summary Of Significant Accounting Policies [Line Items] | ' | ' | ' | ' | ' |
Natural gas balancing (MMcf) | ' | ' | 4,500 | ' | ' |
Natural Gas Balancing [Member] | ' | ' | ' | ' | ' |
Summary Of Significant Accounting Policies [Line Items] | ' | ' | ' | ' | ' |
Accounts receivable | ' | ' | 2,000,000 | ' | ' |
Liability recognized to under production | ' | ' | $3,800,000 | ' | ' |
Jul'12 - Dec'12 [Member] | ' | ' | ' | ' | ' |
Summary Of Significant Accounting Policies [Line Items] | ' | ' | ' | ' | ' |
Portion of future oil and gas production being hedged, as of the reporting period (MMBoe) | ' | 2.9 | ' | ' | ' |
Jan'13 - Dec'13 [Member] | ' | ' | ' | ' | ' |
Summary Of Significant Accounting Policies [Line Items] | ' | ' | ' | ' | ' |
Portion of future oil and gas production being hedged, as of the reporting period (MMBoe) | 6.9 | 4.5 | ' | ' | ' |
Property, Plant and Equipment, Other Types [Member] | Minimum [Member] | ' | ' | ' | ' | ' |
Summary Of Significant Accounting Policies [Line Items] | ' | ' | ' | ' | ' |
Useful life, years | ' | ' | '3 years | ' | ' |
Property, Plant and Equipment, Other Types [Member] | Maximum [Member] | ' | ' | ' | ' | ' |
Summary Of Significant Accounting Policies [Line Items] | ' | ' | ' | ' | ' |
Useful life, years | ' | ' | '15 years | ' | ' |
Drilling Equipment [Member] | Minimum [Member] | ' | ' | ' | ' | ' |
Summary Of Significant Accounting Policies [Line Items] | ' | ' | ' | ' | ' |
Useful life, years | ' | ' | '15 years | ' | ' |
Acquisitions_and_Divestitures_1
Acquisitions and Divestitures - Fair Value of Acquired Assets and Liabilities (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Sep. 17, 2012 | |
In Thousands, unless otherwise specified | Western Oklahoma and Texas Panhandle [Member] | ||||
Noble Energy, Inc. [Member] | |||||
Adjusted Purchase Price [Abstract] | ' | ' | ' | ' | |
Total consideration given | ' | ' | ' | $592,627 | |
Oil and natural gas properties included in the full cost pool: | ' | ' | ' | ' | |
Proved oil and natural gas properties | ' | ' | ' | 260,799 | |
Unproved oil and natural gas properties | ' | ' | ' | 353,343 | |
Total oil and natural gas properties included in the full cost pool | ' | ' | ' | 614,142 | [1] |
Equipment and facilities | ' | ' | ' | 25,163 | |
Asset retirement obligation | -133,657 | -146,159 | -96,446 | -46,678 | |
Fair value of net assets acquired | ' | ' | ' | $592,627 | |
[1] | We used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. |
Acquisitions_and_Divestitures_2
Acquisitions and Divestitures - Pro Forma (Details) (USD $) | 12 Months Ended | |
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2012 | Dec. 31, 2011 |
Pro forma: | ' | ' |
Revenues | $1,376,393 | $1,336,227 |
Net income | $83,940 | $229,272 |
Net income per common share: | ' | ' |
Basic | $1.75 | $4.81 |
Diluted | $1.74 | $4.78 |
Acquisitions_and_Divestitures_3
Acquisitions and Divestitures - Narrative (Details) (USD $) | 3 Months Ended | 12 Months Ended | 1 Months Ended | 3 Months Ended | 1 Months Ended | |||||||||||||||||||
Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Nov. 13, 2012 | 18-May-11 | Aug. 31, 2013 | Sep. 30, 2012 | Sep. 30, 2012 | Dec. 31, 2012 | Jul. 24, 2012 | Sep. 17, 2012 | Sep. 17, 2012 | Jul. 20, 2011 | Aug. 31, 2011 | Aug. 31, 2012 | Sep. 17, 2012 | |
rig | rig | Bakken [Member] | Bakken [Member] | Brazos and Madison Counties [Member] | Noble Energy, Inc. [Member] | Noble Energy, Inc. [Member] | Noble Energy, Inc. [Member] | Noble Energy, Inc. [Member] | Oklahoma And Lipscomb [Member] | Oklahoma Arkoma Woodford And Hartshorne Coal [Member] | Oklahoma Arkoma Woodford And Hartshorne Coal [Member] | Western Oklahoma and Texas Panhandle [Member] | ||||||||||||
Granite Wash [Member] | Other Plays [Member] | acre | locations | acre | Noble Energy, Inc. [Member] | |||||||||||||||||||
locations | acre | Unit | systems | |||||||||||||||||||||
acre | MMBoe | |||||||||||||||||||||||
acre | ||||||||||||||||||||||||
Business Combination, Description [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Payments to acquire oil and gas property | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $12,300,000 | $30,500,000 | ' | ' |
Acquired operated wells | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 30 | ' | ' | ' |
Acquired non-operated wells | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 59 | ' | ' | ' |
Purchase price allocation for proved properties | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8,400,000 | ' | ' | ' |
Unproved properties | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,900,000 | ' | ' | ' |
Acres acquired held by production | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 12,000 | ' | ' | ' |
Operating and non-operating number of wells | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 500 | ' | ' |
Oil And Gas Developed And Undeveloped Acreage Net | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 55,000 | ' |
Percentage of acre held for production | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 96.00% | ' | ' |
Land acquired (in acres) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 24,000 | 59,000 | ' | ' | ' | 83,000 |
Total consideration given | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 592,627,000 |
Proved developed reserves (BOE) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 44,000,000 |
Number of horizontal driling locations included in the land acquired | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 600 | ' | ' | ' | ' | ' |
Acquired land with existing production capacity, percent | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 95.00% | ' | ' | ' | ' |
Natural gas gathering systems received as part of acquisition | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4 |
Aggregate principal amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 650,000,000 | 250,000,000 | ' | ' | ' | ' | 400,000,000 | ' | ' | ' | ' | ' | ' |
Revenues | 359,121,000 | 333,776,000 | 340,421,000 | 318,532,000 | 331,582,000 | 321,790,000 | 327,785,000 | 333,966,000 | 1,351,850,000 | 1,315,123,000 | 1,207,503,000 | ' | ' | ' | ' | ' | 21,400,000 | ' | ' | ' | ' | ' | ' | ' |
Net income | 51,301,000 | 34,232,000 | 59,007,000 | 40,206,000 | -56,547,000 | 46,586,000 | -19,302,000 | 52,439,000 | 184,746,000 | 23,176,000 | 195,867,000 | ' | ' | ' | ' | ' | 800,000 | ' | ' | ' | ' | ' | ' | ' |
Asset Divestiture [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Proceeds from divestiture of assets | ' | ' | ' | ' | ' | ' | ' | ' | 21,700,000 | ' | ' | ' | ' | 57,100,000 | 226,600,000 | 44,100,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Number of rigs sold | ' | ' | ' | ' | ' | ' | ' | ' | 5 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Gain (Loss) on Disposition of Property Plant Equipment | ' | ' | ' | ' | ' | ' | ' | ' | 16,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of rigs held for sale | 4 | ' | ' | ' | ' | ' | ' | ' | 4 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Assets held for sale | 15,621,000 | ' | ' | ' | 0 | ' | ' | ' | 15,621,000 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Estimated gain (loss) on sale of assets | ' | ' | ' | ' | ' | ' | ' | ' | $10,400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Earnings_Per_Share_Schedule_Of
Earnings Per Share (Schedule Of Earnings Per Share) (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||||||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||||
Earnings Per Share [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Income of basic earnings per common share | $51,301 | $34,232 | $59,007 | $40,206 | ($56,547) | $46,586 | ($19,302) | $52,439 | $184,746 | $23,176 | $195,867 | ||||
Income of effect of dilutive stock options, restricted stock, and SARs | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 0 | ||||
Income of diluted earnings per common share | ' | ' | ' | ' | ' | ' | ' | ' | $184,746 | $23,176 | $195,867 | ||||
Weighted shares of basic earnings per common share | ' | ' | ' | ' | ' | ' | ' | ' | 48,218 | 47,909 | 47,658 | ||||
Weighted shares of effect of dilutive stock options, restricted stock, and SARs | ' | ' | ' | ' | ' | ' | ' | ' | 354 | 245 | 293 | ||||
Weighted shares of diluted earnings per common share | ' | ' | ' | ' | ' | ' | ' | ' | 48,572 | 48,154 | 47,951 | ||||
Per share amount of basic earnings per common share | $1.06 | $0.71 | $1.22 | $0.84 | ($1.18) | [1] | $0.97 | [1] | ($0.40) | [1] | $1.10 | [1] | $3.83 | $0.48 | $4.11 |
Per share amount of effect of dilutive stock options, restricted stock, and SARs | ' | ' | ' | ' | ' | ' | ' | ' | ($0.03) | $0 | ($0.03) | ||||
Per share amount of diluted earnings per common share | $1.05 | $0.70 | $1.22 | $0.83 | ($1.18) | $0.97 | ($0.40) | $1.09 | $3.80 | $0.48 | $4.08 | ||||
[1] | Due to the effect of rounding the basic earnings per share for the yearbs four quarters does not equal annual earnings per share. |
Earnings_Per_Share_Schedule_Of1
Earnings Per Share (Schedule Of Antidilutive Securities Excluded From Computation Of Earnings Per Share) (Details) (Derivative [Member], USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Derivative [Member] | ' | ' | ' |
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ' | ' | ' |
Stock options and SARs | 149,665 | 250,901 | 105,000 |
Average Exercise Price | $58.41 | $52.72 | $61.24 |
Accrued_Liabilities_Accrued_Li
Accrued Liabilities (Accrued Liabilities) (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Accrued Liabilities [Abstract] | ' | ' |
Employee costs | $27,633 | $24,632 |
Lease operating expenses | 16,073 | 10,903 |
Interest Payable | 6,504 | 6,568 |
Deposits on assets held for sale | 3,750 | 0 |
Taxes | 2,313 | 7,308 |
Hedge settlements | 416 | 160 |
Other | 7,674 | 4,527 |
Total accrued liabilities | $64,363 | $54,098 |
LongTerm_Debt_And_Other_LongTe2
Long-Term Debt And Other Long-Term Liabilities (Long-Term Debt) (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
Long-term debt and other long-term liabilites [Abstract] | ' | ' |
Credit agreement with an average interest rates of 2.9% at December 31, 2012 | $0 | $71,100,000 |
6.625% senior subordinated notes due 2021, net of unamortized discount of $4.3 million and $4.7 million at December 31, 2013 and 2012, respectively | 645,696,000 | 645,259,000 |
Total long-term debt | 645,696,000 | 716,359,000 |
Line of Credit Facility, Interest Rate at Period End | 0.00% | 2.90% |
Debt Instrument, Unamortized Discount | $4,300,000 | $4,700,000 |
LongTerm_Debt_And_Other_LongTe3
Long-Term Debt And Other Long-Term Liabilities (Other Long-Term Liabilities) (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
In Thousands, unless otherwise specified | |||
Long-term debt and other long-term liabilites [Abstract] | ' | ' | ' |
ARO liability | $133,657 | $146,159 | $96,446 |
Workers' compensation | 20,041 | 18,517 | ' |
Separation benefit plans | 9,382 | 7,972 | ' |
Gas balancing liability | 3,775 | 3,838 | ' |
Deferred compensation plan | 3,589 | 2,779 | ' |
Other liabilities | 170,444 | 179,265 | ' |
Less current portion | 12,113 | 12,282 | ' |
Total other long-term liabilities | $158,331 | $166,983 | ' |
LongTerm_Debt_And_Other_LongTe4
Long-Term Debt And Other Long-Term Liabilities (Narrative) (Details) (USD $) | 0 Months Ended | 12 Months Ended | |||||
Jul. 24, 2012 | 18-May-12 | Dec. 31, 2013 | Dec. 31, 2012 | Nov. 13, 2012 | Sep. 05, 2012 | 18-May-11 | |
Debt Instrument [Line Items] | ' | ' | ' | ' | ' | ' | ' |
Credit Facility Maximum Credit Amount | ' | ' | $900,000,000 | ' | ' | ' | ' |
Commitment fee under credit facility standard | ' | ' | 1.00% | ' | ' | ' | ' |
Origination, agency and syndication fees | ' | ' | ' | ' | ' | 1,500,000 | ' |
Debt Instrument, Variable Interest Rate, Payable Assessment Period | ' | ' | '90 days | ' | ' | ' | ' |
LIBOR interest rate plus one percent | ' | ' | 'LIBOR plus 1.00% | ' | ' | ' | ' |
Credit agreement with an average interest rates of 2.9% at December 31, 2012 | ' | ' | 0 | 71,100,000 | ' | ' | ' |
Current ratio of credit facility | ' | ' | '1 to 1 | ' | ' | ' | ' |
Leverage ratio of long-term debt | ' | ' | '4 to 1 | ' | ' | ' | ' |
Aggregate principal amount | ' | ' | ' | ' | 650,000,000 | ' | 250,000,000 |
Interest percentage of senior subordinated notes | ' | ' | 6.63% | ' | 6.63% | ' | 6.63% |
Debt Instrument, Maturity Date | 15-May-21 | 15-May-21 | 15-May-21 | ' | ' | ' | ' |
Proceeds from sale of notes | ' | 244,000,000 | ' | ' | ' | ' | ' |
Deducting fees for debt issuance | 8,700,000 | 6,000,000 | ' | ' | ' | ' | ' |
Repayment of outstanding borrowings under unsecured credit facility | ' | 220,300,000 | ' | ' | ' | ' | ' |
Debt Instrument, Issued at Discount, Percent of Par | 98.75% | ' | ' | ' | ' | ' | ' |
Percentage of maximum, aggregate principal equity amount | ' | ' | 35.00% | ' | ' | ' | ' |
Proceed from equity offerings redemption price percentage | ' | ' | 106.63% | ' | ' | ' | ' |
Minimum redemption percentage of debt outstanding | ' | ' | 65.00% | ' | ' | ' | ' |
Equal redemption price percentage of principal amount of debt | ' | ' | 100.00% | ' | ' | ' | ' |
Senior notes repurchase price in percentage | ' | ' | 101.00% | ' | ' | ' | ' |
Current Year | ' | ' | 12,100,000 | ' | ' | ' | ' |
Year Two | ' | ' | 2,800,000 | ' | ' | ' | ' |
Year Three | ' | ' | 40,400,000 | ' | ' | ' | ' |
Year Four | ' | ' | 4,200,000 | ' | ' | ' | ' |
Year Five | ' | ' | 3,500,000 | ' | ' | ' | ' |
Minimum [Member] | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument [Line Items] | ' | ' | ' | ' | ' | ' | ' |
Commitment fee percentage under credit facility | ' | ' | 0.38% | ' | ' | ' | ' |
LIBOR plus interest rate | ' | ' | 1.75% | ' | ' | ' | ' |
Maximum [Member] | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument [Line Items] | ' | ' | ' | ' | ' | ' | ' |
Commitment fee percentage under credit facility | ' | ' | 0.50% | ' | ' | ' | ' |
LIBOR plus interest rate | ' | ' | 2.50% | ' | ' | ' | ' |
Payments of dividends exceeding percentage | ' | ' | 30.00% | ' | ' | ' | ' |
Senior Unsecured Credit Facility [Member] | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument [Line Items] | ' | ' | ' | ' | ' | ' | ' |
Credit facility maturity date | ' | ' | 'September 13, 2016 | ' | ' | ' | ' |
Senior Notes, 6.625% Due 2021 [Member] | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument [Line Items] | ' | ' | ' | ' | ' | ' | ' |
Aggregate principal amount | 400,000,000 | ' | ' | ' | ' | ' | ' |
Line Of Credit Facility Commitment Amount [Member] | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument [Line Items] | ' | ' | ' | ' | ' | ' | ' |
Credit facility current credit amount | ' | ' | 500,000,000 | ' | ' | ' | ' |
Line Of Credit Facility Lender Determined Amount [Member] | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument [Line Items] | ' | ' | ' | ' | ' | ' | ' |
Credit facility current credit amount | ' | ' | $800,000,000 | ' | ' | ' | ' |
Asset_Retirement_Obligations_S
Asset Retirement Obligations (Schedule Of Asset Retirement Obligations) (Details) (USD $) | 12 Months Ended | |||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | ||
ARO liability, January 1: | $146,159 | $96,446 | ||
Accretion of discount | 5,450 | 4,615 | ||
Liability incurred | 4,857 | 56,650 | [1] | |
Liability settled | -4,751 | -2,788 | ||
Liability sold | -2,622 | -1,258 | ||
Revision of estimates | -15,436 | [2] | -7,506 | [2] |
ARO liability, December 31: | 133,657 | 146,159 | ||
Less current portion | 2,954 | 2,953 | ||
Total long-term ARO liability | 130,703 | 143,206 | ||
Noble Energy, Inc. [Member] | ' | ' | ||
Liability incurred | ' | $46,700 | ||
[1] | The liability incurred increased $46.7 million related to the Noble properties acquired in September 2012. | |||
[2] | Plugging liability estimates were revised in both 2013 and 2012 for updates in the cost of services used to plug wells over the preceding year. We had various upward and downward adjustments as well as changes in estimated timing of cash flows. |
Income_Taxes_Reconciliation_Of
Income Taxes (Reconciliation Of Income Tax Expense) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Income Tax Disclosure [Abstract] | ' | ' | ' |
Income tax expense computed by applying the statutory rate | $105,514 | $13,791 | $111,651 |
State income tax, net of federal benefit | 8,290 | 1,084 | 8,941 |
Statutory depletion and other | 2,919 | 1,351 | 2,543 |
Total income taxes | $116,723 | $16,226 | $123,135 |
Income_Taxes_Schedule_Of_Total
Income Taxes (Schedule Of Total Provision For Income Taxes) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Income Tax Disclosure [Abstract] | ' | ' | ' |
Current taxes, Federal | $15,845 | $2,084 | ($3,159) |
Current taxes, State | 146 | -1,388 | 743 |
Current taxes | 15,991 | 696 | -2,416 |
Deferred taxes, Federal | 87,839 | 13,768 | 109,363 |
Deferred taxes, State | 12,893 | 1,762 | 16,188 |
Deferred taxes | 100,732 | 15,530 | 125,551 |
Total provision | $116,723 | $16,226 | $123,135 |
Income_Taxes_Schedule_Of_Defer
Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Income Tax Disclosure [Abstract] | ' | ' |
Allowance for losses and nondeductible accruals | $77,285 | $74,890 |
Net operating loss carryforward | 61,055 | 56,020 |
Alternative minimum tax credit carryforward | 17,258 | 1,972 |
Deferred tax assets, total | 155,598 | 132,882 |
Depreciation, depletion, amortization and impairment | -943,411 | -819,893 |
Net deferred tax liability | -787,813 | -687,011 |
Current deferred tax asset | 13,585 | 8,765 |
Non-current-deferred tax liability | ($801,398) | ($695,776) |
Income_Taxes_Narrative_Details
Income Taxes (Narrative) (Details) (USD $) | 12 Months Ended |
In Millions, unless otherwise specified | Dec. 31, 2013 |
Operating Loss Carryforwards [Line Items] | ' |
Operating loss carryforwards | 146.5 |
Start [Member] | ' |
Operating Loss Carryforwards [Line Items] | ' |
Operating loss expiration period | 31-Dec-15 |
End [Member] | ' |
Operating Loss Carryforwards [Line Items] | ' |
Operating loss expiration period | 31-Dec-33 |
Employee_Benefit_Plans_Details
Employee Benefit Plans (Details) (USD $) | 12 Months Ended | 12 Months Ended | ||||||||||
In Millions, except Share data, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Jan. 01, 1997 | 5-May-04 | Dec. 31, 2013 | Dec. 31, 2013 |
D | Employee Thrift Plan [Member] | Employee Thrift Plan [Member] | Employee Thrift Plan [Member] | Salary Deferral Plan [Member] | Salary Deferral Plan [Member] | Separation Plan [Member] | Special Separation Benefit Plan [Member] | Change Of Control Contracts [Member] | Plan 401k [Member] | |||
Y | Y | Y | Y | Y | ||||||||
week | ||||||||||||
Defined Benefit Plan Disclosure [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Contribution of shares, common stock | ' | ' | ' | 111,995 | 95,598 | 71,742 | ' | ' | ' | ' | ' | ' |
Recognized stock compensation expense | $16.10 | $11.40 | $10 | $6 | $5.50 | $4.30 | ' | ' | ' | ' | ' | ' |
Liability recorded under deferral plan | ' | ' | ' | ' | ' | ' | 3.6 | 2.8 | ' | ' | ' | ' |
Service period, years | ' | ' | ' | ' | ' | ' | ' | ' | 20 | 20 | ' | ' |
Maximum period benefit, weeks | ' | ' | ' | ' | ' | ' | ' | ' | 104 | ' | ' | ' |
Age limit | ' | ' | ' | ' | ' | ' | ' | ' | ' | 65 | ' | ' |
Separation benefit plans expense | $2.40 | $2.20 | $1.90 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Employee contract period, years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3 | ' |
Employment contract period extension, years | 1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Grace period following the first anniversary | 30 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Multiple for determination compensation | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2.9 | ' |
Additional period for 401k, years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3 |
Transactions_With_Related_Part2
Transactions With Related Parties Transactions With Related Parties (Schedule of Amount Received in Public and Private Partnerships) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Related Party Transaction [Line Items] | ' | ' | ' |
Contract Drilling Fees | $16 | $246 | $352 |
Well Supervision And Other Fees | 470 | 434 | 396 |
General And Administrative Expense Reimbursement | $36 | $39 | $610 |
Transactions_With_Related_Part3
Transactions With Related Parties (Narrative) (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Related Party Transaction [Line Items] | ' | ' | ' |
Number of oil and gas limited partnerships | 16 | ' | ' |
Number of oil and gas limited partnerships for third party investment | 3 | ' | ' |
Number of oil and gas limited partnerships for employee investment | 13 | ' | ' |
Minimum salary for employees to participate in the oil and gas partnership | ' | ' | $36,000 |
Minimum [Member] | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' |
Interest rate of employee partnerships in oil and gas properties | 1.00% | ' | ' |
Maximum [Member] | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' |
Interest rate of employee partnerships in oil and gas properties | 15.00% | ' | ' |
Upland Resources [Member] | ' | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' |
Number of wells drilled | 0 | 3 | ' |
Revenue from Related Parties | ' | 1,600,000 | ' |
Payments for Royalties | $1,400,000 | $1,200,000 | $700,000 |
Shareholder_Rights_Plan_Detail
Shareholder Rights Plan (Details) (USD $) | 12 Months Ended |
Dec. 31, 2013 | |
D | |
Shareholder Rights Plan [Abstract] | ' |
Right of common stock | 'one |
Percentage of fair value of common stock that can be acquired | 50.00% |
Rights become exercisable period, in days | 10 |
Minimum percentage of common stock that should be acquired | 15.00% |
Redemption price per share | $0.01 |
Shareholder rights plan expiration date | 'May 19, 2015 |
StockBased_Compensation_Schedu
Stock-Based Compensation (Schedule Of Restricted Stock Awards Stock Options And SAR) (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' |
Recognized stock compensation expense | $16.10 | $11.40 | $10 |
Capitalized stock compensation cost for our oil and natural gas properties | 3.5 | 2.7 | 2.5 |
Tax benefit on stock based compensation | $6.20 | $4.50 | $3.90 |
StockBased_Compensation_Estima
Stock-Based Compensation (Estimated Fair Value Of The Stock Options Granted) (Details) (Directors Plan [Member], USD $) | 12 Months Ended | ||
In Millions, except Share data, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Directors Plan [Member] | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' |
Options granted | 0 | 0 | 31,500 |
Estimated fair value (in millions) | ' | ' | $0.70 |
Estimate of stock volatility | ' | ' | 0.48 |
Estimated dividend yield | ' | ' | 0.00% |
Risk free interest rate | ' | ' | 2.00% |
Expected life range based on prior experience (in years) | ' | ' | '5 years |
Forfeiture rate | ' | ' | 0.00% |
StockBased_Compensation_StockB
Stock-Based Compensation Stock-Based Compensation (Activity Pertaining to Stock Appreciation Rights) (Details) (Stock Appreciation Rights (SARs) [Member], USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Stock Appreciation Rights (SARs) [Member] | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' |
Number of shares, beginning balance | 145,901 | 145,901 | 145,901 |
Weighted average grant date price, beginning balance | $46.59 | $46.59 | $46.59 |
Number of shares, granted | 0 | 0 | 0 |
Weighted average grant date price, granted | $0 | $0 | $0 |
Number of shares, exercised | 0 | 0 | 0 |
Weighted average grant date price, exercised | $0 | $0 | $0 |
Number of shares, forfeited | 0 | 0 | 0 |
Weighted average grant date price, forfeited | $0 | $0 | $0 |
Number of shares, ending balance | 145,901 | 145,901 | 145,901 |
Weighted average grant date price, ending balance | $46.59 | $46.59 | $46.59 |
StockBased_Compensation_Activi
Stock-Based Compensation (Activity Pertaining To Restricted Stock Awards) (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Restricted Stock [Member] | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' |
Number of shares, beginning balance | 589,527 | 447,961 | 446,125 |
Weighted average grant date price, beginning balance | $48.11 | $47.44 | $47.39 |
Number of shares, granted | 453,549 | 376,445 | 211,050 |
Weighted average grant date price, granted | $48.20 | $47.37 | $55.91 |
Number of Shares, Vested | -248,003 | -220,788 | -190,262 |
Weighted average grant date price, exercised | $46.46 | $45.66 | $43.32 |
Number of shares, forfeited | -18,330 | -14,091 | -18,952 |
Weighted average grant date price, forfeited | $47.85 | $45.37 | $44.55 |
Number of shares, ending balance | 776,743 | 589,527 | 447,961 |
Weighted average grant date price, ending balance | $48.70 | $48.11 | $47.44 |
Non-employee Directors [Member] | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' |
Number of shares, beginning balance | 24,606 | 0 | ' |
Weighted average grant date price, beginning balance | $40.23 | $0 | ' |
Number of shares, granted | 21,128 | 24,606 | ' |
Weighted average grant date price, granted | $41.65 | $40.23 | ' |
Number of Shares, Vested | -10,030 | 0 | ' |
Weighted average grant date price, exercised | $40.23 | $0 | ' |
Number of shares, forfeited | 0 | 0 | ' |
Weighted average grant date price, forfeited | $0 | $0 | ' |
Number of shares, ending balance | 35,704 | 24,606 | ' |
Weighted average grant date price, ending balance | $41.07 | $40.23 | ' |
StockBased_Compensation_StockB1
Stock-Based Compensation Stock-Based Compensation (Activity Pertaining to Stock Options) (Details) (Stock Options [Member], USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Stock Options [Member] | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' |
Number of Shares, Beginning Balance | 118,030 | 138,980 | 184,765 |
Weighted average grant date price, beginning balance | $33.03 | $31.39 | $31.11 |
Number of Shares, Granted | 0 | 0 | 0 |
Weighted average grant date price, granted | $0 | $0 | $0 |
Number of Shares, Exercised | -48,110 | -18,850 | -42,285 |
Weighted Average Grant Date Price, Exercised | $26.09 | $20.38 | $28.29 |
Number of Shares, Forfeited | -1,000 | -2,100 | -3,500 |
Weighted average grant date price, forfeited | $37.83 | $37.83 | $53.90 |
Number of Shares, Ending Balance | 68,920 | 118,030 | 138,980 |
Weighted average grant date price, ending balance | $37.81 | $33.03 | $31.39 |
StockBased_Compensation_Shares
Stock-Based Compensation (Shares Authorized Under Stock Option Plans By Exercise Price Range) (Details) (USD $) | 12 Months Ended |
Dec. 31, 2013 | |
Stock Options [Member] | $37.69 - $37.83 [Member] | ' |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | ' |
Exercise Prices Minimum | $37.69 |
Exercise Prices Maximum | $37.83 |
Outstanding and Exercisable Options, Number Of Shares | 68,920 |
Outstanding and exercisable options weighted average remaining contractual life, years | '1 year |
Outstanding and Exercisable Options, Weighted Average Exercise Price | $37.81 |
Directors Plan [Member] | $28.23 - $41.21 [Member] | ' |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | ' |
Exercise Prices Minimum | $28.23 |
Exercise Prices Maximum | $41.21 |
Outstanding and Exercisable Options, Number Of Shares | 66,500 |
Outstanding and exercisable options weighted average remaining contractual life, years | '4 years 7 months 6 days |
Outstanding and Exercisable Options, Weighted Average Exercise Price | $36.64 |
Directors Plan [Member] | $53.81 - $73.26 [Member] | ' |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | ' |
Exercise Prices Minimum | $53.81 |
Exercise Prices Maximum | $73.26 |
Outstanding and Exercisable Options, Number Of Shares | 105,000 |
Outstanding and exercisable options weighted average remaining contractual life, years | '4 years 6 months |
Outstanding and Exercisable Options, Weighted Average Exercise Price | $61.24 |
StockBased_Compensation_StockB2
Stock-Based Compensation Stock-Based Compensation (Activity Pertaining to Nonemployee Director Stock Award Plan) (Details) (Directors Plan [Member], USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Directors Plan [Member] | ' | ' | ' |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' |
Number of Shares, Beginning Balance | 192,500 | 199,500 | 178,500 |
Weighted average grant date price, beginning balance | $49.39 | $48.37 | $48.77 |
Number of Shares, Granted | 0 | 0 | 31,500 |
Weighted average grant date price, granted | $0 | $0 | $53.81 |
Number of Shares, Exercised | -17,500 | -7,000 | -10,500 |
Weighted Average Grant Date Price, Exercised | $32.53 | $20.28 | $21.96 |
Number of Shares, Forfeited | -3,500 | 0 | 0 |
Weighted average grant date price, forfeited | $20.46 | $0 | $0 |
Number of Shares, Ending Balance | 171,500 | 192,500 | 199,500 |
Weighted average grant date price, ending balance | $51.70 | $49.39 | $48.37 |
StockBased_Compensation_Narrat
Stock-Based Compensation (Narrative) (Details) (USD $) | 3 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | |||||||||||||||||||||
In Millions, except Share data, unless otherwise specified | Mar. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2010 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2010 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2010 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2010 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 |
Stock Appreciation Rights (SARs) [Member] | Stock Appreciation Rights (SARs) [Member] | Stock Appreciation Rights (SARs) [Member] | Stock Appreciation Rights (SARs) [Member] | Restricted Stock [Member] | Restricted Stock [Member] | Restricted Stock [Member] | Restricted Stock [Member] | Restricted Stock [Member] | Restricted Stock [Member] | Restricted Stock [Member] | Restricted Stock [Member] | Restricted Stock [Member] | Stock Options [Member] | Stock Options [Member] | Stock Options [Member] | Stock Options [Member] | Directors Plan [Member] | Directors Plan [Member] | Directors Plan [Member] | Directors Plan [Member] | Incentive Stock Grants [Member] | 2011 [Member] | 2012 [Member] | 2013 [Member] | |||
Minimum [Member] | Maximum [Member] | First Half of 2016 [Member] | First Half of 2015 [Member] | First Half of 2014 [Member] | Restricted Stock [Member] | Restricted Stock [Member] | Restricted Stock [Member] | ||||||||||||||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Unrecognized compensation cost related to unvested awards | ' | $14.20 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Unrecognized compensation cost, expect to be capitalized | ' | 2.4 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Weighted average years over which this cost will be recognized | ' | '0 years 9 months 18 days | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Maximum number of shares of common stock allowed for the issuance | ' | 3,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,000,000 | ' | ' | ' |
Number of shares, granted | ' | ' | 0 | 0 | 0 | ' | 453,549 | 376,445 | 211,050 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Expire years | ' | ' | '10 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '10 years | ' | ' | ' | '10 years | ' | ' | ' | ' | ' | ' | ' |
Shares vested | ' | ' | 0 | 0 | 33,745 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of shares, ending balance | ' | ' | 145,901 | 145,901 | 145,901 | 145,901 | 776,743 | 589,527 | 447,961 | 446,125 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Aggregate intrinsic value | ' | ' | 0.7 | ' | ' | ' | 40.1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1 | ' | ' | ' | ' | ' | ' | ' |
Weighted average remaining contractual term, years | ' | ' | '3 years 7 months 6 days | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '1 year | ' | ' | ' | '4 years 7 months 6 days | ' | ' | ' | ' | ' | ' | ' |
Vesting Period | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '2 years | '3 years | ' | ' | ' | ' | ' | ' | ' | '0 years 6 months | ' | ' | ' | ' | ' | ' | ' |
Percentage of restricted stock awards to be vested as performance shares to executives | ' | ' | ' | ' | ' | ' | 30.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Restricted stock awards granted to designated executive officers | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 57,405 | 46,441 | 20,062 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Performance evaluation period | '3 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Performance percentage criteria | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.00% | 150.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 65.25% | 100.00% | 100.00% |
Grant date fair value | ' | ' | ' | ' | ' | ' | 21.3 | 16.9 | 10.8 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.7 | ' | ' | ' | ' | ' |
Number of Shares, Vested | ' | ' | ' | ' | ' | ' | -248,003 | -220,788 | -190,262 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Exercised intrinsic value | ' | ' | ' | ' | ' | ' | 11.3 | ' | ' | ' | ' | ' | ' | ' | ' | 1.1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Restricted stock weighted average remaining contractual term, years | ' | ' | ' | ' | ' | ' | '1 year | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Maximum Number of Shares of Common Stock Previously Allowed for the Issuance | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Vesting rate of options | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Cash received from the options exercised | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.1 | ' | ' | ' | 0.6 | ' | ' | ' | ' | ' | ' | ' |
Options Outstanding | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 68,920 | 118,030 | 138,980 | 184,765 | 171,500 | 192,500 | 199,500 | 178,500 | ' | ' | ' | ' |
Weighted average grant date price, ending balance | ' | ' | $46.59 | $46.59 | $46.59 | $46.59 | $48.70 | $48.11 | $47.44 | $47.39 | ' | ' | ' | ' | ' | $37.81 | $33.03 | $31.39 | $31.11 | $51.70 | $49.39 | $48.37 | $48.77 | ' | ' | ' | ' |
Exercisable options intrinsic value | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $1 | ' | ' | ' | $0.20 | ' | ' | ' | ' | ' | ' | ' |
Director option awards | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,500 | ' | ' | ' | ' | ' | ' |
Options granted | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 0 | ' | 0 | 0 | 31,500 | ' | ' | ' | ' | ' |
Number of Shares, Exercised | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -48,110 | -18,850 | -42,285 | ' | -17,500 | -7,000 | -10,500 | ' | ' | ' | ' | ' |
Derivatives_Derivatives_Schedu
Derivatives Derivatives (Schedule of Non-designated Hedges Outstanding) (Details) (Not Designated as Hedging Instrument [Member]) | 12 Months Ended |
Dec. 31, 2013 | |
MMBTU | |
Unit | |
Natural Gas [Member] | Swap [Member] | If Nymex [Member] | Jan'14 - Dec'14 [Member] | ' |
Derivative Instruments, Gain (Loss) [Line Items] | ' |
Hedged Volume (MMBtu/day) | 80,000 |
Weighted Average Fixed Price for Swaps | 4.24 |
Natural Gas [Member] | Collar [Member] | If Nymex [Member] | Jan'14 - Dec'14 [Member] | ' |
Derivative Instruments, Gain (Loss) [Line Items] | ' |
Hedged Volume (MMBtu/day) | 10,000 |
Crude Oil [Member] | Swap [Member] | Wti Nymex [Member] | Jan'14 - Jun'14 [Member] | ' |
Derivative Instruments, Gain (Loss) [Line Items] | ' |
Hedged Volume (Bbl/day) | 500 |
Weighted Average Fixed Price for Swaps | 100.03 |
Crude Oil [Member] | Swap [Member] | Wti Nymex [Member] | Jan'14 - Dec'14 [Member] | ' |
Derivative Instruments, Gain (Loss) [Line Items] | ' |
Hedged Volume (Bbl/day) | 3,000 |
Weighted Average Fixed Price for Swaps | 91.77 |
Crude Oil [Member] | Collar [Member] | Wti Nymex [Member] | Jan'14 - Dec'14 [Member] | ' |
Derivative Instruments, Gain (Loss) [Line Items] | ' |
Hedged Volume (Bbl/day) | 4,000 |
Minimum [Member] | Natural Gas [Member] | Swap [Member] | If Nymex [Member] | Jan'14 - Dec'14 [Member] | ' |
Derivative Instruments, Gain (Loss) [Line Items] | ' |
Commodity Derivatives Description Terms | 'Jan'14 |
Minimum [Member] | Natural Gas [Member] | Collar [Member] | If Nymex [Member] | Jan'14 - Dec'14 [Member] | ' |
Derivative Instruments, Gain (Loss) [Line Items] | ' |
Commodity Derivatives Description Terms | 'Jan'14 |
Weighted Average Fixed Price for Swaps | 3.75 |
Minimum [Member] | Crude Oil [Member] | Swap [Member] | Wti Nymex [Member] | Jan'14 - Jun'14 [Member] | ' |
Derivative Instruments, Gain (Loss) [Line Items] | ' |
Commodity Derivatives Description Terms | 'Jan'14 |
Minimum [Member] | Crude Oil [Member] | Swap [Member] | Wti Nymex [Member] | Jan'14 - Dec'14 [Member] | ' |
Derivative Instruments, Gain (Loss) [Line Items] | ' |
Commodity Derivatives Description Terms | 'Jan'14 |
Minimum [Member] | Crude Oil [Member] | Collar [Member] | Wti Nymex [Member] | Jan'14 - Dec'14 [Member] | ' |
Derivative Instruments, Gain (Loss) [Line Items] | ' |
Commodity Derivatives Description Terms | 'Jan'14 |
Weighted Average Fixed Price for Swaps | 90 |
Maximum [Member] | Natural Gas [Member] | Swap [Member] | If Nymex [Member] | Jan'14 - Dec'14 [Member] | ' |
Derivative Instruments, Gain (Loss) [Line Items] | ' |
Commodity Derivatives Description Terms | 'Dec'14 |
Maximum [Member] | Natural Gas [Member] | Collar [Member] | If Nymex [Member] | Jan'14 - Dec'14 [Member] | ' |
Derivative Instruments, Gain (Loss) [Line Items] | ' |
Commodity Derivatives Description Terms | 'Dec'14 |
Weighted Average Fixed Price for Swaps | 4.37 |
Maximum [Member] | Crude Oil [Member] | Swap [Member] | Wti Nymex [Member] | Jan'14 - Jun'14 [Member] | ' |
Derivative Instruments, Gain (Loss) [Line Items] | ' |
Commodity Derivatives Description Terms | 'Jun'14 |
Maximum [Member] | Crude Oil [Member] | Swap [Member] | Wti Nymex [Member] | Jan'14 - Dec'14 [Member] | ' |
Derivative Instruments, Gain (Loss) [Line Items] | ' |
Commodity Derivatives Description Terms | 'Dec'14 |
Maximum [Member] | Crude Oil [Member] | Collar [Member] | Wti Nymex [Member] | Jan'14 - Dec'14 [Member] | ' |
Derivative Instruments, Gain (Loss) [Line Items] | ' |
Commodity Derivatives Description Terms | 'Dec'14 |
Weighted Average Fixed Price for Swaps | 96.08 |
Derivatives_Schedule_Of_Subseq
Derivatives (Schedule Of Subsequent Non-designated Hedges) (Details) (Not Designated as Hedging Instrument [Member], Subsequent to December 31, 2013 [Member], Mar'14 [Member], Natural Gas [Member], Basis Swap [Member]) | 12 Months Ended |
Dec. 31, 2013 | |
MMBTU | |
Unit | |
NGPL-TXOK [Member] | ' |
Derivative Instruments, Gain (Loss) [Line Items] | ' |
Hedged Volume (MMBtu/day) | 30,000 |
Weighted Average Fixed Price for Swaps | -0.095 |
NGPL-Midcon [Member] [Member] | ' |
Derivative Instruments, Gain (Loss) [Line Items] | ' |
Hedged Volume (MMBtu/day) | 60,000 |
Weighted Average Fixed Price for Swaps | -0.027 |
Start [Member] | NGPL-TXOK [Member] | ' |
Derivative Instruments, Gain (Loss) [Line Items] | ' |
Commodity Derivatives Term | 'Mar'14 |
Start [Member] | NGPL-Midcon [Member] [Member] | ' |
Derivative Instruments, Gain (Loss) [Line Items] | ' |
Commodity Derivatives Term | 'Mar'14 |
End [Member] | NGPL-TXOK [Member] | ' |
Derivative Instruments, Gain (Loss) [Line Items] | ' |
Commodity Derivatives Term | 'Mar'14 |
End [Member] | NGPL-Midcon [Member] [Member] | ' |
Derivative Instruments, Gain (Loss) [Line Items] | ' |
Commodity Derivatives Term | 'Mar'14 |
Derivatives_Fair_Value_Of_Deri
Derivatives (Fair Value Of Derivative Instruments And Locations In Balance Sheets) (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Derivatives, Fair Value [Line Items] | ' | ' |
Current derivative assets | $515 | $16,552 |
Total derivatives assets | 515 | 16,552 |
Current portion of derivative liabilities | 5,561 | 1,948 |
Non-current derivative liabilities | 0 | 562 |
Total derivative liabilities | 5,561 | 2,510 |
Designated as Hedging Instrument [Member] | ' | ' |
Derivatives, Fair Value [Line Items] | ' | ' |
Current derivative assets | 0 | 13,674 |
Non-current derivative assets | 0 | 0 |
Total derivatives assets | 0 | 13,674 |
Current portion of derivative liabilities | 0 | 1,005 |
Non-current derivative liabilities | 0 | 0 |
Total derivative liabilities | 0 | 1,005 |
Not Designated as Hedging Instrument [Member] | ' | ' |
Derivatives, Fair Value [Line Items] | ' | ' |
Current derivative assets | 515 | 2,878 |
Non-current derivative assets | 0 | 0 |
Total derivatives assets | 515 | 2,878 |
Current portion of derivative liabilities | 5,561 | 943 |
Non-current derivative liabilities | 0 | 562 |
Total derivative liabilities | $5,561 | $1,505 |
Derivatives_Amount_Of_Gain_Or_
Derivatives (Amount Of Gain Or (Loss) Recognized In Accumulated OCI On Derivative) (Details) (USD $) | 12 Months Ended | |||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | ||
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ' | ' | ||
Amount of Gain Recognized in Accumulated OCI on Derivative | $0 | [1] | $7,587 | [1] |
[1] | Net of taxes. |
Derivatives_Gain_Or_Loss_Of_Re
Derivatives (Gain Or Loss Of Reclassified Accumulated Other Comprehensive Income And Recognized Income) (Details) (USD $) | 12 Months Ended | |||||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |||
Derivative Instruments, Gain (Loss) [Line Items] | ' | ' | ' | |||
Amount of Gain or (Loss) Reclassified from Accumulated OCI into Income | $603 | $51,853 | $2,965 | |||
Amount of Gain or (Loss) Recognized in Income | -190 | -2,616 | ' | |||
Commodity Derivatives [Member] | Oil and natural gas revenue [Member] | ' | ' | ' | |||
Derivative Instruments, Gain (Loss) [Line Items] | ' | ' | ' | |||
Amount of Gain or (Loss) Reclassified from Accumulated OCI into Income | 603 | [1] | 51,853 | [1] | 2,965 | [1] |
Commodity Derivatives [Member] | Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness [Member] | ' | ' | ' | |||
Derivative Instruments, Gain (Loss) [Line Items] | ' | ' | ' | |||
Derivative, Gain on Derivative | ($190) | [2] | ($2,616) | [2] | $2,749 | [2] |
[1] | Effective portion of gain (loss). | |||||
[2] | Ineffective portion of gain (loss). |
Derivatives_Effect_Of_Derivati
Derivatives (Effect Of Derivative Instruments Recognized In Statement Of Operations, Not Designated As Hedging Instruments) (Details) (USD $) | 12 Months Ended | |||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | ||
Derivative Instruments, Gain (Loss) [Line Items] | ' | ' | ||
Amount of Gain or (Loss) Recognized in Income on Derivative | ($8,184) | $1,373 | ||
Loss on derivatives not designated as hedging instruments, amount settled during period | -1,764 | 0 | ||
Commodity Contract [Member] | ' | ' | ||
Derivative Instruments, Gain (Loss) [Line Items] | ' | ' | ||
Amount of Gain or (Loss) Recognized in Income on Derivative | ($8,184) | [1] | $1,373 | [1] |
[1] | Amount settled during the period is a loss of $(1,764) and $0, respectively. |
Derivatives_Narrative_Details
Derivatives (Narrative) (Details) (USD $) | 12 Months Ended | |||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | ||
Derivative [Line Items] | ' | ' | ||
Accumulated OCI gain net of tax | $0 | [1] | $7,587 | [1] |
[1] | Net of taxes. |
Fair_Value_Measurements_Recurr
Fair Value Measurements (Recurring Fair Value Measurements) (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ' | ' |
Financial assets (liabilities) | ($5,000) | ' |
Commodity Derivatives [Member] | ' | ' |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ' | ' |
Assets | 515 | 16,552 |
Liabilities | -5,561 | -2,510 |
Financial assets (liabilities) | -5,046 | 14,042 |
Commodity Derivatives [Member] | Level 2 [Member] | ' | ' |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ' | ' |
Assets | 1,978 | 18,555 |
Liabilities | -4,429 | -3,918 |
Financial assets (liabilities) | -2,451 | 14,637 |
Commodity Derivatives [Member] | Level 3 [Member] | ' | ' |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ' | ' |
Assets | 20 | 0 |
Liabilities | -2,615 | -595 |
Financial assets (liabilities) | -2,595 | -595 |
Commodity Derivatives [Member] | Effect of Netting [Member] | ' | ' |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ' | ' |
Assets | -1,483 | -2,003 |
Liabilities | 1,483 | 2,003 |
Financial assets (liabilities) | $0 | $0 |
Fair_Value_Measurements_Reconc
Fair Value Measurements (Reconciliations Of Level 3 Fair Value Measurements) (Details) (Collar [Member], USD $) | 12 Months Ended | |||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | ||
Collar [Member] | ' | ' | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ' | ' | ||
Beginning of period | ($595) | $33,615 | ||
Included in earnings | -2,637 | [1] | 24,484 | [1] |
Included in other comprehensive income (loss) | 0 | -11,641 | ||
Settlements | 637 | -25,129 | ||
Transfers out of Level 3 into Level 2 | 0 | -21,924 | ||
End of period | -2,595 | -595 | ||
Total gains for the period included in earnings attributable to the change in unrealized gain relating to assets still held at end of period | ($2,000) | ($645) | ||
[1] | Commodity sales collars are reported in the consolidated statements of income in oil and gas revenues (for cash flow hedges), and gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net, respectively. |
Fair_Value_Measurements_Schedu
Fair Value Measurements (Schedule Of Quantitative Information About Unobservable Inputs) (Details) (Level 3 [Member], Collar [Member], USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2013 | |
Natural Gas [Member] | ' | |
Derivative assets, Fair Value | ($349) | [1] |
Derivatives assets, Valuation Technique(s) | 'DiscountedB cashB flow | [1] |
Unobservable Input | 'ForwardB commodityB priceB curve | [1] |
Natural Gas [Member] | Minimum [Member] | ' | |
Forward commodity price curve | 0 | |
Natural Gas [Member] | Maximum [Member] | ' | |
Forward commodity price curve | 0.39 | |
Crude Oil [Member] | ' | |
Derivative assets, Fair Value | ($2,246) | [1] |
Derivatives assets, Valuation Technique(s) | 'DiscountedB cashB flow | [1] |
Unobservable Input | 'ForwardB commodityB priceB curve | [1] |
Crude Oil [Member] | Minimum [Member] | ' | |
Forward commodity price curve | 0.2 | |
Crude Oil [Member] | Maximum [Member] | ' | |
Forward commodity price curve | 5.2906 | |
[1] | The commodity contracts detailed in this category include non-exchange-traded natural gas and crude oil collars that are valued based on NYMEX. The forward pricing range represents the low and high price expected to be received within the settlement period. |
Fair_Value_Measurements_Narrat
Fair Value Measurements (Narrative) (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ' | ' |
6.625% senior subordinated notes due 2021, net of unamortized discount of $4.3 million and $4.7 million at December 31, 2013 and 2012, respectively | $645,696,000 | $645,259,000 |
Estimated fair value of long-term debt | $688,200,000 | $687,700,000 |
Accumulated_Other_Comprehensiv2
Accumulated Other Comprehensive Income (Changes in accumulated other comprehensive income) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Beginning of Period: | $7,587 | $19,026 | ($6,851) |
Other comprehensive income before reclassification | -7,349 | 18,635 | 29,384 |
Amounts reclassified from accumulated other comprehensive income | -238 | -30,074 | -3,507 |
New current-period other comprehensive income | -7,587 | -11,439 | 25,877 |
Ending of Period: | $0 | $7,587 | $19,026 |
Accumulated_Other_Comprehensiv3
Accumulated Other Comprehensive Income (Schedule of accumulated other comprehensive income (loss)) (Details) (USD $) | 12 Months Ended | |||||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |||
Amounts reclassified from accumulated other comprehensive income | $603 | $51,853 | $2,965 | |||
Commodity Derivatives [Member] | ' | ' | ' | |||
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, before Tax | 413 | 49,237 | 5,714 | |||
Tax expense | -175 | -19,163 | -2,207 | |||
Total reclassification for the period | 238 | 30,074 | 3,507 | |||
Oil and natural gas revenue [Member] | Commodity Derivatives [Member] | ' | ' | ' | |||
Amounts reclassified from accumulated other comprehensive income | 603 | [1] | 51,853 | [1] | 2,965 | [1] |
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness [Member] | Commodity Derivatives [Member] | ' | ' | ' | |||
Derivative Instruments, Gain Recognized in Income | ($190) | [2] | ($2,616) | [2] | $2,749 | [2] |
[1] | Effective portion of gain (loss). | |||||
[2] | Ineffective portion of gain (loss). |
Commitments_And_Contingencies_
Commitments And Contingencies (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Other Commitments [Line Items] | ' | ' | ' |
Lease expiration date | 1-Sep-17 | ' | ' |
Future minimum rental payments under leases, year one | $8,400,000 | ' | ' |
Future minimum rental payments under leases, year two | 3,400,000 | ' | ' |
Future minimum rental payments under leases, year three | 600,000 | ' | ' |
Future minimum rental payments under leases, year four | 100,000 | ' | ' |
Rent expense incurred | 16,900,000 | 14,000,000 | 8,500,000 |
Repurchase of limited units outstanding | 20.00% | ' | ' |
Repurchase of limited units outstanding amount | 16,000 | 56,000 | 22,000 |
Drilling Equipment [Member] | ' | ' | ' |
Other Commitments [Line Items] | ' | ' | ' |
Purchase Commitment, Remaining Minimum Amount Committed | 11,400,000 | ' | ' |
Gas Gathering and Processing Equipment [Member] | ' | ' | ' |
Other Commitments [Line Items] | ' | ' | ' |
Purchase Commitment, Remaining Minimum Amount Committed | $600,000 | ' | ' |
Industry_Segment_Information_R
Industry Segment Information (Revenue From Different Segments) (Details) (USD $) | 3 Months Ended | 12 Months Ended | ||||||||||||||
Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||||||
Segment Reporting [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Oil and natural gas | ' | ' | ' | ' | ' | ' | ' | ' | $649,718,000 | $567,944,000 | $514,614,000 | |||||
Contract drilling | ' | ' | ' | ' | ' | ' | ' | ' | 479,091,000 | 579,368,000 | 536,872,000 | |||||
Elimination of inter-segment revenue | ' | ' | ' | ' | ' | ' | ' | ' | -64,313,000 | -49,649,000 | -52,221,000 | |||||
Contract drilling net of inter-segment revenue | ' | ' | ' | ' | ' | ' | ' | ' | 414,778,000 | 529,719,000 | 484,651,000 | |||||
Gas gathering and processing | ' | ' | ' | ' | ' | ' | ' | ' | 378,397,000 | 290,773,000 | 284,248,000 | |||||
Elimination of inter-segment revenue | ' | ' | ' | ' | ' | ' | ' | ' | -91,043,000 | -73,313,000 | -76,010,000 | |||||
Gas gathering and processing | ' | ' | ' | ' | ' | ' | ' | ' | 287,354,000 | 217,460,000 | 208,238,000 | |||||
Total revenues | 359,121,000 | 333,776,000 | 340,421,000 | 318,532,000 | 331,582,000 | 321,790,000 | 327,785,000 | 333,966,000 | 1,351,850,000 | 1,315,123,000 | 1,207,503,000 | |||||
Oil and natural gas | ' | ' | ' | ' | ' | ' | ' | ' | 239,219,000 | -77,221,000 | [1] | 199,993,000 | ||||
Contract drilling | ' | ' | ' | ' | ' | ' | ' | ' | 96,304,000 | 159,188,000 | 135,085,000 | |||||
Gas gathering and processing | ' | ' | ' | ' | ' | ' | ' | ' | 10,757,000 | 5,780,000 | [2] | 17,278,000 | ||||
Total operating income | ' | ' | ' | ' | ' | ' | ' | ' | 346,280,000 | [3] | 87,747,000 | [3] | 352,356,000 | [3] | ||
General and administrative expense | ' | ' | ' | ' | ' | ' | ' | ' | -38,323,000 | -33,086,000 | -30,055,000 | |||||
Gain (Loss) on Disposition of Assets | ' | ' | ' | ' | ' | ' | ' | ' | 17,076,000 | 253,000 | -595,000 | |||||
Interest expense, net | ' | ' | ' | ' | ' | ' | ' | ' | -15,015,000 | -14,137,000 | -4,167,000 | |||||
Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net | ' | ' | ' | ' | ' | ' | ' | ' | -8,374,000 | -1,243,000 | 1,702,000 | |||||
Other Income (loss), net | ' | ' | ' | ' | ' | ' | ' | ' | -175,000 | -132,000 | -239,000 | |||||
Income before income taxes | ' | ' | ' | ' | ' | ' | ' | ' | 301,469,000 | 39,402,000 | 319,002,000 | |||||
Oil and natural gas | 2,441,792,000 | ' | ' | ' | 2,214,029,000 | ' | ' | ' | 2,441,792,000 | 2,214,029,000 | 1,820,492,000 | |||||
Contract drilling | 1,042,661,000 | ' | ' | ' | 1,079,736,000 | ' | ' | ' | 1,042,661,000 | 1,079,736,000 | 1,118,666,000 | |||||
Gas gathering and processing | 473,717,000 | ' | ' | ' | 413,708,000 | ' | ' | ' | 473,717,000 | 413,708,000 | 247,763,000 | |||||
Total identifiable assets | 3,958,170,000 | [4] | ' | ' | ' | 3,707,473,000 | [4] | ' | ' | ' | 3,958,170,000 | [4] | 3,707,473,000 | [4] | 3,186,921,000 | [4] |
Corporate assets | 64,220,000 | ' | ' | ' | 53,647,000 | ' | ' | ' | 64,220,000 | 53,647,000 | 69,799,000 | |||||
Total assets | 4,022,390,000 | ' | ' | ' | 3,761,120,000 | ' | ' | ' | 4,022,390,000 | 3,761,120,000 | 3,256,720,000 | |||||
Oil and natural gas | ' | ' | ' | ' | ' | ' | ' | ' | 531,233,000 | [5] | 1,145,337,000 | [5] | 588,158,000 | [5] | ||
Contract drilling | ' | ' | ' | ' | ' | ' | ' | ' | 64,325,000 | 77,520,000 | 162,208,000 | |||||
Gas gathering and processing | ' | ' | ' | ' | ' | ' | ' | ' | 96,085,000 | 183,162,000 | 79,355,000 | |||||
Other | ' | ' | ' | ' | ' | ' | ' | ' | 4,483,000 | [5] | 11,083,000 | [5] | 2,688,000 | [5] | ||
Total capital expenditures | ' | ' | ' | ' | ' | ' | ' | ' | 696,126,000 | 1,417,102,000 | 832,409,000 | |||||
Oil and gas depreciation, depletion, and amortization | ' | ' | ' | ' | ' | ' | ' | ' | 226,498,000 | 211,347,000 | 183,350,000 | |||||
Impairment of Oil and Natural Gas Properties | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 283,606,000 | [1] | 0 | ||||
Contract drilling | ' | ' | ' | ' | ' | ' | ' | ' | 71,194,000 | 81,007,000 | 79,667,000 | |||||
Gas gathering and processing | ' | ' | ' | ' | ' | ' | ' | ' | 33,191,000 | 24,388,000 | [2] | 16,101,000 | ||||
Other | ' | ' | ' | ' | ' | ' | ' | ' | 3,024,000 | 2,279,000 | 1,333,000 | |||||
Total depreciation, depletion, amortization and impairment | ' | ' | ' | ' | ' | ' | ' | ' | 333,907,000 | 602,627,000 | 280,451,000 | |||||
Non-cash write down of our oil and natural gas properties | ' | ' | ' | ' | 167,700,000 | ' | 115,900,000 | ' | ' | ' | ' | |||||
Non-cash write down of our oil and natural gas properties net of tax | ' | ' | ' | ' | 104,400,000 | ' | 72,100,000 | ' | ' | ' | ' | |||||
Impairment of long-lived assets held-for-use | ' | ' | ' | ' | 1,200,000 | ' | ' | ' | 0 | 1,200,000 | 0 | |||||
Reclassified salt water disposal expenditures | ' | ' | ' | ' | ' | ' | ' | ' | ' | $16,988,000 | $8,103,000 | |||||
[1] | In June 2012 and December 2012, due to low 12-month average commodity prices, we incurred non-cash ceiling test write downs of our oil and natural gas properties of $115.9 million pre-tax ($72.1 million net of tax) and $167.7 million pre-tax ($104.4 million net of tax), respectively. | |||||||||||||||
[2] | Depreciation, depletion, amortization, and impairment for gas gathering and processing includes a $1.2 million write down of our Erick system. | |||||||||||||||
[3] | Operating income is total operating revenues less operating expenses, depreciation, depletion, amortization, and impairment and does not include general corporate expenses, (gain) loss on disposition of assets, gain (loss) on non-designated hedges and hedge ineffectiveness, interest expense, other income (loss), or income taxes. | |||||||||||||||
[4] | Identifiable assets are those used in Unitbs operations in each industry segment. Corporate assets are principally cash and cash equivalents, short-term investments, corporate leasehold improvements, furniture and equipment. | |||||||||||||||
[5] | Reclassified salt water disposal capital expenditures out of other and into oil and natural gas of $16,988 and $8,103 for 2012 and 2011, respectively. |
Selected_Quarterly_Financial_I2
Selected Quarterly Financial Information (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||||||||||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||||||||
Selected Quarterly Financial Information [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Revenues | $359,121 | $333,776 | $340,421 | $318,532 | $331,582 | $321,790 | $327,785 | $333,966 | $1,351,850 | $1,315,123 | $1,207,503 | ||||||||
Gross profit | 92,692 | [1] | 79,082 | [1] | 90,823 | [1] | 83,683 | [1] | -81,833 | [1] | 95,921 | [1] | -22,253 | [1] | 95,912 | [1] | ' | ' | ' |
Net income | $51,301 | $34,232 | $59,007 | $40,206 | ($56,547) | $46,586 | ($19,302) | $52,439 | $184,746 | $23,176 | $195,867 | ||||||||
Basic | $1.06 | $0.71 | $1.22 | $0.84 | ($1.18) | [2] | $0.97 | [2] | ($0.40) | [2] | $1.10 | [2] | $3.83 | $0.48 | $4.11 | ||||
Diluted | $1.05 | $0.70 | $1.22 | $0.83 | ($1.18) | $0.97 | ($0.40) | $1.09 | $3.80 | $0.48 | $4.08 | ||||||||
[1] | Gross profit excludes general and administrative expense, interest expense, (gain) loss on disposition of assets, gain (loss) on non-designated hedges and hedge ineffectiveness, income taxes, and other income (loss). | ||||||||||||||||||
[2] | Due to the effect of rounding the basic earnings per share for the yearbs four quarters does not equal annual earnings per share. |
Supplemental_Oil_And_Gas_Discl2
Supplemental Oil And Gas Disclosures (Schedule Of Capitalized Costs And Costs Incurred On Oil And Gas Properties) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Supplemental Oil and Gas Disclosures [Abstract] | ' | ' | ' |
Proved properties | $4,235,712 | $3,822,381 | $3,302,032 |
Unproved properties not being amortized | 545,588 | 521,659 | 185,632 |
Capitalized costs gross | 4,781,300 | 4,344,040 | 3,487,664 |
Accumulated depreciation, depletion, amortization and impairment | -2,439,458 | -2,216,787 | -1,724,312 |
Net capitalized costs | 2,341,842 | 2,127,253 | 1,763,352 |
Unproved properties acquired | 76,304 | 420,467 | 70,999 |
Proved properties acquired | 0 | 225,669 | 50,013 |
Exploration | 33,373 | 46,467 | 43,836 |
Development | 424,314 | 390,649 | 391,862 |
Asset retirement obligation | -17,951 | 45,097 | 23,345 |
Total costs incurred | $516,040 | $1,128,349 | $580,055 |
Supplemental_Oil_And_Gas_Discl3
Supplemental Oil And Gas Disclosures (Schedule Of The Oil And Natural Gas Property Costs Not Being Amortized) (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2010 |
In Thousands, unless otherwise specified | ||||
Supplemental Oil and Gas Disclosures [Abstract] | ' | ' | ' | ' |
Unproved properties acquired and wells in progress | $92,929 | $412,623 | $32,492 | $7,544 |
Unproved properties acquired, total | $545,588 | ' | ' | ' |
Supplemental_Oil_And_Gas_Discl4
Supplemental Oil And Gas Disclosures (Results Of Operations For Producing Activities) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Supplemental Oil and Gas Disclosures [Abstract] | ' | ' | ' |
Revenues | $633,792 | $557,003 | $505,450 |
Production costs | -162,822 | -131,389 | -115,400 |
Depreciation, depletion, amortization and impairment | -222,672 | -492,475 | -181,960 |
Results of operations, income before income taxes | 248,298 | -66,861 | 208,090 |
Income tax (expense) benefit | -96,091 | 27,533 | -80,323 |
Results of operations for producing activities (excluding corporate overhead and financing costs) | $152,207 | ($39,328) | $127,767 |
Supplemental_Oil_And_Gas_Discl5
Supplemental Oil And Gas Disclosures (Schedule Of Proved Developed And Undeveloped Oil And Gas Reserve Quantities) (Details) | 12 Months Ended | |||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||
bbl | bbl | bbl | ||
Oil [Member] (bbls) | ' | ' | ' | |
Reserve Quantities [Line Items] | ' | ' | ' | |
Beginning of year | 21,998,000 | 20,255,000 | 17,494,000 | |
Revision of previous estimates | -2,113,000 | -1,747,000 | 374,000 | [1] |
Extensions and discoveries | 4,678,000 | 5,014,000 | 3,477,000 | |
Infill reserves in existing proved fields | 2,299,000 | 4,196,000 | 1,229,000 | |
Purchases of minerals in place | 0 | 2,830,000 | 192,000 | |
Production | -3,360,000 | -3,279,000 | -2,511,000 | |
Sales | -1,737,000 | -5,271,000 | 0 | |
End of Year | 21,765,000 | 21,998,000 | 20,255,000 | |
Beginning of year, developed | 16,441,000 | 15,618,000 | 12,773,000 | |
End of year, developed | 15,594,000 | 16,441,000 | 15,618,000 | |
Beginning of year, undeveloped | 5,557,000 | 4,637,000 | 4,721,000 | |
End of year, undeveloped | 6,171,000 | 5,557,000 | 4,637,000 | |
Natural Gas Liquids [Member] (bbls) | ' | ' | ' | |
Reserve Quantities [Line Items] | ' | ' | ' | |
Beginning of year | 35,166,000 | 22,087,000 | 16,117,000 | |
Revision of previous estimates | 836,000 | -2,682,000 | 2,112,000 | [1] |
Extensions and discoveries | 7,273,000 | 4,819,000 | 3,924,000 | |
Infill reserves in existing proved fields | 1,945,000 | 3,018,000 | 1,780,000 | |
Purchases of minerals in place | 0 | 11,098,000 | 393,000 | |
Production | -3,914,000 | -2,796,000 | -2,239,000 | |
Sales | -101,000 | -378,000 | 0 | |
End of Year | 41,205,000 | 35,166,000 | 22,087,000 | |
Beginning of year, developed | 25,657,000 | 16,649,000 | 12,088,000 | |
End of year, developed | 30,437,000 | 25,657,000 | 16,649,000 | |
Beginning of year, undeveloped | 9,509,000 | 5,438,000 | 4,029,000 | |
End of year, undeveloped | 10,768,000 | 9,509,000 | 5,438,000 | |
Natural Gas [Member] (Mcf) | ' | ' | ' | |
Reserve Quantities [Line Items] | ' | ' | ' | |
Beginning of year | 555,647,000 | 442,135,000 | 420,486,000 | |
Revision of previous estimates | 2,421,000 | -55,110,000 | -30,510,000 | [1] |
Extensions and discoveries | 68,611,000 | 54,761,000 | 39,836,000 | |
Infill reserves in existing proved fields | 21,573,000 | 25,057,000 | 15,592,000 | |
Purchases of minerals in place | 11,000 | 141,494,000 | 40,835,000 | |
Production | -56,757,000 | -48,930,000 | -44,104,000 | |
Sales | -9,722,000 | -3,760,000 | 0 | |
End of Year | 581,784,000 | 555,647,000 | 442,135,000 | |
Beginning of year, developed | 452,844,000 | 372,311,000 | 346,928,000 | |
End of year, developed | 464,234,000 | 452,844,000 | 372,311,000 | |
Beginning of year, undeveloped | 102,803,000 | 69,824,000 | 73,558,000 | |
End of year, undeveloped | 117,550,000 | 102,803,000 | 69,824,000 | |
[1] | Natural gas revisions of previous estimates decreased primarily due to a decline in natural gas prices. |
Supplemental_Oil_And_Gas_Discl6
Supplemental Oil And Gas Disclosures (Standardized Measure Of Discounted Future Cash Flows Relating To Proved Reserves Disclosure) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Supplemental Oil and Gas Disclosures [Abstract] | ' | ' | ' |
Future net cash flows relating to proved oil and gas reserves future cash inflows | $5,573,119 | $4,522,351 | $4,583,629 |
Future production costs | -1,734,985 | -1,405,773 | -1,277,856 |
Future development costs | -571,170 | -431,673 | -340,992 |
Future income tax expenses | -1,044,608 | -762,519 | -952,736 |
Future net cash flows | 2,222,356 | 1,922,386 | 2,012,045 |
10% annual discount for estimated timing of cash flows | -996,380 | -842,430 | -924,136 |
Standardized measure of discounted future net cash flows relating to proved oil, NGLs and natural gas reserves | $1,225,976 | $1,079,956 | $1,087,909 |
Percentage of annual discount for estimated timing of cash flows | 10.00% | 10.00% | 10.00% |
Supplemental_Oil_And_Gas_Discl7
Supplemental Oil And Gas Disclosures (Schedule Of Principal Sources Of Changes In Standardized Measure Of Discounted Future Net Cash Flows) (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Reserve Quantities [Line Items] | ' | ' | ' |
Sales and transfers of oil and natural gas produced, net of production costs | ($470,970) | ($425,626) | ($389,339) |
Net changes in prices and production costs | 188,826 | -321,099 | 115,852 |
Revisions in quantity estimates and changes in production timing | -10,650 | -148,648 | -38,336 |
Extensions, discoveries and improved recovery, less related costs | 426,377 | 432,058 | 401,134 |
Changes in estimated future development costs | 26,629 | 51,587 | 37,742 |
Previously estimated cost incurred during the period | 96,457 | 104,377 | 45,327 |
Purchases of minerals in place | 9 | 283,774 | 58,567 |
Sales of minerals in place | -43,435 | -112,359 | -29 |
Accretion of discount | 147,579 | 157,842 | 128,492 |
Net change in income taxes | -170,091 | 94,678 | -60,675 |
Other-net | -44,711 | -124,537 | -65,912 |
Net change | 146,020 | -7,953 | 232,823 |
Beginning of year | 1,079,956 | 1,087,909 | 855,086 |
End of year | $1,225,976 | $1,079,956 | $1,087,909 |
Supplemental_Oil_And_Gas_Discl8
Supplemental Oil And Gas Disclosures Supplemental Oil and Gas Disclosures (Narrative) (Details) | 12 Months Ended |
Dec. 31, 2013 | |
Oil [Member] (bbls) | ' |
Average Sales Prices | 96.94 |
Natural Gas Liquids [Member] (bbls) | ' |
Average Sales Prices | 41.03 |
Natural Gas [Member] (Mcf) | ' |
Average Sales Prices | 3.67 |
Schedule_II_Valuation_And_Qual1
Schedule II - Valuation And Qualifying Accounts And Reserves (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Valuation and Qualifying Accounts [Abstract] | ' | ' | ' |
Balance at Beginning of Period | $5,343 | $5,343 | $5,083 |
Additions Charged to Costs And Expenses | 0 | 90 | 260 |
Deductions And Net Write-Offs | -1 | -90 | 0 |
Balance at End of Period | $5,342 | $5,343 | $5,343 |