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Significant Accounting Policies (Policy)
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Dec. 31, 2011
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| Significant Accounting Policies [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Operations |
Operations W&T Offshore, Inc. and subsidiaries, referred to herein as "W&T" or the "Company," is an independent oil and natural gas producer focused primarily in the Gulf of Mexico and, more recently, onshore Texas. The Company is active in the acquisition, exploration and development of oil and natural gas properties. |
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| Basis Of Presentation |
Basis of Presentation Our consolidated financial statements include the accounts of W&T Offshore, Inc. and its majority owned subsidiaries. All significant intercompany transactions and amounts have been eliminated for all years presented. |
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| Reclassifications |
Reclassifications Certain reclassifications have been made to prior periods' financial statements to conform to the current presentation. In Note 13, certain state income tax items were previously reported separately and are now combined with other items due to being immaterial. In Note 22, reserve information related to oil and natural gas liquids ("NGLs") is reported separately due to the increase in NGLs as a percent of total reserves and these had been combined in prior periods. The historical information was modified to report oil and NGLs separately for comparability to the current year's information. |
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| Use Of Estimates |
Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States ("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, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves. Actual results could differ from those estimates. |
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| Fiscal Year |
Fiscal Year Our fiscal year ends on December 31. |
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| Cash Equivalents |
Cash Equivalents We consider all highly liquid investments purchased with original or remaining maturities of three months or less at the date of purchase to be cash equivalents. |
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| Revenue Recognition |
Revenue Recognition We recognize oil and natural gas revenues based on the quantities of our production sold to purchasers under short-term contracts (less than 12 months) at market prices when delivery has occurred, title has transferred and collectability is reasonably assured. We use the sales method of accounting for oil and natural gas revenues from properties with joint ownership. Under this method, we record oil and natural gas revenues based upon physical deliveries to our customers, which can be different from our net revenue ownership interest in field production. These differences create imbalances that we recognize as a liability only when the estimated remaining recoverable reserves of a property will not be sufficient to enable the under-produced party to recoup its entitled share through production. We do not record receivables for those properties in which the Company has taken less than its ownership share of production. At December 31, 2011 and 2010, $6.5 million and $6.5 million, respectively, were included in current liabilities related to natural gas imbalances. |
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| Concentration Of Credit Risk |
Concentration of Credit Risk Our customers are primarily large integrated oil and natural gas companies and large financial institutions. Our production is sold utilizing month-to-month contracts that are based on bid prices. We also have receivables from joint interest owners on properties we operate and we may have the ability to withhold future revenue disbursements to recover amounts due us. We attempt to minimize our credit risk exposure to purchasers of our oil and natural gas, joint interest owners, derivative counterparties and other third-party entities through formal credit policies, monitoring procedures, and letters of credit or guaranties when considered necessary. We historically have not had any significant problems collecting our receivables except in rare circumstances. Accordingly, we do not maintain an allowance for doubtful accounts. The following identifies customers from whom we derived 10% or more of receipts from sales of oil and natural gas.
We believe that the loss of any of the customers above would not result in a material adverse effect on our ability to market future oil and natural gas production as replacement customers could be obtained in a relatively short period of time on terms, conditions and pricing substantially similar to those currently existing. |
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| Properties And Equipment |
Properties and Equipment We use the full-cost method of accounting for oil and natural gas properties and equipment. Under this method, all costs associated with the acquisition, exploration, development and abandonment of oil and natural gas properties are capitalized. Acquisition costs include costs incurred to purchase, lease or otherwise acquire property. Exploration costs include costs of drilling exploratory wells and external geological and geophysical costs, which mainly consist of seismic costs. Development costs include the cost of drilling development wells and costs of completions, platforms, facilities and pipelines. Costs associated with production, certain geological and geophysical costs and general and administrative costs are expensed in the period incurred. Oil and natural gas properties and equipment include costs of unproved properties. The cost of unproved properties related to significant acquisitions are excluded from the amortization base until it is determined that proved reserves can be assigned to such properties or until such time as the Company has made an evaluation that impairment has occurred. The costs of drilling exploratory dry holes are included in the amortization base immediately upon determination that such wells are non-commercial. We capitalize interest on expenditures made in connection with the exploration and development of unproved properties that are excluded from the amortization base. Interest is capitalized only for the period that exploration and development activities are in progress. We capitalized $9.9 million, $5.4 million and $6.7 million of interest expense during the years 2011, 2010, and 2009, respectively.
Oil and natural gas properties included in the amortization base are amortized using the units-of-production method based on production and estimates of proved reserve quantities. In addition to costs associated with evaluated properties and capitalized asset retirement obligations ("ARO"), the amortization base includes estimated future development costs to be incurred in developing proved reserves as well as estimated plugging and abandonment costs, net of salvage value, related to developing proved reserves. These additional costs related to developing proved reserves are not recorded as liabilities on the balance sheet. Sales of proved and unproved oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas. Under the full cost method of accounting, we are required to periodically perform a "ceiling test," which determines a limit on the book value of our oil and natural gas properties. If the net capitalized cost of oil and natural gas properties (including capitalized ARO), net of related deferred income taxes, exceeds the present value of estimated future net revenues from proved reserves discounted at 10%, plus the cost of unproved oil and natural gas properties not being amortized, plus the lower of cost or estimated fair value of unproved oil and natural gas properties included in the amortization base, net of related tax effects, the excess is charged to expense and reflected as additional accumulated depreciation, depletion and amortization. Any such write downs are not recoverable or reversible in future periods. Estimated future net revenues used in the ceiling test as of December 31, 2011, 2010 and 2009 are based on the unweighted average of first-day-of-the-month commodity prices over the period January through December for that year and exclude future cash outflows related to capitalized ARO and include future development costs and ARO related to wells to be drilled. For the ceiling test as of March 31, 2009, commodity prices were based on the end-of-the-period prices using guidance effective for that reporting period. We recorded a ceiling test impairment in 2009 of $218.9 million primarily as a result of a decline in natural gas prices as of March 31, 2009. Declines in oil and natural gas prices after December 31, 2011 may require us to record additional ceiling test impairments in the future. We did not have a ceiling test impairment during the years 2011 and 2010, respectively. Furniture, fixtures and non-oil and natural gas property and equipment are depreciated using the straight-line method based on the estimated useful lives of the respective assets, generally ranging from five to seven years. Leasehold improvements are amortized over the shorter of their economic lives or the lease term. Repairs and maintenance costs are expensed in the period incurred. |
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| Asset Retirement Obligations |
Asset Retirement Obligations Pursuant to the Asset Retirement and Environmental Obligations topic of the Financial Accounting Standards Board ("FASB") Accounting Standards Codification (the "Codification"), we are required to record a separate liability for the present value of our ARO, with an offsetting increase to the related oil and natural gas properties on our balance sheet. We have significant obligations to remove our platforms, pipelines, facilities and equipment and restore the land or seabed at the end of oil and natural gas production operations. These obligations are primarily associated with plugging and abandoning wells, removing pipelines, removing and disposing of offshore platforms and site clean up. Estimating the future restoration and removal cost is difficult and requires us to make estimates and judgments because the removal obligations may be many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations, which can substantially affect our estimates of these future costs from period to period. For additional information, refer to Note 5. |
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| Oil And Natural Gas Reserve Information |
Oil and Natural Gas Reserve Information In January 2010, the FASB issued certain amendments to the Extractive Activities – Oil and Gas topic of the Codification that updated and aligned the FASB's reserve estimation and disclosure requirements for oil and natural gas companies with the reserve estimation and disclosure requirements that were adopted by the Securities and Exchange Commission ("SEC") in December 2008. The FASB's amendments and the SEC's new requirements became effective for annual reporting periods ending on or after December 31, 2009. Collectively, the new rules permit the use of new technologies in the determination of proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. Other definitions and terms were revised, including the definition of proved reserves which was changed to indicate, among other things, that commencing with year-end 2009 entities must use the unweighted average of first-day-of-the-month commodity prices over the preceding 12-month period, rather than end-of-period commodity prices, when estimating quantities of proved reserves. Similarly, the prices used to calculate the standardized measure of discounted future cash flows and prices used in the ceiling test for impairment have been changed from end-of-period commodity prices to the 12-month average commodity prices. Also, because it is our policy to use end-of-period reserves in the determination of quarterly depletion, our depreciation, depletion, amortization and accretion expense for the fourth quarter of 2009, each of the quarters of 2010 and each of the quarters of 2011 were calculated using proved reserves that were determined in accordance with the new rules. Additionally, entities must separately disclose information about reserve quantities and certain financial statement amounts for geographic areas that represent 15% or more of proved reserves, and equity-method investees should be included in determining whether an entity has significant oil and gas producing activities. Another significant provision of the new rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years. Refer to Note 22 for additional information about our proved reserves and the impact of the new reserve estimation and disclosure requirements. |
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| Derivative Financial Instruments |
Derivative Financial Instruments Our market risk exposure relates primarily to commodity prices and interest rates. From time to time, we use various derivative instruments to manage our exposure to commodity price risk from sales of oil and natural gas and interest rate risk from floating interest rates on our credit facility. Our derivative instruments currently consist of commodity swap and option contracts for oil. We do not enter into derivative instruments for speculative trading purposes. We account for derivative contracts in accordance with the Derivatives and Hedging topic of the Codification, which requires each derivative to be recorded on the balance sheet as an asset or a liability at its fair value. Changes in a derivative's fair value are required to be recognized currently in earnings unless specific hedge accounting and documentation criteria are met at the time the derivative contract is entered into. We have elected not to designate our commodity derivatives as hedging instruments, therefore all changes in fair value are recognized in earnings. |
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| Fair Value Of Financial Instruments |
Fair Value of Financial Instruments We include fair value information in the notes to our consolidated financial statements when the fair value of our financial instruments is different from the book value. We believe that the book value of our cash and cash equivalents, receivables, accounts payable and accrued liabilities materially approximates fair value due to the short-term nature and the terms of these instruments. We believe that the book value of our restricted deposits approximates fair value as deposits are in cash or short-term investments. |
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| Income Taxes |
Income Taxes We use the liability method of accounting for income taxes in accordance with the Income Taxes topic of the Codification. Under this method, deferred tax assets and liabilities are determined by applying tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the financial statements. In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized. We recognize uncertain tax positions in our financial statements when it is more likely than not that we will sustain the benefit taken or expected to be taken. When applicable, we recognize interest and penalties related to uncertain tax positions in income tax expense. |
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| Deferred Financing Costs |
Deferred Financing Costs Debt issuance costs associated with our revolving loan facility are amortized using the straight-line method over the scheduled maturity of the debt. Debt issuance costs associated with all other debt are deferred and amortized over the scheduled maturity of the debt utilizing the effective interest method. |
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| Share-Based Compensation |
Share-Based Compensation In accordance with the Compensation – Stock Compensation topic of the Codification, compensation cost for share-based payments to employees and non-employee directors is based on the fair value of the equity instrument on the date of grant and is recognized over the period during which the recipient is required to provide service in exchange for the award. |
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| Earnings (Loss) Per Share |
Earnings (Loss) Per Share In accordance with the Earnings Per Share topic of the Codification, unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of earnings per share under the two-class method. For additional information, refer to Note 14. |
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