Oil And Natural Gas Properties	9 Months Ended
Sep. 30, 2012
Oil And Natural Gas Properties [Abstract]
Oil And Natural Gas Properties	Oil and natural gas properties The accounting for, and disclosure of, oil and natural gas producing activities require that we choose between two GAAP alternatives; the full cost method or the successful efforts method. We use the full cost method of accounting, which involves capitalizing all intangible drilling costs, lease and well equipment and exploration and development costs incurred plus acquired proved and unproved leaseholds. Once we incur costs, they are recorded in the depletable pool of proved properties or in unproved properties, collectively, the full cost pool. Our unproved property costs, which include unproved oil and natural gas properties, properties under development, and major development projects, collectively totaled $546.5 million and $667.3 million as of September 30, 2012 and December 31, 2011, respectively, and are not subject to depletion. We review our unproved oil and natural gas property costs on a quarterly basis to assess for impairment and transfer unproved costs to proved properties as a result of extensions or discoveries from drilling operations or determination that no Proved Reserves are attributable to such costs. We expect these costs to be evaluated in one to seven years and transferred to the depletable portion of the full cost pool during that time. We have impaired approximately $11.7 million of undeveloped properties during the first nine months of 2012. When we acquire significant amounts of undeveloped acreage, we capitalize interest on the acquisition costs in accordance with Financial Accounting Standards Board, or FASB, Accounting Standards Codification, or ASC, Subtopic 835-20, Capitalization of Interest. We capitalize interest upon identification and development of shale resource opportunities in the Haynesville and Marcellus areas. When the unproved property costs are moved to proved developed and undeveloped oil and natural gas properties, or the properties are sold, we cease capitalizing interest. We calculate depletion using the unit-of-production method. Under this method, the sum of the full cost pool, excluding the book value of unproved properties, and all estimated future development costs are divided by the total estimated quantities of Proved Reserves. This rate is applied to our total production for the quarter, and the appropriate expense is recorded. We capitalize the portion of general and administrative costs, including share-based compensation, that is attributable to our exploration, exploitation and development activities. Sales, dispositions and other oil and natural gas property retirements are accounted for as adjustments to the full cost pool, with no recognition of gain or loss, unless the disposition would significantly alter the amortization rate and/or the relationship between capitalized costs and Proved Reserves. Pursuant to Rule 4-10(c)(4) of Regulation S-X, at the end of each quarterly period, companies that use the full cost method of accounting for their oil and natural gas properties must compute a limitation on capitalized costs, or ceiling test. The ceiling test involves comparing the net book value of the full cost pool, after taxes, to the full cost ceiling limitation defined below. In the event the full cost ceiling is less than the full cost pool, we must record a ceiling test write-down of our oil and natural gas properties to the value of the full cost ceiling. The full cost ceiling limitation is computed as the sum of the present value of estimated future net revenues from our Proved Reserves by applying average price as prescribed by the SEC Release No. 33-8995, less estimated future expenditures (based on current costs) to develop and produce the Proved Reserves, discounted at 10%, plus the cost of properties not being amortized and the lower of cost or estimated fair value of unproved properties included in the costs being amortized, net of income tax effects. The ceiling test is computed using the simple average spot price for the trailing twelve month period using the first day of each month. For the period ended September 30, 2012, the trailing twelve month reference price was $94.97 per Bbl for the West Texas Intermediate oil at Cushing, Oklahoma, $49.62 per Bbl for natural gas liquids based on a percentage of the NYMEX oil price, and $2.83 per Mmbtu for natural gas at Henry Hub. Each of the reference prices for oil and natural gas are further adjusted for quality factors and regional differentials to derive estimated future net revenues. Under full cost accounting rules, any ceiling test write-downs of oil and natural gas properties may not be reversed in subsequent periods. Since we do not designate our derivative financial instruments as hedges, we are not allowed to use the impacts of the derivative financial instruments in our ceiling test computations. As a result, decreases in commodity prices which contribute to ceiling test write-downs may be offset by mark-to-market gains which are not reflected in our ceiling test results. For the three and nine months ended September 30, 2012, we recognized a pre-tax ceiling test write-down of $318.0 million and $1,022.7 million, respectively, to our proved oil and natural gas properties. There were no ceiling test write-downs for the three and nine months ended September 30, 2011. The ceiling test calculation is based upon estimates of Proved Reserves. There are numerous uncertainties inherent in estimating quantities of Proved Reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

Oil and natural gas properties

The accounting for, and disclosure of, oil and natural gas producing activities require that we choose between two GAAP alternatives; the full cost method or the successful efforts method. We use the full cost method of accounting, which involves capitalizing all intangible drilling costs, lease and well equipment and exploration and development costs incurred plus acquired proved and unproved leaseholds. Once we incur costs, they are recorded in the depletable pool of proved properties or in unproved properties, collectively, the full cost pool. Our unproved property costs, which include unproved oil and natural gas properties, properties under development, and major development projects, collectively totaled $546.5 million and $667.3 million as of September 30, 2012 and December 31, 2011, respectively, and are not subject to depletion. We review our unproved oil and natural gas property costs on a quarterly basis to assess for impairment and transfer unproved costs to proved properties as a result of extensions or discoveries from drilling operations or determination that no Proved Reserves are attributable to such costs. We expect these costs to be evaluated in one to seven years and transferred to the depletable portion of the full cost pool during that time. We have impaired approximately $11.7 million of undeveloped properties during the first nine months of 2012.

When we acquire significant amounts of undeveloped acreage, we capitalize interest on the acquisition costs in accordance with Financial Accounting Standards Board, or FASB, Accounting Standards Codification, or ASC, Subtopic 835-20, Capitalization of Interest. We capitalize interest upon identification and development of shale resource opportunities in the Haynesville and Marcellus areas. When the unproved property costs are moved to proved developed and undeveloped oil and natural gas properties, or the properties are sold, we cease capitalizing interest.

We calculate depletion using the unit-of-production method. Under this method, the sum of the full cost pool, excluding the book value of unproved properties, and all estimated future development costs are divided by the total estimated quantities of Proved Reserves. This rate is applied to our total production for the quarter, and the appropriate expense is recorded. We capitalize the portion of general and administrative costs, including share-based compensation, that is attributable to our exploration, exploitation and development activities.

Sales, dispositions and other oil and natural gas property retirements are accounted for as adjustments to the full cost pool, with no recognition of gain or loss, unless the disposition would significantly alter the amortization rate and/or the relationship between capitalized costs and Proved Reserves.

Pursuant to Rule 4-10(c)(4) of Regulation S-X, at the end of each quarterly period, companies that use the full cost method of accounting for their oil and natural gas properties must compute a limitation on capitalized costs, or ceiling test. The ceiling test involves comparing the net book value of the full cost pool, after taxes, to the full cost ceiling limitation defined below. In the event the full cost ceiling is less than the full cost pool, we must record a ceiling test write-down of our oil and natural gas properties to the value of the full cost ceiling. The full cost ceiling limitation is computed as the sum of the present value of estimated future net revenues from our Proved Reserves by applying average price as prescribed by the SEC Release No. 33-8995, less estimated future expenditures (based on current costs) to develop and produce the Proved Reserves, discounted at 10%, plus the cost of properties not being amortized and the lower of cost or estimated fair value of unproved properties included in the costs being amortized, net of income tax effects.

The ceiling test is computed using the simple average spot price for the trailing twelve month period using the first day of each month. For the period ended September 30, 2012, the trailing twelve month reference price was $94.97 per Bbl for the West Texas Intermediate oil at Cushing, Oklahoma, $49.62 per Bbl for natural gas liquids based on a percentage of the NYMEX oil price, and $2.83 per Mmbtu for natural gas at Henry Hub. Each of the reference prices for oil and natural gas are further adjusted for quality factors and regional differentials to derive estimated future net revenues. Under full cost accounting rules, any ceiling test write-downs of oil and natural gas properties may not be reversed in subsequent periods. Since we do not designate our derivative financial instruments as hedges, we are not allowed to use the impacts of the derivative financial instruments in our ceiling test computations. As a result, decreases in commodity prices which contribute to ceiling test write-downs may be offset by mark-to-market gains which are not reflected in our ceiling test results. For the three and nine months ended September 30, 2012, we recognized a pre-tax ceiling test write-down of $318.0 million and $1,022.7 million, respectively, to our proved oil and natural gas properties. There were no ceiling test write-downs for the three and nine months ended September 30, 2011.

The ceiling test calculation is based upon estimates of Proved Reserves. There are numerous uncertainties inherent in estimating quantities of Proved Reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.