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Oil And Gas Properties | 12 Months Ended
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Dec. 31, 2012
Oil And Gas Properties [Abstract] |
Oil And Gas Properties | Note 3 — Oil and Gas Properties Discontinued Operations In December 2012, we announced a definitive agreement for the sale of ERT. On February 6, 2013, we sold ERT for $620 million plus contingent consideration in the form of overriding royalty interests in the Wang well and certain other future exploration prospects. As a result, we have presented the assets and liabilities included in the sale of ERT and the historical operating results of our former Oil and Gas segment as discontinued operations in the accompanying consolidated financial statements. Oil and Gas Significant Accounting Policies Restricted Cash We had restricted cash totaling $28.4 million at December 31, 2012 and $33.7 million at December 31, 2011, all of which consisted of funds required to be escrowed to cover the future asset retirement obligations associated with the South Marsh Island Block 130 field. These escrowed funds were included in the sale of ERT in February 2013. These amounts are reflected in “Non-current assets of discontinued operations” in the accompanying consolidated balance sheets. Inventories We had oil and gas inventory totaling $11.9 million at December 31, 2012 and $16.4 million at December 31, 2011. This inventory primarily represents the cost of supplies to be used in our oil and gas drilling and development activities, primarily drilling pipe, tubulars and certain wellhead equipment, including two subsea trees. Our inventories are stated at the lower of cost or market value and we utilize the average cost method of maintaining our inventory. There were no charges to reduce inventory to its lower cost or market value in 2012. In December 2011, we agreed to sell approximately $4.6 million of our drilling pipe inventory for $2.5 million. In connection with this sale, we recorded a $2.1 million loss to reduce its value to its expected realized value at December 31, 2011. Property and Equipment Depreciation and Depletion. Depletion expense for oil and gas properties is determined on a field-by-field basis using the units-of-production method, with depletion rates for leasehold acquisition costs based on estimated total remaining proved reserves. Depletion rates for well and related facility costs are based on estimated total remaining proved developed reserves associated with each individual field. The depletion rates are changed whenever there is an indication of the need for a revision, but at a minimum, are evaluated annually. Any such revisions are accounted for prospectively as a change in accounting estimate. Depletion was discontinued when we announced the sale of ERT. We depreciate our other property and equipment over its estimated useful life on a straight-line basis. Oil and Gas Properties. All of our former oil and gas properties are located in the United States offshore in the Gulf of Mexico. We followed the successful efforts method of accounting for our oil and natural gas exploration and development activities. Under this method, the costs of successful wells and leases containing productive reserves are capitalized. Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized and are reflected as a reduction of investing cash flows in the accompanying consolidated statements of cash flows. Proved Properties. Proved oil and gas properties are assessed for possible impairment at least annually or when events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. An impairment loss is recognized as a result of a triggering event and when the estimated undiscounted future cash flows from a property are less than the carrying value. If impairment is indicated, an impairment charge is recorded equal to the difference between the carrying amount and the fair value of the property based on discounted future cash flows. In the discounted cash flow method, estimated future cash flows are based on prices based on published forward commodity price curves as of the date of the estimate and management’s estimates of future operating and development costs and a risk adjusted discount rate. See “Impairments” below for additional information regarding our oil and gas property impairments. Unproved Properties. Unproved properties are also periodically assessed for impairment based on exploration and drilling efforts to date on the individual prospects and lease expiration dates. The amounts and timing of impairment provisions are also impacted by management’s assessment of the results of exploration activities, availability of funds for future activities and the current and projected political climate in areas in which we operate. We recorded impairments to unproved oil and gas properties totaling $0.8 million in 2012, $8.3 million in 2011 and $6.4 million in 2010. Such impairments were included in exploration expenses. Exploratory Costs. The costs of drilling an exploratory well are capitalized as uncompleted or “suspended” wells pending the determination of whether the well has found proved reserves. If proved reserves are found these costs remain capitalized; if no reserves are found the capitalized costs are charged to exploration expenses. See “Exploration and Other” below for additional information regarding our exploration costs. Accounting for Asset Retirement Obligations We are required to record our asset retirement obligations at fair value in the period such obligations are incurred. The associated asset retirement costs are capitalized as part of the carrying cost of the asset. Our asset retirement obligations consisted of estimated costs for dismantlement, removal, site reclamation and similar activities associated with our former oil and gas properties. An asset retirement obligation and the related asset retirement cost are recorded when an asset is first constructed or purchased. The asset retirement cost is determined and discounted to present value using a credit-adjusted risk-free rate. After the initial recording, the liability is increased for the passage of time, with the increase being reflected as accretion expense, which is a component of our depreciation, depletion and amortization expense. The following table describes the changes in our asset retirement obligations for ERT (both current and long-term) for the years ended December 31, 2012 and 2011 (in thousands):
|  | 2012 |  | 2011 |
Asset retirement obligations at January 1, | $ | 227,090 | $ | 222,653 |
Liability incurred during the period |  | 3,664 |  | 4,982 |
Liability settled during the period |  | (105,160) |  | (37,769) |
Other revisions in estimated cash flows (1) |  | 62,834 |  | 22,345 |
Accretion expense (included in depreciation and amortization) |  | 12,550 |  | 14,879 |
Asset retirement obligations at December 31, | $ | 200,978 | $ | 227,090 |
(1) The increased amount of these liabilities includes revisions to both non-producing and producing oil and gas properties. Increases to liabilities associated with non-producing fields ($12.4 million and $22.5 million during the year ended December 31, 2012 and 2011, respectively) include corresponding abandonment expense charges to cost of sales within our consolidated statements of operations while changes in estimates for producing properties are recorded as an increase to property and equipment carrying costs of the related oil and gas properties within our consolidated balance sheets. Revenue Recognition Revenues from sales of crude oil and natural gas are recorded when delivery to the customer has occurred, title has transferred, prices are fixed and determinable and collection is reasonably assured. This occurs when production has been delivered to a pipeline or when a barge lifting has occurred. We may have an interest with other producers in certain properties. In this case, the entitlements method is used to account for sales of production. Under the entitlements method, we may receive more or less than our entitled share of production. If more than our entitled share of production is received, the imbalance is treated as a liability. If less than our entitled share is received, the imbalance is recorded as an asset. As of December 31, 2012, the net imbalance was a $1.0 million asset and was included in “Current assets of discontinued operations” ($4.0 million) and “Current liabilities of discontinued operations” ($3.0 million). Derivative Instruments and Hedging Activities As previously noted, our risk management activities often involve the use of derivative financial instruments to hedge the impact of market risk exposure, including those related to the market prices of oil and natural gas. To reduce the impact of these risks on earnings and increase the predictability of our cash flows, from time to time we have entered into certain derivative contracts, including costless collars and swaps for a portion of our oil and gas production. These derivative contracts are reflected in our balance sheet at fair value. See Note 2 for additional disclosure regarding our accounting for derivative contracts. The fair value of our oil and gas derivative contracts reflects our best estimate and is based upon exchange or over-the-counter quotations whenever they are available. Quoted valuations may not be available due to location differences or terms that extend beyond the period for which quotations are available. Where quotes are not available, we utilize other valuation techniques or models to estimate market values. These modeling techniques require us to make estimates of future prices, price correlation and market volatility and liquidity. Our actual results may differ from our estimates, and these differences can be positive or negative. Prior to the announcement of the sale of ERT in December 2012, all of the effect of our oil and gas hedging contracts were reflected as a component of our discontinued operations in the accompanying consolidated financial statements. As a result of the announcement of the sale of ERT, we de-designated all of our remaining oil and natural gas derivative contracts as hedging instruments. Because the hedging contracts were not part of the sale of ERT, the effect post announcement of the sale are included within continuing operations in the accompanying consolidated financial statements. At December 31, 2012, all of our commodity derivative contracts were subject to mark-to-market adjustments to reflect the changes in their fair values. In connection with the de-designation of these derivative contracts as hedging instruments, we were required to recognize amounts previously recorded in accumulated other comprehensive income (loss) and related deferred taxes into earnings. At December 31, 2012, we recorded losses of approximately $10.5 million ($6.8 million net of tax) to reflect the mark-to-market adjustments for changes in the fair values of the oil and gas commodity derivative contracts. See Note 17 for additional information regarding our commodity derivative contracts. Impairments Proved property impairment charges are reflected as reductions in cost of sales in our discontinued operations. We had no oil and gas proved property impairment charges in 2012. In December 2012, following the announcement of our intention to sell ERT, we recorded a $138.6 million impairment charge to reduce our carrying value of ERT to its estimated fair value less costs to sell as determined by the negotiated sales price for ERT. In 2011, we recor ded $90.9 million of oil and gas property impairment charges associated with 11 of our Gulf of Mexico oil and gas fields. These impairment charges were primarily related to changes in the field economics of the affected oil and gas properties. During 2011, the price of natural gas decreased significantly. When natural gas prices decr ease this often affects the assumptions regarding future development of certain fields as some or all of those proved reserves may become uneconomic to develop or produce. Our impairment charges also reflect end of field life factors, including premature depletion or capital allocation decisions, primarily those affecting third party operated fields. In 2010, we recorded $176.7 million of oil and gas property impairment charges, including $4.1 million related to our one U.K. oil and gas property which is reflected in continuing operations as it was not included in the sale of ERT. A total of 21 of our former Gulf of Mexico oil and gas properties were affected by impairment charges in 2010. The impairment charges associated with producing fields totaled $172.6 million, which primarily reflected reduction in our estimates of proved reserves (Note 16). Results of Discontinued Operations The following summarized financial information relates to ERT, which is reported as “Income (loss) from discontinued operations, net of tax” in the accompanying consolidated statements of operations:
|  | Year Ended December 31, |
|  | 2012 |  | 2011 |  | 2010 |
Revenues | $ | 557,231 | $ | 696,607 | $ | 425,369 |
Costs: |  |  |  |  |  |  |
Production (lifting) costs |  | 164,663 |  | 176,269 |  | 131,156 |
Hurricane repair expense |  | 662 |  | (4,838) |  | 4,699 |
Exploration expenses (1) |  | 3,295 |  | 10,914 |  | 8,276 |
Depreciation, depletion, amortization and accretion |  | 158,284 |  | 219,915 |  | 235,243 |
Proved property impairment and abandonment charges (2) |  | 151,045 |  | 113,439 |  | 177,138 |
(Gain) loss on sale of oil and gas properties |  | 1,714 |  | (4,531) |  | (287) |
Non-hedge gain on commodity derivative contracts |  | (5,550) |  | - |  | (1,088) |
Selling, general and administrative expenses |  | 17,823 |  | 12,951 |  | 15,966 |
Net interest expense and other (3) |  | 28,191 |  | 25,558 |  | 19,687 |
Total costs |  | 520,127 |  | 549,677 |  | 590,790 |
Pretax income (loss) from discontinued operations |  | 37,104 |  | 146,930 |  | (165,421) |
Income tax provision (benefit) |  | 13,420 |  | 51,709 |  | (58,764) |
Income (loss) from discontinued operations, net of tax | $ | 23,684 | $ | 95,221 | $ | (106,657) |
(1) See “Exploration and Other” below for additional information related to the components of our exploration costs, including impairment charges for expiring unproved leases. (2) Includes $138.6 million recorded to reduce our carrying value of ERT to its estimated fair value less costs to sell. (3) Net interest expense of $27.7 million, $25.2 million and $19.7 million for the years ended December 31, 2012, 2011 and 2010, respectively, was allocated to ERT primarily based on interest associated with indebtedness directly attributed to the substantial acquisition made by our oil and gas subsidiary in 2006. This includes interest related to debt required to be paid upon the disposition of ERT. Included in the accompanying consolidated balance sheets are the following major classes of assets and liabilities associated with ERT as of December 31, 2012 and 2011:
|  | 2012 |  | 2011 |
Cash and cash equivalents | $ | 2 | $ | 2 |
Accounts receivable |  | 63,762 |  | 90,882 |
Other current assets |  | 20,236 |  | 28,037 |
Current assets of discontinued operations |  | 84,000 |  | 118,921 |
Property and equipment, net |  | 787,852 |  | 871,658 |
Restricted cash and other |  | 28,375 |  | 33,741 |
Non-current assets of discontinued operations | $ | 816,227 | $ | 905,399 |
Accounts payable | $ | 110,569 | $ | 73,124 |
Accrued liabilities |  | 18,217 |  | 27,968 |
Current asset retirement obligations |  | 53,741 |  | 65,883 |
Current liabilities of discontinued operations |  | 182,527 |  | 166,975 |
Asset retirement obligations |  | 147,237 |  | 161,208 |
Non-current liabilities of discontinued operations | $ | 147,237 | $ | 161,208 |
Exploration and Other As of December 31, 2012, we had $8.2 million of capitalized costs associated with ongoing exploration and/or appraisal activities. The following table provides a detail of our capitalized exploratory project costs at December 31, 2012 and 2011 (in thousands):
|  | 2012 |  | 2011 |
Wang (1) | $ | - | $ | 3,096 |
Danny II |  | - |  | 2,619 |
T-6 (1) |  | 8,122 |  | - |
Other |  | 125 |  | 125 |
Total | $ | 8,247 | $ | 5,840 |
(1) Both of these wells are located within the Phoenix field at Green Canyon Block 237. The following table reflects net changes in exploratory well costs during the years ended December 31, 2012, 2011 and 2010 (in thousands):
|  | 2012 |  | 2011 |  | 2010 |
Beginning balance at January 1, | $ | 5,840 | $ | 3,252 | $ | 3,059 |
Additions pending the determination of proved reserves |  | 135,311 |  | 2,513 |  | (944) |
Reclassifications to proved properties |  | (132,959) |  | 5 |  | 713 |
Charged to dry hole expense |  | 55 |  | 70 |  | 424 |
Ending balance at December 31, | $ | 8,247 | $ | 5,840 | $ | 3,252 |
Further, the following table details the components of exploration expenses for the years ended December 31, 2012, 2011 and 2010 (in thousands):
|  | Year Ended December 31, |
|  | 2012 |  | 2011 |  | 2010 |
Delay rental and geological and geophysical costs | $ | 2,517 | $ | 2,650 | $ | 2,306 |
Impairment of unproved properties |  | 833 |  | 8,334 |  | 6,394 |
Dry hole expense |  | (55) |  | (70) |  | (424) |
Total exploration expense | $ | 3,295 | $ | 10,914 | $ | 8,276 |
Our oil and gas activities in the United States are regulated by the federal government and require significant third-party involvement, such as refinery processing and pipeline transportation. We record revenue from our offshore properties net of royalties paid to the Office of Natural Resources Revenue. Royalty fees paid totaled approximately $78.1 million, $85.4 million and $37.2 million for the years ended December 31, 2012, 2011 and 2010, respectively. United Kingdom Property Since 2006, we have maintained an ownership interest in the Camelot field, located offshore in the North Sea. In 2007, we sold half of our 100% working interest in Camelot to a third party with whom we agreed to jointly pursue future development and production of the field. In February 2010, we acquired this third party thereby assuming its obligations, most notably the asset retirement obligation, related to its 50% working interest in the field. In connection with the valuation of assets acquired and liabilities assumed in this acquisition, we reassessed the fair value associated with our original 50% interest in the field. Based on these evaluations, it was concluded that an impairment of the property was required based on the unlikely probability of our spending the future capital necessary to further develop the Camelot field. In 2010, we recorded $4.1 million of impairment charges to fully impair the property and $0.9 million of charges to expense to increase the asset retirement obligation for the Camelot field. Our plan was to fully abandon the field in 2012 in accordance with applicable regulations in the United Kingdom. Modifications to U.K. regulations governing such operations required us to reassess our existing abandonment plan and cost estimates in 2011. The results of this review concluded that the scope of work to be performed in the abandoning of the wells in the field would be significantly expanded and as a result our cost estimates significantly increased. Based on our abandonment plan, we increased the asset retirement obligation by recording a corresponding $20.0 million charge to expense. At December 31, 2011, the remaining asset retirement obligation for the Camelot field was $27.3 million. During 2012, we recorded $15.5 million of additional charges to expense to reflect further increases in our estimated costs to complete our abandonment activities at Camelot, including the removal of certain environmentally sensitive materials. The abandonment of the Camelot field is substantially complete. At December 31, 2012, the recorded asset retirement obligation for the Camelot field was $2.9 million. The operating results and financial position associated with our U.K. property do not qualify for discontinued operations accounting treatment as this property was not classified as held for sale and thus they are reflected as continuing operations in our consolidated financial statements for all periods presented.

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