Note 2 — Summary of Significant Accounting Policies

Use of Estimates

The preparation of financial statements in accordance with U.S. generally accepted accounting principles and pursuant to the rules and regulations of the SEC requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and disclosure of contingent assets and liabilities in the financial statements. Actual results could differ from those estimates.

Cash and Cash Equivalents

Cash and cash equivalents primarily consist of cash on deposit and investments in funds with original maturities of three months or less, stated at market value.

Restricted Cash

Restricted cash relates to an escrow account for ATP-IP, discussed below, which holds cash in excess of monthly partnership distributions and operating needs. Also, the ATP Titan Facility, discussed below, requires us to maintain in a restricted account a minimum $10.0 million cash balance (classified as noncurrent on the Consolidated Balance Sheet) plus additional amounts based on production at the Telemark Hub to be used for the quarterly debt service of the ATP Titan Facility. Occasionally, we also receive cash which is restricted for use to retire certain assets or perform other operations.

Oil and Gas Properties

We account for our oil and gas property costs using the successful efforts accounting method. Under the successful efforts method, lease acquisition costs and intangible drilling and development costs on successful wells and development dry holes are capitalized. Costs of drilling exploratory wells are initially capitalized, but charged to expense if and when a well is determined to be unsuccessful.

Capitalized proved property acquisition costs are depleted on the unit-of-production method on the basis of total estimated units of proved reserves. Capitalized costs relating to producing properties are depleted on the unit-of-production method on the basis of total estimated units of proved developed reserves. When significant development costs (such as the cost of an offshore production platform) are incurred in connection with a planned group of development wells before all of the planned wells have been drilled, it is occasionally necessary to exclude a portion of those development costs in determining the unit-of-production depletion rate until the additional development wells are drilled. However, in no case are future development costs anticipated in computing our depletion rate. Estimated dismantlement, restoration and abandonment costs and estimated residual salvage values are taken into account in determining depletion provisions. Our ATP Titan and ATP Innovator floating platforms are included in oil and gas properties and depreciated straight line over 40 and 25 years, respectively since they can be relocated to other fields once existing production is depleted. Expenditures for geological and geophysical testing costs are generally charged to expense unless the costs can be specifically attributed to mapping a proved reservoir and determining the optimal placement for future developmental well locations. Expenditures for repairs and maintenance are charged to expense as incurred; renewals and betterments are capitalized. The costs and related accumulated depreciation, depletion, and amortization of properties sold or otherwise retired are eliminated from the accounts, and gains or losses on disposition are reflected in the statements of operations.

We perform impairment analysis whenever events or changes in circumstances indicate that an asset's carrying amount may not be recoverable. To determine if a depletable unit is impaired, we compare the carrying value of the depletable unit to the undiscounted future net cash flows by applying management's estimates of future oil and gas prices to the estimated future production of oil and gas reserves over the economic life of the property and deducting future costs. Future net cash flows are based upon reservoir engineers' estimates of proved reserves. In addition, other factors such as probable and possible reserves are taken into consideration when justified by economic conditions and actual or planned drilling or other development activities. For a property determined to be impaired, an impairment loss equal to the difference between the carrying value and the estimated fair value of the impaired property will be recognized. Fair value, on a depletable unit basis, is estimated to be the present value of the aforementioned expected future net cash flows. Unproved properties are assessed periodically to determine whether they have been impaired. An impairment allowance is provided on an unproved property when we determine that the property will not be developed, but no later than lease expiration. Any impairment charge incurred is recorded in accumulated depletion, depreciation, impairment and amortization to reduce our basis in the asset. Each part of these calculations is subject to a large degree of judgment, including estimated reserves, future net cash flows and fair value.

We recorded impairments during the years ended December 31, 2011, 2010 and 2009 totaling $53.0 million, $42.4 million and $44.6 million, respectively, on certain proved properties in the Gulf of Mexico. We also recorded impairments totaling $1.2 million and $14.9 million during 2011 and 2010, respectively on certain proved properties in the North Sea. The 2011 and 2010 impairments were primarily due to updated performance history. The 2009 impairments were primarily a result of reduced commodity prices and unfavorable operating performance.

Impairments of unproved properties were $3.4 million, $6.0 million and $1.2 million in 2011, 2010 and 2009, respectively, primarily related to surrendered leases in the Gulf of Mexico.

Management's assumptions used in calculating oil and gas reserves or regarding the future net cash flows or fair value of our properties are subject to change in the future. Any change could cause impairment expense to be recorded, impacting our net income or loss and our basis in the related asset. Any change in reserves directly impacts our estimate of future cash flows from the property, as well as the property's fair value. Additionally, as commodity price forecasts change, so too will the estimate of future net cash flows and the fair value estimates.

As of December 31, 2011, there were $9.7 million of capitalized exploratory well costs (suspended well costs) related to two wells in the North Sea which were still being evaluated, and for which drilling was completed in 2010. We are still performing our work program and completing studies that will allow us to calculate estimates of gas in place and potential reserves for Kilmar, part of our Tors development. In 2011, the only change in the suspended well costs was for additions of $0.2 million.

Asset Retirement Obligation

We recognize liabilities associated with the eventual retirement of tangible long-lived assets, upon the acquisition, construction and development of the assets. We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Changes in estimates on fully depleted properties are charged directly to loss on abandonment.

Shortages or an increase in cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our abandonment operations, which could have a material adverse effect on our business, financial condition and results of operations. Increased drilling activity in the Gulf of Mexico and the North Sea decreases the availability of offshore rigs and associated equipment. In periods of increased drilling activity in the Gulf of Mexico and the North Sea, we may experience increases in associated costs, including those related to drilling rigs, equipment, supplies and personnel and the services and products of other vendors to the industry. These costs may increase further and necessary equipment and services may not be available to us at economical prices.

We recognize (i) depletion expense on the additional capitalized asset retirement costs; (ii) accretion expense as the present value of the future asset retirement obligation increases with the passage of time, and; (iii) the impact, if any, of changes in estimates of the liability. The following table sets forth a reconciliation of the beginning and ending asset retirement obligation (in thousands):


	December 31,
	2011			2010			2009
Asset retirement obligation, beginning of year	$	166,858		$	150,199		$	132,108
Liabilities incurred		14,457			5,960			16,220
Liabilities settled		(26,725	)		(15,362	)		(9,603	)
Property dispositions		—			(242	)		(292	)
Accretion expense		15,000			13,827			11,676
Changes in estimates		(1,073	)		12,476			90

Total asset retirement obligation, end of year		168,517			166,858			150,199
Less current portion		(52,536	)		(43,386	)		(43,418	)

Total long-term asset retirement obligation, end of year	$	115,981		$	123,472		$	106,781

During 2011, 2010 and 2009, we recognized loss on abandonment of $3.9 million, $4.8 million and $2.9 million, respectively. These amounts are primarily the result of actual abandonment operations in the Gulf of Mexico requiring more work than originally estimated.

Limited Partnership

On March 6, 2009, along with GE Energy Financial Services ("GE"), we formed ATP-IP to own the ATP Innovator, the floating production facility that currently serves our Mississippi Canyon Block 711 Gomez Hub properties. We contributed the ATP Innovator in exchange for a 49% subordinated limited partner interest, a 2% general partner interest and cash. GE paid $150.0 million to ATP-IP for a 49% Class A limited partner interest. We remain the operator and continue to hold a 100% working interest in the Gomez field and its oil and gas reserves. The transaction was effective June 1, 2008 and allows us exclusive use of the ATP Innovator during the term of the Platform Use Agreement ("PUA"), which is expected to be the economic life of the Gomez Hub reserves.

From an operational standpoint, during the term of the PUA, we are obligated to pay to ATP-IP a per unit fee for all hydrocarbons processed by the ATP Innovator, subject to a minimum throughput fee of $53,000 per day. Such minimum fees, if applicable, can be recovered by us in future periods whenever fees owed during a month exceed the minimum due. We may also be subject to a minimum fee of $53,000 per day for up to 180 days under certain circumstances, including if we fail to provide the minimum notification period before the Gomez field ceases production. We made no other performance guarantees to GE and the ultimate fees earned by ATP-IP beyond the minimum fees will be determined by the volumes of hydrocarbons processed through the facility. During the term of the PUA, we are responsible for all of the operating costs and periodic maintenance of the ATP Innovator. ATP-IP pays us a monthly fee for certain administrative services we provide to the partnership.

We have entered a period under the agreements when all of the cash distributions from the partnership are paid to the Class A limited partner until such time as they have achieved the return of their invested capital plus a specified return. Once those amounts have been received by the Class A limited partner, all cash distributions will be made to the general partner and subordinated limited partner (ATP's interests) until specified amounts have been received. At the conclusion of the special distribution periods, all partners will again share in distributions proportionately according to their ownership in the partnership.

For financial reporting purposes, because we are the general partner of the partnership, we consolidate ATP-IP, along with three wholly owned limited liability companies (the "LLCs") we created to own our interests in ATP-IP. The GE Class A limited partner interest is reflected as a noncontrolling interest in our consolidated financial statements. Under the provisions of our limited partnership agreement with ATP-IP, we could be required to repurchase the Class A limited partner interest if certain change of control events were to occur. If a change of control were to become probable in a future period, we would be required to adjust the carrying amount of the redeemable noncontrolling interest to its redemption amount, to the extent it differed from the carrying amount, at the time the change of control was deemed to be probable. We do not currently believe a change of control is probable.

Capitalized Interest

Interest costs during the construction phase of certain long-term assets are capitalized and amortized over the related assets' estimated useful lives. Interest expense capitalized during the last three years and the properties to which it relates is set forth in the following table (in thousands):


	Year Ended December 31,
	2011		2010		2009
ATP Titan – Telemark (Gulf of Mexico)	$	—	$	40,400	$	102,200
Octabuoy – Cheviot (North Sea)		29,246		12,900		7,900

Total capitalized interest	$	29,246	$	53,300	$	110,100

Deferred Financing Costs

Costs incurred in connection with the issuance of long-term debt and other obligations are capitalized and amortized to interest expense over the term of the related agreement, using the effective interest method.

Environmental Liabilities

Environmental liabilities are recognized when the expenditures are considered probable and can be reasonably estimated. Measurement of liabilities is based on currently enacted laws and regulations, existing technology and undiscounted site-specific costs. Generally, such recognition would coincide with a commitment to a formal plan of action. We have no accruals for such liabilities at December 31, 2011 or 2010.

Revenue Recognition

We use the sales method of accounting for oil and natural gas revenues. Under this method, revenues are recognized based on actual volumes of oil and gas sold to purchasers. The volumes sold may differ from the volumes to which we are entitled based on our interests in the properties. Differences between volumes sold and entitled volumes create oil and gas imbalances which are generally reflected as adjustments to reported proved oil and gas reserves and future cash flows in our supplemental oil and gas disclosures. If our excess takes of oil or natural gas exceed our estimated remaining proved reserves for a property, an oil or natural gas imbalance liability is recorded in the consolidated balance sheet.

Drilling Interruption Costs

Drilling interruption costs represent the costs we have incurred as a result of the deepwater drilling moratoriums and subsequent drilling permit delays caused by the April 2010 Deepwater Horizon incident in the Gulf of Mexico. During 2011, we incurred $19.7 million stand-by costs related to drilling operations at our Telemark and Gomez Hubs. During 2010 a side-track well operation in 7,000 feet of water was interrupted when the moratorium was imposed and work on that project stopped, resulting in the early termination of a drilling contract. In the course of obtaining a full release from our obligations under the contract, we incurred net costs of $8.7 million. Additionally, because the necessary deepwater drilling permits were not issued, drilling interruption costs during 2010 also include $14.9 million of stand-by costs related to drilling operations at our Telemark and Gomez Hubs.

Concentration of Credit Risk

We extend credit, primarily in the form of uncollateralized oil and gas sales and joint interest owners' receivables, to various companies in the oil and gas industry, which results in concentrations of credit risk. Concentrations of credit risk may be affected by changes in economic or other conditions within our industry and may accordingly impact our overall credit risk. However, we believe that the risk of these unsecured receivables is mitigated by the size, reputation, and nature of the companies to which we extend credit.

Major Customers

Historically, we have sold our oil and natural gas production to a relatively small number of purchasers. We are not dependent upon, or confined to, any one purchaser or small group of purchasers. Due to the nature of oil and natural gas markets and because oil and natural gas are commodities and there are numerous purchasers in the areas in which we sell production, we do not believe the loss of a single purchaser, or a few purchasers, would materially affect our ability to sell our production.

For the year ended December 31, 2011, revenues from two purchasers accounted for 67% and 20%, respectively, of oil and gas production revenues. For the year ended December 31, 2010, revenues from four purchasers accounted for 65%, 12%, 11% and 5%, respectively, of oil and gas production revenues. For the year ended December 31, 2009, revenues from four purchasers accounted for 39%, 33%, 13% and 7%, respectively, of oil and gas production revenues. A substantial portion of our oil and gas production revenues in the North Sea are from one customer.

Translation of Foreign Currencies

The local currency is the functional currency for our foreign subsidiaries, and as such, assets and liabilities are translated into U.S. dollars at year-end exchange rates. Income and expense items are translated at average exchange rates during the year. The gains or losses resulting from such translations are deferred and included in accumulated other comprehensive income as a separate component of shareholders' equity. Gains and losses arising from transactions denominated in a currency other than the functional currency of a particular entity are included in net income. At December 31, 2011, accumulated other comprehensive loss consisted of $106.4 million of loss related to cumulative foreign currency translation adjustments.

Insurance Recoveries

When realized, insurance recoveries under our loss of production income policy are reported as other revenues in the consolidated statements of operations and in cash flows from operating activities in the consolidated statements of cash flows. During 2009 insurance recoveries of $13.7 million were related to disruptions caused by Hurricane Ike in 2008.

Income Taxes

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences or benefits attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and for operating loss and tax credit carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes that enactment date. A valuation allowance is recorded to reduce deferred tax assets to an amount that management believes is more likely than not to be realized in future years.

Stock-based Compensation

We recognize stock-based compensation expense as vesting of the stock award occurs. Generally, restricted stock awards vest over three years and common stock option awards vest evenly over four years.

Fair Value of Financial Instruments

For cash and cash equivalents, receivables and payables, the carrying amounts approximate fair value because of the short maturity of these instruments.

Derivative Instruments

We utilize derivative instruments and fixed-price forward sales contracts with respect to a portion of our expected production in order to manage our exposure to oil and natural gas price volatility. These instruments expose us to risk of financial loss if:

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production is less than expected for forward sales contracts;

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the counterparty to the derivative instrument defaults on its contract obligations; or

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there is an adverse change in the expected differential between the underlying price in the derivative instrument and the actual prices received for our production at the physical sales point.

Our results of operations may be negatively impacted in the future by our derivative instruments and fixed-price forward sales contracts as these instruments may limit any benefit we would otherwise receive from increases in the prices for oil and natural gas.

We primarily utilize fixed-price physical forward contracts, price swaps, prepaid swaps, price collars and put and call options which are generally placed with major financial institutions or with counterparties of high credit quality in order to minimize our credit risks. The oil and natural gas reference prices of these commodity derivative contracts are based upon oil and natural gas market exchanges which have a high degree of historical correlation with the actual prices we receive. All derivative instruments are recorded on the balance sheet at fair value with changes in fair value recorded as a component of derivative income (expense) in our consolidated statement of operations. Cash settlements of our derivative instruments are classified as operating cash flows unless the derivative contains a significant financing element at contract inception, in which case these cash settlements are classified as financing cash flows in the accompanying Consolidated Statements of Cash Flows.

From time to time, we utilize foreign currency and interest rate derivative instruments to mitigate risks associated with our foreign operations and borrowings, respectively.

Recently Issued Accounting Pronouncements

In May 2011, the FASB issued guidance which will result in common fair value measurement and disclosure requirements in GAAP and International Financial Reporting Standards. For public entities, the guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. We expect to adopt the provisions for the quarter ended March 31, 2012 and we do not anticipate that this will have a material impact on our financial position or results of operations.

In June 2011, the FASB issued guidance which eliminates the option to present components of other comprehensive income as part of the statement of changes in shareholders' equity and requires that all nonowner changes in shareholders' equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. We have adopted the provisions of this standard at December 31, 2011 and it has not had a material impact on our financial statements.

In December 2011, the FASB deferred the provisions that relate to the presentation of reclassification adjustments. For public entities, the guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011.

In December 2011, the FASB issued guidance related to disclosure of information about offsetting and related arrangements for financial instruments and derivative instruments recognized as assets and liabilities. The guidance is effective for fiscal years and interim periods within those years, beginning after January 1, 2013. We expect to adopt the provisions for the quarter ending March 31, 2013 and we do not anticipate that this will have a material impact on our financial position or results of operations.