Note 2 — Summary of Significant Accounting Policies

Principles of Consolidation

Our consolidated financial statements include the accounts of majority-owned subsidiaries. The equity method is used to account for investments in affiliates in which we do not have majority ownership, but have the ability to exert significant influence. We consolidated our former subsidiary CDI until June 10, 2009, at which time our ownership in CDI was reduced to less than 50%. We recorded our proportional share of CDI's results under the equity method of accounting until we sold substantially all of our ownership interest in CDI on September 23, 2009. We sold our remaining ownership interest in CDI in 2011. We also account for our Deepwater Gateway, Independence Hub and Australian joint venture investments under the equity method of accounting. Noncontrolling interests represent the minority shareholders' proportionate share of the equity in CDI until we deconsolidated its results in June 2009 and Kommandor LLC. All material intercompany accounts and transactions have been eliminated. Certain reclassifications were made to previously reported amounts in the consolidated financial statements and notes thereto to make them consistent with the current presentation format.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States 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.

Cash and Cash Equivalents

Cash and cash equivalents are highly liquid financial instruments with original maturities of three months or less. They are carried at cost plus accrued interest, which approximates fair value.

Statement of Cash Flow Information

As of December 31, 2011 and 2010, we had $33.7 million and $35.3 million, respectively, of restricted cash included in other assets (Note 6), all of which related to funds required to be escrowed to cover the future asset retirement obligations associated with our South Marsh Island Block 130 field. We have fully satisfied the requirements under the escrow agreement. We have used a small portion of these escrowed funds to pay for the initial reclamation activities at the South Marsh Island Block 130 field. Reclamation activities at the field will occur over many years and will be funded with these escrowed amounts. These amounts are reflected in other assets, net in the accompanying consolidated balance sheets.

The following table provides supplemental cash flow information for the periods stated (in thousands):


		Year Ended December 31,
		2011		2010		2009

Interest paid, net of interest capitalized	$	81,000	$	68,534	$	48,313
Income taxes paid	$	11,216	$	10,071	$	106,480

Non-cash investing activities for the years ended December 31, 2011, 2010 and 2009 included $26.1 million, $21.9 million and $48.9 million, respectively, related to accruals of capital expenditures. The accruals have been reflected in the accompanying consolidated balance sheets as an increase in property and equipment and accounts payable.

Accounts Receivable and Allowance for Uncollectible Accounts

Accounts receivable are stated at the historical carrying amount net of write-offs and allowance for uncollectible accounts. The amount of our net accounts receivable approximates fair value. We establish an allowance for uncollectible accounts receivable based on historical experience and any specific customer collection issues that we have identified. Uncollectible accounts receivable are written off when a settlement is reached for an amount that is less than the outstanding historical balance or when we have determined that the balance will not be collected (Note 18).

Inventories

We had inventory totaling $18.1 million at December 31, 2011 and $25.3 million at December 31, 2010. Our 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. These costs will be partially reimbursed by third party participants in the wells supplied with these materials. Our inventories are stated at the lower of cost or market value and we utilize the average cost method of maintaining our inventory. 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. This sale transaction closed in early January 2012. There were no charges to reduce inventory to its lower cost or market value in 2010. For the year ended December 31, 2009, we recorded an aggregate of $1.8 million of charges to cost of sales to reduce our inventory to its lower of cost or market value at various times throughout the year.

Property and Equipment

Overview. Property and equipment is recorded at cost. The following is a summary of the gross components of property and equipment (dollars in thousands):

	Estimated Useful Life		2011		2010

ROVs/Vessels	10to 30 years	$	1,616,772	$	1,573,471
Oil and gas leases and related equipment	Units-of-Production		2,574,693		2,747,895
Machinery, equipment, buildings and leasehold improvements	5to 30 years		199,599		164,711
Total property and equipment		$	4,391,064	$	4,486,077

The cost of repairs and maintenance is charged to expense as incurred, while the cost of improvements is capitalized. Total repair and maintenance expenses totaled $40.1 million, $35.0 million and $35.6 million for the years ended December 31, 2011, 2010 and 2009, respectively. Included in machinery, equipment, buildings and leasehold improvements were $18.1 million and $17.8 million of capitalized software costs at December 31, 2011 and 2010, respectively. The total amount charged to expense related to the amortization of these software costs was $2.6 million during each of the years ended December 31, 2011, 2010 and 2009.

Assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value and reported as an impairment (a component of cost of sales) in the periods in which the determination of the impairment is made. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. Our marine vessels are assessed on a vessel by vessel basis, while our ROVs are grouped and assessed by asset class. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants or based on a multiple of operating cash flow validated with historical market transactions of similar assets where possible. The expected future cash flows used for impairment reviews and related fair value calculations are based on judgmental assessments operating costs, project margins and capital project decisions, considering all available information at the date of review. If an impairment has occurred, we recognize a loss for the difference between the carrying amount and the fair value of the asset.

In 2011, in an acknowledgment of our declining operating results in Australia and in association with the reorganization of our Australian well operations business, we conducted an impairment assessment of its subsea well intervention equipment, which resulted in a $6.6 million charge to reduce the carrying value of such well intervention equipment to its then estimated fair value. During 2009, we recorded an aggregate $1.3 million charge to reduce the carrying value of certain specific ROV equipment to its fair value of $6.1 million. There were no such impairments related to our vessels during 2011, 2010 and 2009. See Note 5 for disclosure related to the impairment of our oil and gas properties.

Assets are classified as held for sale when we have a formalized plan for disposal and those assets meet the held for sale criteria. Assets classified as held for sale are included in other current assets. There were no assets meeting the requirements to be classified as assets held for sale at December 31, 2011 and 2010.

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. We depreciate our other property and equipment over its estimated useful life on a straight-line basis.

Oil and Gas Properties. All of our oil and gas properties are in the United States located offshore in the Gulf of Mexico. We follow 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 flow in the accompanying consolidated statements of cash flows. Costs incurred relating to unsuccessful exploratory wells are expensed in the period when the drilling is determined to be unsuccessful and are included as a reconciling item to net income (loss) in operating activities in the accompanying consolidated statements of cash flows.

Proved Properties. We assess proved oil and gas properties for possible impairment at least annually or when events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. We recognize an impairment loss 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 an impairment is indicated, the cash flows are discounted at an approximate rate that market participants would be willing to pay for similar types of assets and compared to the carrying value for determining the amount of the impairment loss to record. 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 Note 5 for additional information regarding our oil and gas property impairments.

Unproved Properties. We also periodically assess unproved properties for impairment based on exploration and drilling efforts to date on the individual prospects and lease expiration dates. 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 also impact the amounts and timing of impairment provisions. We recorded impairments to unproved oil and gas properties totaling $8.3 million in 2011, $6.4 million in 2010 and $20.1 million in 2009. Such impairments were included in exploration expenses for our Oil and Gas business segment.

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 expense. At times, it may be determined that an exploratory well may have found hydrocarbons at the time drilling is completed, but it may not be possible to classify the reserves at that time. In this case, we may continue to capitalize the drilling costs as an uncompleted, or "suspended," well beyond one year if we can justify its completion as a producing well and we are making sufficient progress assessing the reserves and the economic and operating viability of the project. If reserves are not ultimately deemed proved or economically viable, the well is considered impaired and its costs, net of any salvage value, are charged to expense. See Note 5 for additional information regarding our exploration costs.

Properties Acquired from Business Combinations. Properties acquired through business combinations are recorded at their fair value. In determining the fair value of the proved and unproved properties, we prepare estimates of oil and gas reserves. We estimate future prices to apply to the estimated reserve quantities acquired and the estimated future operating and development costs to arrive at our estimates of future net revenues. For the fair value assigned to proved reserves, the future net revenues are discounted using a market-based weighted average cost of capital rate determined to be appropriate at the time of the acquisition. To compensate for inherent risks of estimating and valuing unproved reserves, probable and possible reserves are reduced by additional risk weighting factors.

Capitalized Interest. Interest from external borrowings is capitalized on major projects until the assets are ready for their intended use. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful life of the asset in the same manner as the underlying asset. The total of our interest expense capitalized during each of the three years ended December 31, 2011, 2010 and 2009 was $1.3 million, $12.5 million and $48.1 million, respectively.

Equity Investments

We periodically review our equity investments in Deepwater Gateway, Independence Hub and our Australian joint venture for impairment. Under the equity method of accounting, an impairment loss would be recorded whenever the fair value of an equity investment is determined to be below its carrying amount and the reduction is considered to be other than temporary. In judging "other than temporary," we would consider the length of time and extent to which the fair value of the investment has been less than the carrying amount of the equity investment, the near-term and long-term operating and financial prospects of the equity company and our longer-term intent of retaining the investment in the entity. See Notes 3 and 9 for discussion of other than temporary loss amounts recorded in both 2011 and 2010.

Goodwill and Other Intangible Assets

We are required to perform an annual impairment analysis of goodwill. We elected November 1 to be our annual impairment assessment date for goodwill. However, we could be required to evaluate the recoverability of goodwill prior to the annual assessment date if we experience disruption to the business, unexpected significant declines in operating results, divestiture of a significant component of the business, emergence of unanticipated competition, loss of key personnel or a sustained decline in market capitalization. Our goodwill impairment test involves a comparison of the fair value with our carrying amount. The fair value is determined using discounted cash flows and other market-related valuation models. At the time of our annual assessment of goodwill on November 1, 2011 we had two reporting units with goodwill and our impairment analysis.

In 2011, we adopted the new accounting standards intended to simplify goodwill impairment testing by giving an entity the option to first assess certain qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If an entity determines it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then performing the currently prescribed two-step impairment test is unnecessary. Early adoption is permitted, including for annual and interim goodwill impairment tests performed, if an entity's financial statements for the most recent annual or interim period have not yet been issued. The Company early adopted this standard for its annual goodwill impairment tests in 2011.

All of our remaining goodwill at December 31, 2011 ($62.2 million) was associated with our Contracting Services segment. The reporting units that support the remaining goodwill amounts are strong operationally, and absent any significant downturn in their areas of service, should be able to support their goodwill amounts for the foreseeable future. Based on the current and historical evidence supporting these reporting units' carrying value being sufficient to maintain their recorded goodwill amounts, we concluded, as allowed under newly enacted accounting guidance to forego the historically mandated quantitative step 1 impairment analysis. We will continue to monitor the current and future operations of these two reporting units to determine whether or not the mandated quantitative assessment is once again necessary. We will conduct the quantitative test at least every three years with the last such test occurring on November 1, 2010.

Historically, goodwill impairment is determined using a two-step process. The first step is to identify if a potential impairment exists by comparing the fair value of the reporting unit with its carrying amount, including goodwill. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered to have a potential impairment and the second step of the impairment test is not necessary. However, if the carrying amount of a reporting unit exceeds its fair value, the second step is performed to determine if goodwill is impaired and to measure the amount of impairment loss to recognize, if any.

The second step compares the implied fair value of goodwill with the carrying amount of goodwill. If the implied fair value of goodwill exceeds the carrying amount, then goodwill is not considered impaired. However, if the carrying amount of goodwill exceeds the implied fair value, an impairment loss is recognized in an amount equal to that excess. The implied fair value of goodwill is determined in the same manner as the amount of goodwill recognized in a business combination (i.e., the fair value of the reporting unit is allocated to all the assets and liabilities, including any unrecognized intangible assets, as if the reporting unit had been acquired in a business combination).

We use both the income approach and market approach to estimate the fair value of our reporting units under the first step of our goodwill impairment assessment. Under the income approach, a discounted cash flow analysis is performed requiring us to make various judgmental assumptions about future revenue, operating margins, growth rates and discount rates. These judgmental assumptions are based on our budgets, long-term business plans, economic projections, anticipated future cash flows and market place data. Under the market approach, the fair value of each reporting unit is calculated by applying an average peer total invested capital EBITDA (defined as earnings before interest, income taxes and depreciation and amortization) multiple to the upcoming fiscal year's forecasted EBITDA for each reporting unit. Judgment is required when selecting peer companies that operate in the same or similar lines of business and are potentially subject to the same economic risks.

We did not record any impairment of goodwill in 2009 based on our evaluations conducted throughout the year. We primarily focused our goodwill evaluations on our Well Ops SEA Pty Ltd ("WOSEA") reporting unit's goodwill as its results were adversely affected by damage to its main revenue generating asset. The asset repairs were substantially complete at December 31, 2009 and based on WOSEA's then forecasted business activity no impairment of its goodwill was necessary during 2009. WOSEA placed its revenue generating asset back in service in 2010 and also entered into the an Australian joint venture in February 2010 (Note 7). Despite these positive developments, in 2010 WOSEA's operating results were disappointing and its near-term outlook reflected the uncertainties involving the subsea market in the Southeast Asia region, including increased competition and a fragmented market. These factors were considered in our impairment test at November 1, 2010. Based on the results of that evaluation, WOSEA no longer passed its step 1 test and we concluded that a full write off of its goodwill ($16.7 million) was required after we determined the fair value of its assets under the step 2 requirements. This impairment charge is reflected as a separate line item in the accompanying consolidated statement of operations titled "Goodwill impairments." WOSEA is part of our Contracting Services business segment.

The changes in the carrying amount of goodwill are as follows (in thousands):


	Contracting Services

Balance at December 31, 2009 (1)	$	78,643
Impairments (2)		(16,743	)
Other adjustments(3)		594
Balance at December 31, 2010		62,494
Impairments		—
Other adjustments(3)		(279	)
Balance at December 31, 2011	$	62,215

(1)	Prior to 2009, we fully impaired our oil and gas related goodwill ($704.3 million) as well as the $8.3 million of goodwill associated with our former reservoir consulting business.

(2)	Amount reflects full write off of goodwill associated with our WOSEA operations.

(3)	Reflects foreign currency adjustment for certain amounts of our goodwill.

At December 31, 2011, our only remaining intangible asset, other than goodwill, was $1.6 million ($0.5 million, net of accumulated amortization) for intellectual property related to our well operations business in the North Sea. Total amortization expenses for intangible assets for the years ended December 31, 2011, 2010, and 2009 was $0.1 million, $0.1 million and $2.4 million, respectively. We expect to record a total of $0.1 million of amortization expense related to our remaining unamortized intellectual property for each of the next five years.

Recertification Costs and Deferred Drydock Charges

Our Contracting Services vessels are required by regulation to be recertified after certain periods of time. Recertification costs are incurred while a vessel is in drydock. In addition, routine repairs and maintenance are performed and at times, major replacements and improvements are performed. We expense routine repairs and maintenance costs as they are incurred. We defer and amortize drydock and related recertification costs over the length of time for which we expect to receive benefits from the drydock and related recertification, which is generally 30 months but can be as long as 60 months if the appropriate permitting is obtained. Vessels are typically available to earn revenue for the period between drydock and related recertification processes. A drydock and related recertification process typically lasts one to two months, a period during which the vessel is not available to earn revenue. Major replacements and improvements that extend the vessel's economic useful life or functional operating capability are capitalized and depreciated over the vessel's remaining economic useful life.

As of December 31, 2011 and 2010, capitalized deferred drydock charges included within Other Assets in the accompanying consolidated balance sheets (Note 6) totaled $5.4 million and $11.1 million, respectively. During the years ended December 31, 2011, 2010 and 2009, drydock amortization expense was $7.6 million, $6.9 million and $16.4 million, respectively. Amounts attributed to Cal Dive's operations totaled $9.3 million for the period prior to its deconsolidation in June 2009.

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 consist of estimated costs for dismantlement, removal, site reclamation and similar activities associated with our 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 (both long term and current) for the years ended December 31, 2011 and 2010 (in thousands):

		2011			2010

Asset retirement obligations at January 1,	$	234,936		$	248,128
Liability incurred during the period		4,982			18,056
Liability settled during the period		(42,675	)		(55,114	)
Other revisions in estimated cash flows		42,268	(1)		8,349
Accretion expense (included in depreciation and amortization)		14,880			15,517
Asset retirement obligations at December 31,	$	254,391		$	234,936

(1)	Includes impairment charges totaling $41.7 million, including $20.0 million associated with our only United Kingdom oil and gas property, to increase the estimated asset retirement obligation related to properties that are no longer producing oil or natural gas.

Revenue Recognition

Contracting Services Revenues

Revenues from Contracting Services are derived from contracts, which are both short term and long term in duration. Our long term Contracting Services contracts are contracts that contain either lump-sum, turnkey or other provisions for specific time, material and equipment charges, which are billed in accordance with the terms of such contracts. We recognize revenue as it is earned at estimated collectible amounts. Further, we record revenues net of taxes collected from customers and remitted to governmental authorities.

Unbilled revenue represents revenue attributable to work completed prior to period end that has not yet been invoiced. All amounts included in unbilled revenue at December 31, 2011 and 2010 are expected to be billed and collected within one year.

Dayrate Contracts. Revenues generated from specific time, materials and equipment contracts are generally earned on a dayrate basis and recognized as amounts are earned in accordance with contract terms. In connection with these contracts, we may receive revenues for mobilization of equipment and personnel. Revenues related to mobilization are deferred and recognized over the period in which contracted services are performed using the straight-line method. Incremental costs incurred directly for mobilization of equipment and personnel to the contracted site, which typically consist of materials, supplies and transit costs, are also deferred and recognized over the period in which the contracted services are performed using the straight-line method. Our policy to amortize the revenues and costs related to mobilization on a straight-line basis over the estimated contract service period is consistent with the general pace of activity, level of services being provided and dayrates being earned over the service period of the contract. Mobilization costs to move vessels when a contract does not exist are expensed as incurred.

Turnkey Contracts. Revenue on significant turnkey contracts is recognized on the percentage-of-completion method based on the ratio of costs incurred to total estimated costs at completion. In determining whether a contract should be accounted for using the percentage-of-completion method, we consider whether:

•		the customer provides specifications for the construction of facilities or for the provision of related services;
•		we can reasonably estimate our progress towards completion and our costs;
•		the contract includes provisions as to the enforceable rights regarding the goods or services to be provided, consideration to be received, and the manner and terms of payment;
•		the customer can be expected to satisfy its obligations under the contract; and
•		we can be expected to perform our contractual obligations.

Under the percentage-of-completion method, we recognize estimated contract revenue based on costs incurred to date as a percentage of total estimated costs. Changes in the expected cost of materials and labor, productivity, scheduling and other factors affect the total estimated costs. Additionally, external factors, including weather and other factors outside of our control, may also affect the progress and estimated cost of a project's completion and, therefore, the timing of income and revenue recognition. We routinely review estimates related to our contracts and reflect revisions to profitability in earnings on a current basis. If a current estimate of total contract cost indicates an ultimate loss on a contract, we recognize the projected loss in full when it is first determined. We recognize additional contract revenue related to claims when the claim is probable and legally enforceable.

Whenever we have a contract that qualifies as a loss contract, we estimate the future shortfall between our anticipated future revenues and future costs. See Note 16 for information regarding our more significant loss contracts during the three years ended December 31, 2011.

Oil and Gas Revenues

We record revenues from the sales of crude oil and natural gas 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, we use the entitlements method to account for sales of production. Under the entitlements method, we may receive more or less than our entitled share of production. If we receive more than our entitled share of production, the imbalance is treated as a liability. If we receive less than our entitled share, the imbalance is recorded as an asset. As of December 31, 2011, the net imbalance was a $0.9 million asset and was included in Other Current Assets ($5.1 million) and Accrued Liabilities ($4.2 million) in the accompanying consolidated balance sheet.

Income Taxes

Deferred income taxes are based on the differences between financial reporting and tax bases of assets and liabilities. We utilize the liability method of computing deferred income taxes. The liability method is based on the amount of current and future taxes payable using tax rates and laws in effect at the balance sheet date. Income taxes have been provided based upon the tax laws and rates in the countries in which operations are conducted and income is earned. A valuation allowance for deferred tax assets is recorded when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. We consider the undistributed earnings of our principal non-U.S. subsidiaries to be permanently reinvested.

It is our policy to provide for uncertain tax positions and the related interest and penalties based upon management's assessment of whether a tax benefit is more likely than not to be sustained upon examination by tax authorities. At December 31, 2011, we believe we have appropriately accounted for any unrecognized tax benefits. To the extent we prevail in matters for which a liability for an unrecognized tax benefit is established or are required to pay amounts in excess of the liability, our effective tax rate in a given financial statement period may be affected.

Foreign Currency

The functional currency for our foreign subsidiary, Helix Well Ops (U.K.) Limited is the applicable local currency (British Pound), and the functional currency of WOSEA is the applicable local currency (Australian Dollar). Results of operations for these subsidiaries are translated into U.S. dollars using average exchange rates during the period. Assets and liabilities of these foreign subsidiaries are translated into U.S. dollars using the exchange rate in effect at December 31, 2011 and 2010 and the resulting translation adjustment, which was an unrealized losses of $1.0 million and $10.0 million, respectively, is included in accumulated other comprehensive income (loss), a component of shareholders' equity. All foreign currency transaction gains and losses are recognized currently in the consolidated statements of operations.

Our foreign currency gains (losses) totaled $(1.6) million in 2011, $1.7 million in 2010 and $2.2 million in 2009. These realized amounts are exclusive of any unrealized gains or losses from our foreign currency exchange derivative contracts.

Derivative Instruments and Hedging Activities

We are currently exposed to market risk in three major areas: commodity price, interest and foreign currency exchange rates. Our risk management activities involve the use of derivative financial instruments to hedge the impact of market risk exposure primarily related to our oil and gas production prices, variable interest rates and foreign currency exchange rates. All derivatives are reflected in our balance sheet at fair value, unless otherwise noted.

We engage solely in cash flow hedges. Hedges of cash flow exposure are entered into to hedge a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability. Changes in the derivative fair values that are designated as cash flow hedges are deferred to the extent that they are effective and are recorded as a component of accumulated other comprehensive income, a component of shareholders' equity, until the hedged transactions occur and are recognized in earnings. The ineffective portion of a cash flow hedge's change in fair value is recognized immediately in earnings. In addition, any change in the fair value of a derivative that does not qualify for hedge accounting is recorded in earnings in the period in which the change occurs.

We formally document all relationships between hedging instruments and the related hedged items, as well as our risk management objectives, strategies for undertaking various hedge transactions, the methods for assessing and testing correlation, and hedge ineffectiveness. All hedging instruments are linked to the hedged asset, liability, firm commitment or forecasted transaction. We also assess, both at the inception of the hedge and on an on-going basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows of the hedged items. We discontinue hedge accounting if we determine that a derivative is no longer highly effective as a hedge, or it is probable that a hedged transaction will not occur. If hedge accounting is discontinued because it is probable the hedged transaction will not occur, deferred gains or losses on the hedging instruments are recognized in earnings immediately. If the forecasted transaction continues to be probable of occurring, any deferred gains or losses in accumulated other comprehensive income are amortized to earnings over the remaining period of the original forecasted transaction.

Commodity Price Risks

The fair value of derivative instruments 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 estimations 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.

Historically, we have entered into various financial derivative contracts, including costless collar and swap contracts, to stabilize cash flows relating to a portion of our expected oil and gas production. At December 31, 2008, our commodity derivative contracts continue to qualify for hedge accounting. However, the effects of the hurricane damage sustained in the third quarter of 2008 continued to disrupt our production causing most of our 2009 natural gas financial contracts to no longer qualified for hedge accounting as of March 31, 2009. At their inception, our forward sales contracts qualified for the normal purchases and sales scope exception but due to disruptions in our production as a result of damage caused by the 2008 hurricanes these contracts ceased to qualify for the scope exception at March 31, 2009. As previously noted, contracts that fail to qualify for hedge accounting must be marked-to-market each reporting period.

At December 31, 2009, all the then existing commodity derivative contracts qualified for hedge accounting. In June 2010, oil contracts for 480 MBbl of our anticipated production during the third quarter of 2010 ceased to qualify for hedge accounting as a result of our decision to contract the HP I to assist in the Gulf oil spill response and containment efforts rather than commencing production from our Phoenix field. In September 2010, we concluded that oil contracts covering 480 MBbls of the fourth quarter 2010 anticipated production ceased to qualify for hedge accounting because of uncertainty as to when the Phoenix field would be ready to commence initial production following extensions of the HP I contract to assist BP in the oil spill response and containment efforts. The HP I returned to the Phoenix field in October and initial production from the field commenced on October 19, 2010. At December 31, 2011, all of our existing commodity derivative contracts qualified for hedge accounting treatment.

The aggregate fair value of our commodity derivative instruments represented a net asset of $19.8 million at December 31, 2011 and a net liability of $24.4 million at December 31, 2010. For the years ended December 31, 2011, 2010 and 2009, we recorded unrealized gains (losses) of approximately $28.7 million, $(6.5) million and $(19.1) million, respectively, net of taxes (benefit) of $15.5 million, $(3.5) million and $(10.3) million, respectively, in accumulated other comprehensive income (loss). During 2011, 2010 and 2009, we reclassified approximately $(21.7) million, $25.6 million and $17.0 million, respectively, of gains (losses) from accumulated other comprehensive income (loss) to oil and gas revenues upon the sale of the related oil and gas production. In addition, during 2010 and 2009 we recorded gains of approximately $1.1 million and $89.5 million, respectively, to reflect mark-to-market adjustments for changes in the fair values of our contracts that no longer qualified for hedge accounting. These gains are reported in the accompanying consolidated statements of operations in the line titled "Gain on oil and gas derivative commodity contracts". There were no mark-to-market adjustments during 2011 associated with our commodity derivative contracts. The amount of ineffectiveness related to our oil and gas commodity contracts was immaterial for all periods presented in this Annual Report on Form10-K. See Note 20 for more disclosure regarding our hedge contracts.

As of December 31, 2011, we had derivatives contracts related to our oil and gas production totaling approximately 3.8 million barrels of oil and 17 Bcf of natural gas. At December 31, 2011 our derivative commodity contracts were as follows:

Production Period	Instrument Type	Average Monthly Volumes	Weighted Average Price a
Crude Oil:			(per barrel)
January 2012 — December 2012	Collar	75.0 MBbl	$ 96.67 — $118.57b
January 2012 — December 2012	Collar	139.0 MBbl	$ 99.42 — $117.59
January 2012 — December 2012	Swap	16.0 MBbl	$103.20
January 2013 — December 2013	Swap	41.7 MBbl	$99.15
January 2013 — December 2013	Collar	41.7 MBbl	$ 95.00 — $102.60

Natural Gas:			(per Mcf)
January 2012 — December 2012	Swaps	750.0 Mmcf	$4.35
January 2012 — December 2012	Collar	166.7 Mmcf	$4.75 — $5.09
January 2013 — December 2013	Swaps	500.0 Mmcf	$4.09

a.	The prices quoted in the table above are NYMEX Henry Hub for natural gas. For oil most of the contracts are priced as Brent crude oil.

b.	This contract is priced using NYMEX West Texas Intermediate for crude oil.

In February 2012, we entered into a costless collar financial derivative contract associated with a total of 0.1 MMBbls of our anticipated crude oil production in 2013, with a floor price of $100 per barrel and a ceiling price of $120 per barrel as indexed to Brent crude oil prices.

Changes in NYMEX oil and gas strip prices would, assuming all other things being equal, cause the fair value of these instruments to increase or decrease inversely with the change in NYMEX prices.

Variable Interest Rate Risks

As the interest rates for some of our long-term debt are subject to market influences and will vary over the term of the debt, we entered into various interest rate swaps to stabilize cash flows relating to a portion of our interest payments on our variable interest rate debt. Changes in the interest rate swap fair value are deferred to the extent the swap is effective and are recorded as a component of accumulated other comprehensive income until the anticipated interest payments occur and are recognized in interest expense. The ineffective portion of the interest rate swap, if any, will be recognized immediately in earnings. Ineffectiveness related to our interest swaps was immaterial for all periods presented in this Annual Report on Form 10-K.

In January 2010, we entered into $200 million two-year interest rate swaps to stabilize cash flows relating to a portion of our interest payments on our Term Loan, which extended through January 2012 (Note 9). In August 2011, we entered into additional interest rate swap contracts to fix the interest rate on $200 million of our Term Loan debt. These contracts settle monthly beginning in January 2012 and extend through January 2014. The fair value of our remaining interest swap contracts was a net asset of $0.1 million at December 31, 2011 and a net liability of $1.9 million at December 31, 2010 (Note 20).

Foreign Currency Exchange Risks

Because we operate in various regions in the world, we conduct a portion of our business in currencies other than the U.S. dollar. We entered into various foreign currency forwards to stabilize expected cash outflows relating to certain vessel charters that are denominated in British pounds. The aggregate fair value of the foreign currency forwards was a net liability of $0.1 million at December 31, 2011 and a net asset of $0.2 million at December 31, 2010. All of our remaining foreign exchange contracts are not accounted for as hedge contracts and changes in their fair value are being marked-to-market each reporting period. We recorded gains (losses) totaling $0.2 million in 2011, $(2.6) million in 2010 and $3.3 million in 2009 associated with foreign exchange contracts not qualifying for hedge accounting. See Note 20 for more information regarding our foreign currency contracts.

Earnings Per Share

We have shares of restricted stock issued and outstanding, which are subject to certain vesting requirements. Holders of such shares of unvested restricted stock are entitled to the same liquidation and dividend rights as the holders of our outstanding common stock and are thus considered participating securities. Under applicable accounting guidance, the undistributed earnings for each period are allocated based on the participation rights of both the common shareholders and holders of any participating securities as if earnings for the respective periods had been distributed. Because both the liquidation and dividend rights are identical, the undistributed earnings are allocated on a proportionate basis. Further, we are required to compute earnings per share ("EPS") amounts under the two class method in periods in which we have earnings from continuing operations. For periods in which we have a net loss we do not use the two class method as holders of our restricted shares are not contractually obligated to share in such losses.

The presentation of basic EPS amounts on the face of the accompanying consolidated statements of operations is computed by dividing the net income available to common shareholders by the weighted average shares of outstanding common stock. The calculation of diluted EPS is similar to basic EPS, except that the denominator includes dilutive common stock equivalents and the income included in the numerator excludes the effects of the impact of dilutive common stock equivalents, if any. The computations of the numerator (income) and denominator (shares) to derive the basic and diluted EPS amounts presented on the face of the accompanying consolidated statements of operations for the years ended December 31, 2011, 2010 and 2009 are as follows (in thousands):


		Year Ended December 31,
		2011				2010				2009
		Income		Shares		Income		Shares		Income		Shares
Basic:
Net income (loss) applicable to common shareholders	$	129,939			$	(127,102	)		$	101,867
Less: Undistributed net income allocable to participating securities		(1,599	)			—				(1,436	)
Undistributed net income (loss) applicable to common shareholders		128,340				(127,102	)			100,431
(Income) loss from discontinued operations		—				—				(9,581	)
Add: Undiscounted net income from discontinued operations allocable to participating securities		—				—				135
Income (loss) per common share – continuing operations	$	128,340		104,528	$	(127,102	)	103,857	$	90,985		99,136


		Year Ended December 31,
		2011			2010				2009
		Income	Shares		Income		Shares		Income	Shares
Diluted:
Net income (loss) per common share – continuing operations – Basic	$	128,340	104,528	$	(127,102	)	103,857	$	90,985	99,136
Effect of dilutive securities:
Stock options		—	64		—		—		—	28
Undistributed earnings reallocated to participating securities		7	—		—		—		80	—
Convertible Senior Notes		—	—		—		—		—	—
Convertible preferred stock		40	361		—		—		748	6,556
Income (loss) per common share — continuing operations		128,387			(127,102	)			91,813
Income (loss) per common share — discontinued operations		—			—				9,581
Net income (loss) per common share	$	128,387	104,953	$	(127,102	)	103,857	$	101,394	105,720

The cumulative $53.4 million of beneficial conversion charges that were realized and recorded during the first quarter of 2009 following the transactions affecting our convertible preferred stock (Note 11) are not included as an addition to adjust earnings applicable to common stock for our diluted EPS calculation.

We had a net loss applicable to common shareholders for the year ended December 31, 2010. Accordingly, our diluted EPS calculation for 2010 was equivalent to our basic EPS calculation because it excluded any assumed exercise or conversion of common stock equivalents because they were deemed to be anti-dilutive, meaning their inclusion would have reduced the reported net loss per share in those respective years. Shares that otherwise would have been included in the diluted per share calculations for each of the year ended December 31, 2010, assuming we had earnings from continuing operations, are as follows (in thousands):


	2010
Diluted shares (as reported)		103,857
Stock options		54
Convertible preferred stock		1,015
Total		104,926

The diluted EPS calculation during the year ended December 31, 2010 also excluded the consideration of adding back the $0.1 million of dividends and related costs associated with the convertible preferred stock that otherwise would have been added back to net income if assumed conversion of the shares was diluted during the year.

There were no dilutive shares associated with our 3.25% Convertible Senior Notes as the conversion price of $32.14 was not met in any of the years ended December 31, 2011, 2010 and 2009 (Note 9).

Major Customers and Concentration of Credit Risk

The market for our products and services is primarily the offshore oil and gas industry. Oil and gas companies spend capital on exploration, drilling and production operations, the amount of which is generally dependent on the prevailing view of future oil and gas prices that are subject to many external factors which may contribute to significant volatility. Our customers consist primarily of major oil and gas companies, well-established oil and gas pipeline companies and independent oil and gas producers and suppliers. We perform ongoing credit evaluations of our customers and provide allowances for probable credit losses when necessary. The percent of consolidated revenue of major customers, those whose total represented 10% or more of our consolidated revenues, was as follows: 2011 — Shell (49%); 2010 — Shell (29%) and BP Plc. (17%) and 2009 —Shell (19%). These customers were primarily purchasers of our oil and gas production. We estimate that in 2011 we provided subsea services to over 75 customers.

Fair Value Measurements

Current fair value accounting standards define fair value, establish a consistent framework for measuring fair value and expand disclosure for each major asset and liability category measured at fair value on either a recurring or nonrecurring basis. These standards also clarify that fair value is an exit price, representing the amount that would be received to sell an asset, or paid to transfer a liability, in an orderly transaction between market participants. These fair value accounting rules establish a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows:

•		Level 1. Observable inputs such as quoted prices in active markets;
•		Level 2. Inputs, other than the quoted prices in active markets, that are observable either directly or indirectly; and
•		Level 3. Unobservable inputs for which there is little or no market data, which require the reporting entity to develop its own assumptions.

Assets and liabilities measured at fair value are based on one or more of three valuation techniques noted. The valuation techniques are as follows:

(a)	Market Approach. Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.

(b)	Cost Approach. Amount that would be required to replace the service capacity of an asset (replacement cost).

(c)	Income Approach. Techniques to convert expected future cash flows to a single present value amount based on market expectations (including present value techniques, option-pricing and excess earnings models).

Our financial instruments include cash and cash equivalents, accounts receivable, accounts payable and our long-term debt. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximates fair value due to the highly liquid nature of these instruments. The following table provides additional information related to other financial instruments measured at fair value on a recurring basis at December 31, 2011 (in thousands):

		Level 1		Level 2 (1)		Level 3		Total	Valuation Technique
Assets:
Oil and gas swaps and collars	$	–	$	22,381	$	–	$	22,381	(c)
Interest rate swaps		–		327		–		327	(c)
Foreign currency forwards		–		55		–		55	(c)

Liabilities:
Oil and gas swaps and collars		–		2,597		–		2,597	(c)
Interest rate swaps		–		202		–		202	(c)
Foreign currency forwards		–		159		–		159	(c)
Fair value of long term debt (2)		1,081,376		124,488		–		1,205,864	(a)
Total net liability	$	1,081,376	$	104,683	$	–	$	1,186,059

(1)

Unless otherwise indicated, the fair value of our Level 2 derivative instruments reflects our best estimate and is based upon exchange or over-the-counter quotations whenever they are available. Where quotes are not available, we utilize other valuation techniques or models to estimate market values. These modeling techniques require us to use published future market prices and estimate market volatility and liquidity based on market data. Our actual results may differ from our estimates, and these differences can be positive or negative.

(2)	See Note 9 for additional information regarding our long term debt.

The fair value of our debt at December 31, 2011 and December 31, 2010 is as follows:


	2011				2010
	Carrying Value		Fair Value		Carrying Value		Fair Value

Term Loan(1)	$	279,750	$	279,750	$	410,441	$	406,337
Revolving Credit Facility	—		—		—		—
Convertible Senior Notes(1) (2)		300,000		300,543		300,000		289,158
Senior Unsecured Notes(1)		474,960		501,083		550,000		567,875
MARAD Debt(3)		110,166		124,488		114,811		122,159
Loan Notes	—		—			1,208		1,208
Total	$	1,164,876	$	1,205,864	$	1,376,460	$	1,386,737

(1)	The fair values of these instruments were based on quoted market prices as of December 31, 2011 and 2010. The fair values were estimated using level 1 inputs using the market approach.
(2)	Carrying amounts exclude the $9.6 million and $18.5 million of unamortized discount on the Convertible Senior Notes at December 31, 2011 and 2010, respectively.
(3)	The fair value of the MARAD debt was determined by a third-party evaluation of the remaining average life and outstanding principal balance of the MARAD indebtedness as compared to other government guaranteed obligations in the market place with similar terms. The fair value of the MARAD debt was estimated using Level 2 fair value inputs using the market approach.

We review long-lived assets for impairment whenever events occur or changes in circumstances indicate that the carrying amount of assets may not be recoverable. In such evaluation, the estimated future undiscounted cash flows to be generated by the asset are compared with the carrying value of the asset to determine if an impairment may be required. For our oil and gas properties, the estimated future undiscounted cash flows are based on estimated crude oil and natural gas proved and probable reserves and published future market commodity prices, estimated operating costs and estimates of future capital expenditures. If the estimated undiscounted cash flows for a particular asset are not sufficient to cover the asset's carrying value, it is impaired and the carrying value is reduced to the asset's current fair value. The fair value of these assets is determined using an income approach by calculating the present value of future cash flows attributable to the asset based on market information (such as forward commodity prices), estimates of future costs and estimated proved and probable reserve quantities. These fair value measurements fall within Level 3 of the fair value hierarchy

In 2011, we recorded impairment charges totaling $132.6 million, including $20.0 million related to our one U.K oil and gas property. These impairment charges affected the carrying value for 27 of our oil and gas fields in the Gulf of Mexico. These impairment charges reduced each field's carrying value to its then estimated fair value, which was $60.6 million following the respective impairment charges. In 2010, we recorded impairment charges totaling $181.1 million, including $5.0 million related to our one U.K oil and gas property. These impairment charges affected 28 of our Gulf of Mexico oil and gas properties. The estimated aggregate fair value of these 28 fields was $91.5 million following each field's respective impairment charge. In 2009, we recorded a total of $120.6 million of impairment charges, including the $51.5 million of hurricane-related impairments (Note 4). These impairment charges affected the carrying value of 47 of our Gulf of Mexico oil and gas fields. The aggregate fair value of these 47 fields was $36.2 million following each respective field's impairment charge. See Notes 5 and 21 for additional information regarding our oil and gas impairment charges, including impairment charges to increase the value of non-producing properties' estimated asset retirement obligations.

Debt Discount

On January 1, 2009, we recorded a discount of $60.2 million related to our Convertible Senior Notes as required under a newly-effective accounting pronouncement. To arrive at this discount amount we estimated the fair value of the liability component of the Convertible Senior Notes as of the date of their issuance (March 30, 2005) using an income approach. To determine this estimated fair value, we used borrowing rates of similar market transactions involving comparable liabilities at the time of issuance and an expected life of 7.75 years. In selecting the expected life, we selected the earliest date that the holder could require us to repurchase all or a portion of the Convertible Senior Notes (December 15, 2012). The remaining unamortized amount of the discount of the Convertible Notes was $9.6 million at December 31, 2011 (Note 9).