Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

Our Consolidated Financial Statements have been prepared in accordance with U.S. GAAP and include the accounts of all majority-owned subsidiaries that are not VIEs and all VIEs where we have determined we are the primary beneficiary. Intercompany transactions have been eliminated in consolidation.

Consolidation of OMEC — We were required by U.S. GAAP to adopt new accounting standards for VIEs which became effective January 1, 2010 that required us to perform an analysis to determine whether we should consolidate any of our previously unconsolidated VIEs or deconsolidate any of our previously consolidated VIEs. We completed our required analysis and determined that we are the primary beneficiary of OMEC. Accordingly, as required by U.S. GAAP, we consolidated OMEC effective January 1, 2010. Our Consolidated Financial Statements for the year ended December 31, 2009 present our investment in OMEC’s revenues and expenses under the equity method of accounting. We made no other changes to our group of subsidiaries that we consolidate as a result of the adoption of these new standards. See Note 5 for further discussion of accounting for our VIEs.

Equity Method Investments — We use the equity method of accounting to record our net interests in VIEs where we have determined that we are not the primary beneficiary, which include Greenfield LP, a 50% partnership interest, and Whitby, a 50% equity interest. Our share of net income (loss) is calculated according to our equity ownership percentage or according to the terms of the applicable partnership agreement. See Note 5 for further discussion of our VIEs and unconsolidated investments.

Revision — We have revised the amount reported on our Consolidated Statement of Operations as loss on interest rate derivatives by approximately $24 million for the year ended December 31, 2010. The offsetting reduction was to the amount reported as interest expense. This revision had no impact on our financial condition, results of operations or cash flows. See Note 8 for further information about our interest rate swaps formerly hedging our First Lien Credit Facility.

Use of Estimates in Preparation of Financial Statements

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures included in our Consolidated Financial Statements. Actual results could differ from those estimates.

Fair Value of Financial Instruments and Derivatives

The carrying values of accounts receivable, accounts payable and other receivables and payables approximate their respective fair values due to their short-term maturities. See Note 6 for disclosures regarding the fair value of our debt instruments and Notes 7 and 8 for disclosures regarding the fair values of our derivative instruments.

Concentrations of Credit Risk

Financial instruments that potentially subject us to credit risk consist of cash and cash equivalents, restricted cash, accounts and notes receivable and derivative assets. Certain of our cash and cash equivalents, as well as our restricted cash balances, are invested in money market accounts with investment banks that are not FDIC insured. We place our cash and cash equivalents and restricted cash in what we believe to be creditworthy financial institutions and certain of our money market accounts invest in U.S. Treasury securities or other obligations issued or guaranteed by the U.S. Government, its agencies or instrumentalities. Additionally, we actively monitor the credit risk of our counterparties, including our receivable, commodity and derivative transactions. Our accounts and notes receivable are concentrated within entities engaged in the energy industry, mainly within the U.S. We generally have not collected collateral for accounts receivable from utilities and end-user customers; however, we may require collateral in the future. For financial and commodity derivative counterparties, we evaluate the net accounts receivable, accounts payable and fair value of commodity contracts and may require security deposits, cash margin or letters of credit to be posted if our exposure reaches a certain level or their credit rating declines.

Our counterparties primarily consist of three categories of entities who participate in the wholesale energy markets:


•	financial institutions and trading companies;


•	regulated utilities, municipalities, cooperatives, ISOs and other retail power suppliers; and


•	oil, natural gas, chemical and other energy-related industrial companies.

We have concentrations of credit risk with a few of our commercial customers relating to our sales of power, steam and hedging and optimization activities. We have exposure to trends within the energy industry, including declines in the creditworthiness of our counterparties for our commodity and derivative transactions. Currently, certain of our marketing counterparties within the energy industry have below investment grade credit ratings. Our risk control group manages counterparty credit risk and monitors our net exposure with each counterparty on a daily basis. The analysis is performed on a mark-to-market basis using forward curves. The net exposure is compared against a counterparty credit risk threshold which is determined based on each counterparty’s credit rating and evaluation of their financial statements. We utilize these thresholds to determine the need for additional collateral or restriction of activity with the counterparty. We believe that our credit policies and portfolio of transactions adequately monitor and diversify our credit risk, and currently our counterparties are performing and financially settling timely according to their respective agreements.

We also have unfunded credit exposure to several European financial institutions related to our Russell City Project Debt and Los Esteros Project Debt. These financial institutions continue to provide construction funding in accordance with the terms of the debt agreements. Should one or all of these financial institutions be unable to perform under their obligations, it would not have a material adverse effect on our financial position or results of operations. See Note 6 for a further discussion of our Russell City Project Debt and Los Esteros Project Debt.

Cash and Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We have certain project finance facilities and lease agreements that require us to establish and maintain segregated cash accounts, which have been pledged as security in favor of the lenders under such project finance facilities, and the use of certain cash balances on deposit in such accounts is limited, at least temporarily, to the operations of the respective projects. At December 31, 2011 and 2010, we had cash and cash equivalents of $306 million and $269 million, respectively, that were subject to such project finance facilities and lease agreements.

Restricted Cash

Certain of our debt agreements, lease agreements or other operating agreements require us to establish and maintain segregated cash accounts, the use of which is restricted. These amounts are held by depository banks in order to comply with the contractual provisions requiring reserves for payments such as for debt service, rent, major maintenance and debt repurchases or with applicable regulatory requirements. Funds that can be used to satisfy obligations due during the next 12 months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is generally invested in accounts earning market rates; therefore, the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents on our Consolidated Balance Sheets and Statements of Cash Flows.

The table below represents the components of our restricted cash as of December 31, 2011 and 2010 (in millions):



	2011						2010
	Current		Non-Current		Total		Current		Non-Current		Total
Debt service⁽¹⁾	$	11	$	42	$	53	$	44	$	25	$	69
Rent reserve	—		—		—		22		5		27
Construction/major maintenance	33		10		43		35		14		49
Security/project/insurance	79		—		79		75		7		82
Other	16		3		19		19		2		21
Total	$	139	$	55	$	194	$	195	$	53	$	248

___________


(1)	At both December 31, 2011 and 2010, debt service included approximately $25 million of repurchase agreements with a financial institution containing maturity dates greater than one year.

Accounts Receivable and Payable

Accounts receivable and payable represent amounts due from customers and owed to vendors, respectively. Accounts receivable are recorded at invoiced amounts, net of reserves and allowances, and do not bear interest. Receivable balances greater than 30 days past due are individually reviewed for collectability, and if deemed uncollectible, are charged off against the allowance accounts after all means of collection have been exhausted and the potential for recovery is considered remote. We use our best estimate to determine the required allowance for doubtful accounts based on a variety of factors, including the length of time receivables are past due, economic trends and conditions affecting our customer base, significant one-time events and historical write-off experience. Specific provisions are recorded for individual receivables when we become aware of a customer’s inability to meet its financial obligations. We review the adequacy of our reserves and allowances quarterly.

The accounts receivable and payable balances also include settled but unpaid amounts relating to our marketing, hedging and optimization activities. Some of these receivables and payables with individual counterparties are subject to master netting arrangements whereby we legally have a right of offset and settle the balances net. However, for balance sheet presentation purposes and to be consistent with the way we present the majority of amounts related to marketing, hedging and optimization activities on our Consolidated Statements of Operations, we present our receivables and payables on a gross basis. We do not have any significant off balance sheet credit exposure related to our customers.

Inventory

At December 31, 2011 and 2010, we had inventory of $294 million and $262 million, respectively. Inventory primarily consists of spare parts, stored natural gas and fuel oil, emission reduction credits and natural gas exchange imbalances. Inventory, other than spare parts, is stated primarily at the lower of cost or market value under the weighted average cost method. Spare parts inventory is valued at weighted average cost and are expensed to plant operating expense or capitalized to property, plant and equipment as the parts are utilized and consumed.

Collateral

We use margin deposits, prepayments and letters of credit as credit support with and from our counterparties for commodity procurement and risk management activities. In addition, we have granted additional first priority liens on the assets previously subject to first priority liens under our First Lien Notes, Corporate Revolving Facility, Term Loan and New Term Loan as collateral under certain of our power and natural gas agreements. These agreements qualify as “eligible commodity hedge agreements” under our First Lien Notes, Corporate Revolving Facility, Term Loan and New Term Loan and certain of our interest rate swap agreements. The first priority liens have been granted in order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to our counterparties under such agreements. The counterparties under such agreements would share the benefits of the collateral subject to such first priority liens ratably with the lenders under our First Lien Notes, Corporate Revolving Facility, Term Loan and New Term Loan. See Note 9 for a further discussion on our amounts and use of collateral.

Deferred Financing Costs

Costs incurred related to the issuance of debt instruments are deferred and amortized over the term of the related debt using a method that approximates the effective interest rate method. However, when the timing of debt transactions involve contemporaneous exchanges of cash between us and the same creditor(s) in connection with the issuance of a new debt obligation and satisfaction of an existing debt obligation, deferred financing costs are accounted for depending on whether the transaction qualifies as an extinguishment or modification, which requires us to either write off the original deferred financing costs and capitalize the new issuance costs, or continue to amortize the original deferred financing costs and immediately expense the new issuance costs.

Property, Plant and Equipment, Net

Property, plant, and equipment items are recorded at cost. We capitalize costs incurred in connection with the construction of power plants, the development of geothermal properties and the refurbishment of major turbine generator equipment. When capital improvements to leased power plants meet our capitalization criteria they are capitalized as leasehold improvements and amortized over the shorter of the term of the lease or the economic life of the capital improvement. We expense maintenance when the service is performed for work that does not meet our capitalization criteria. Our current capital expenditures at our Geysers Assets are those incurred for proven reserves and reservoir replenishment (primarily water injection), pipeline and power generation assets and drilling of “development wells” as all drilling activity has been performed within the known boundaries of the steam reservoir. We have capitalized costs incurred during ownership consisting of additions, repairs or replacements when they appreciably extend the life, increase the capacity or improve the efficiency or safety of the property. Such costs are expensed when they do not meet the above criteria. We purchased our Geysers Assets as a proven steam reservoir and accounted for the assets under purchase accounting. All well costs, except well workovers, have been capitalized since our purchase date.

We depreciate our assets under the straight line method over the shorter of their estimated useful life or lease term using an estimated salvage value which approximates 10% of the depreciable cost basis for our power plant assets where we own the land or have a favorable option to purchase the land at conclusion of the lease term and approximately 0.15% of the depreciable costs basis for our rotable equipment. During 2009, we reviewed our accounting policies related to depreciation including our estimates of useful lives. We determined changing from composite depreciation to component depreciation for our rotable natural gas-fired power plant assets, and changing our Geysers Assets depreciation from the units of production method to the straight line method was preferable under U.S. GAAP. We also revised our estimates of useful lives. See Note 4 for further discussion regarding our changes in depreciation, changes in useful lives and the effective date of our changes.

Generally, upon normal retirement of assets under the composite depreciation method, the costs of such assets are retired against accumulated depreciation and no gain or loss is recorded. For the retirement of assets under the component depreciation method, generally, the costs and related accumulated depreciation of such assets are removed from our Consolidated Balance Sheets and a gain or loss is recorded as plant operating expense.

Impairment Evaluation of Long-Lived Assets (Including Intangibles and Investments)

We evaluate our long-lived assets, such as property, plant and equipment, equity method investments and definite-lived intangible assets for impairment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. When we believe an impairment condition may have occurred, we are required to estimate the undiscounted future cash flows associated with a long-lived asset or group of long-lived assets at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities for long-lived assets that are expected to be held and used. If we determine that the undiscounted cash flows from an asset to be held and used are less than the carrying amount of the asset, or if we have classified an asset as held for sale, we must estimate fair value to determine the amount of any impairment loss. Equipment assigned to each power plant is not evaluated for impairment separately; instead, we evaluate our operating power plants and related equipment as a whole unit. All construction and development projects are reviewed for impairment whenever there is an indication of potential reduction in fair value. If it is determined that a construction or development project is no longer probable of completion and the capitalized costs will not be recovered through future operations, the carrying value of the project will be written down to its fair value.

In order to estimate future cash flows, we consider historical cash flows, existing and future contracts and PPAs and changes in the market environment and other factors that may affect future cash flows. To the extent applicable, the assumptions we use are consistent with forecasts that we are otherwise required to make (for example, in preparing our earnings forecasts). The use of this method involves inherent uncertainty. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the impact of such variations could be material.

When we determine that our assets meet the assets held-for-sale criteria, they are reported at the lower of their carrying amount or fair value less the cost to sell. We are also required to evaluate our equity method investments to determine whether or not they are impaired when the value is considered an “other than a temporary” decline in value.

Generally, fair value will be determined using valuation techniques such as the present value of expected future cash flows. We will also discount the estimated future cash flows associated with the asset using a single interest rate representative of the risk involved with such an investment including contract terms, tenor and credit risk of counterparties. We may also consider prices of similar assets, consult with brokers, or employ other valuation techniques. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the impact of such variations could be material.

During 2011, we did not record any impairment losses. During 2010, we impaired approximately $95 million related to South Point (see Note 3 for further information related to our acquisition of the South Point lease and subsequent impairment of our South Point assets) and development costs of approximately $21 million associated with two development projects that originated prior to our Chapter 11 bankruptcy proceedings. We continued to market these projects after our Effective Date, but during 2010 we determined that their continued development was unlikely. During 2009, we had miscellaneous impairments of approximately $4 million.

Asset Retirement Obligation

We record all known asset retirement obligations for which the liability’s fair value can be reasonably estimated. Over time, the liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. At December 31, 2011 and 2010, our asset retirement obligation liabilities were $27 million and $51 million, respectively, primarily relating to land leases upon which our power plants are built and the requirement that the property meet specific conditions upon its return. Our asset retirement obligation liabilities for the year ended December 31, 2011 decreased by $24 million primarily related to a revision in the expected settlement dates of the asset retirement obligations on several of our power plants.

Revenue Recognition

Our operating revenues are composed of the following:


•	power and steam revenue consisting of fixed and variable capacity payments, which are not related to generation including capacity payments received from PJM capacity auctions, variable payments for power and steam, which are related to generation, host steam and RECs from our Geysers Assets, and other revenues such as RMR Contracts, resource adequacy and certain ancillary service revenues;


•	realized and unrealized revenues from derivative instruments as a result of our marketing, hedging and optimization activities; and


•	other service revenues.

Power and Steam

Physical Commodity Contracts — We recognize revenue primarily from the sale of power and steam thermal energy for sale to our customers for use in industrial or other heating operations upon transmission and delivery to the customer.

We routinely enter into physical commodity contracts for sales of our generated power to manage risk and capture the value inherent in our generation. Such contracts often meet the criteria of a derivative but are generally eligible for and designated under the normal purchase normal sale exemption. We apply lease accounting to contracts that meet the definition of a lease and accrual accounting treatment to those contracts that are either exempt from derivative accounting or do not meet the definition of a derivative instrument. Additionally, we determine whether the financial statement presentation of revenues should be on a gross or net basis.

With respect to our physical executory contracts, where we act as a principal, we take title of the commodities and assume the risks and rewards of ownership by receiving the natural gas and using the natural gas in our operations to generate and deliver the power. Where we act as principal, we record settlement of our physical commodity contracts on a gross basis. Where we do not take title of the commodities but receive a net variable payment to convert natural gas into power and steam in a tolling operation, we record the variable payment as revenue but do not record any fuel and purchased energy expense.

Capacity payments, RMR Contracts, RECs, resource adequacy and other ancillary revenues are recognized when contractually earned and consist of revenues received from our customers either at the market price or a contract price.

Leases — Contracts accounted for as operating leases, such as certain tolling agreements, with minimum lease rentals which vary over time must be levelized. Generally, we levelize these contract revenues on a straight-line basis over the term of the contract.

The total contractual future minimum lease receipts for these contracts are as follows (in millions):



2012	$	300
2013	287
2014	286
2015	288
2016	291
Thereafter	1,210
Total	$	2,662

Accounting for Derivative Instruments

We enter into a variety of derivative instruments including both exchange traded and OTC power and natural gas forwards, options as well as instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options) and interest rate swaps. We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for and are designated under the normal purchase normal sale exemption. Accounting for derivatives at fair value requires us to make estimates about future prices during periods for which price quotes are not available from sources external to us, in which case we rely on internally developed price estimates. See Note 8 for a further discussion on our accounting for derivatives.

Fuel and Purchased Energy Expense

Fuel and purchased energy expense is composed of the cost of natural gas and fuel oil purchased from third parties for the purposes of consumption in our power plants as fuel, and the cost of power and natural gas purchased from third parties for marketing, hedging and optimization activities as well as realized and unrealized mark-to-market gains and losses resulting from general market price movements against certain derivative natural gas contracts including financial gas transactions economically hedging anticipated future power sales that do not qualify for hedge accounting treatment.

Plant Operating Expense

Plant operating expense primarily includes employee expenses, utilities, chemicals, repairs and maintenance, insurance and property taxes. We recognize these expenses when the service is performed or in the period in which the expense relates.

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 attributable to differences between the financial statement carrying values of existing assets and liabilities and their respective tax basis and tax credit and NOL carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities due to a change in tax rates is recognized in income in the period that includes the enactment date.

We recognize the financial statement effects of a tax position when it is more-likely-than-not, based on the technical merits, that the position will be sustained upon examination. A tax position that meets the more-likely-than-not recognition threshold is measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with a taxing authority. We reverse a previously recognized tax position in the first period in which it is no longer more-likely-than-not that the tax position would be sustained upon examination. See Note 10 for a further discussion on our income taxes.

Earnings (Loss) per Share

Basic earnings (loss) per share is calculated using the weighted average shares outstanding during the period and includes restricted stock units for which no future service is required as a condition to the delivery of the underlying common stock. Diluted earnings (loss) per share is calculated by adjusting the weighted average shares outstanding by the dilutive effect of share-based awards using the treasury stock method. See Note 11 for a further discussion of our earnings (loss) per share.

Stock-Based Compensation

We use the Black-Scholes option-pricing model or the Monte Carlo simulation model to estimate the fair value of our employee stock options on the grant date. The Black-Scholes option-pricing model and the Monte Carlo simulation model take into account certain variables, which are further explained in Note 12.

New Accounting Standards and Disclosure Requirements

Fair Value Measurement — In May 2011, FASB issued Accounting Standards Update 2011-04, “Fair Value Measurement” to clarify and amend the application or requirements relating to fair value measurements and disclosures relating to fair value measurements. The update stems from the FASB and the International Accounting Standards Board project to develop common requirements for measuring fair value and for disclosing information about fair value measurements. The update is not expected to impact any of our fair value measurements but will require disclosure of the following:


•	quantitative information about the unobservable inputs used in a fair value measurement that is categorized within level 3 of the fair value hierarchy;


•	for those fair value measurements categorized within level 3 of the fair value hierarchy, both the valuation processes used and the sensitivity of the fair value measurement to changes in unobservable inputs and the interrelationships between those unobservable inputs, if any; and


•	the categorization by level of the fair value hierarchy for items that are not measured at fair value in the statement of financial position but for which the fair value is required to be disclosed.

The new requirements relating to fair value measurements are prospective and effective for interim and annual periods beginning after December 15, 2011, with early adoption prohibited. We do not expect that the adoption of this standard will have a material impact on our results of operations, cash flows or financial condition.

Comprehensive Income — In June 2011, FASB issued Accounting Standards Update 2011-05, “Comprehensive Income” to amend requirements relating to the presentation of comprehensive income. The update eliminates the option to present components of other comprehensive income as part of the statement of changes in stockholders' equity and provides an entity with the option to present comprehensive income in a single continuous financial statement or in two separate but consecutive statements. The new requirements relating to the presentation of comprehensive income are retrospective and effective for interim and annual periods beginning after December 15, 2011, with early adoption permitted. Also, in December 2011, FASB issued Accounting Standards Update 2011-12, “Comprehensive Income” to abrogate the requirement for presentation in the income statement of the effect on net income of reclassification adjustments out of AOCI as required in Accounting Standards Update 2011-05. We adopted all of the presentation requirements related to these updates for the year ended December 31, 2011.

Disclosures about Offsetting Assets and Liabilities — In December 2011, FASB issued Accounting Standards Update 2011-11, “Balance Sheet - Disclosures about Offsetting Assets and Liabilities” to enhance disclosure requirements relating to the offsetting of assets and liabilities on an entity's balance sheet. The update requires enhanced disclosures regarding assets and liabilities that are presented net or gross in the statement of financial position when the right of offset exists, or that are subject to an enforceable master netting arrangement. The new disclosure requirements relating to this update are retrospective and effective for annual and interim periods beginning on or after January 1, 2013. The update only requires additional disclosures, as such, we do not expect that the adoption of this standard will have a material impact on our results of operations, cash flows or financial condition.