NRG Energy (NRG) 10-K 2004 FY Annual report

Exhibit 99.1

WEST COAST POWER LLC

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm		2
Consolidated Balance Sheets as of December 31, 2004 and 2003		3
Consolidated Statements of Operations for the years ended December 31, 2004, 2003 and 2002		4
Consolidated Statements of Changes in Equity for the years ended December 31, 2004, 2003 and 2002		5
Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002		6
Notes to Consolidated Financial Statements		7

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Members of West Coast Power LLC:

      In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, members’ equity and comprehensive income and cash flows present fairly, in all material respects, the financial position of West Coast Power LLC (the “Company”) at December 31, 2004 and 2003, and the results of its operations and its cash flows for the three years ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the Standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      As discussed in Note 9, the Company is the subject of substantial litigation. The Company’s ongoing liquidity, financial position and operating results may be adversely impacted by the nature, timing and amount of the resolution of such litigation. The consolidated financial statements do not include any adjustments, beyond existing accruals applicable under Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies”, that might result from the ultimate resolution of such matters.

      As discussed in Note 2, effective January 1, 2002, the Company adopted the provisions of Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets”. As discussed in Note 2, effective January 1, 2003, the Company adopted the provisions of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations”.

PricewaterhouseCoopers LLP
Houston, Texas
March 11, 2005

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WEST COAST POWER LLC

CONSOLIDATED BALANCE SHEETS
(in thousands)

	December 31,			December 31,
	2004			2003
ASSETS
Current Assets
Cash and cash equivalents	$	208,730		$	124,245
Accounts receivable, net of allowance for doubtful accounts of $1,032 and $391,819, respectively		113,794			57,844
Inventory		21,318			25,626
Prepaid expenses		52,121			41,000
Assets from risk-management activities		33,231			8,740
Total Current Assets		429,194			257,455
Property, Plant and Equipment		596,776			610,534
Accumulated depreciation		(203,060	)		(157,017	)
Property, Plant and Equipment, Net		393,716			453,517
Total Assets	$	822,910		$	710,972
LIABILITIES AND MEMBERS’ EQUITY
Current Liabilities
Accounts payable	$	1,694		$	1,032
Accounts payable, affiliates		33,529			19,242
Accrued liabilities and other current liabilities		10,132			26,241
Liabilities from risk-management activities		36,790			8,740
Total Current Liabilities		82,145			55,255
Asset retirement obligation		5,223			7,632
Total Liabilities		87,368			62,887
Total Members’ Equity		735,542			648,085
Total Liabilities and Members’ Equity	$	822,910		$	710,972

See the notes to the consolidated financial statements.

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WEST COAST POWER LLC

CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands)

	Year Ended December 31,
	2004			2003			2002
Revenues	$	725,626		$	695,964		$	585,307
Affiliate operating costs, exclusive of depreciation shown separately below		(316,632	)		(302,954	)		(456,526	)
Non-affiliate operating costs, exclusive of depreciation shown separately below		(42,191	)		(62,372	)		(29,039	)
Depreciation and amortization expense		(39,456	)		(31,693	)		(27,227	)
Goodwill impairment		—			(38,998	)		—
Impairment charges		(24,348	)		—			(13,451	)
Gain on sale of assets		689			—			—
General and administrative expenses		(198	)		(28,858	)		(10,638	)
Operating income		303,490			231,089			48,426
Interest expense		(82	)		(176	)		(15,410	)
Interest income		2,539			1,327			1,129
Income before cumulative effect of change in accounting principle		305,947			232,240			34,145
Cumulative effect of change in accounting principle		—			1,030			—
Net income	$	305,947		$	233,270		$	34,145

See the notes to the consolidated financial statements.

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WEST COAST POWER LLC

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(in thousands)

	Accumulated
	Other Comprehensive
	Income (Loss)			Members’ Equity			Comprehensive Income
Balance at December 31, 2001	$	(4,527	)	$	653,152
Net income		—			34,145		$	34,145
Amounts reclassified into income		4,527
Other comprehensive income		4,527			4,527			4,527
Comprehensive income							$	38,672
Contributions		—			13,516
Distributions		—			(64,525	)
Balance at December 31, 2002	$	—		$	640,815
Net income		—			233,270		$	233,270
Comprehensive income							$	233,270
Distributions		—			(226,000	)
Balance at December 31, 2003	$	—		$	648,085
Net income		—			305,947		$	305,947
Comprehensive income							$	305,947
Contributions		—			5,000
Distributions		—			(217,245	)
Other distributions		—			(6,245	)
Balance at December 31, 2004	$	—		$	735,542

See the notes to the consolidated financial statements.

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WEST COAST POWER LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)

	Year Ended December 31,
	2004			2003			2002
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	305,947		$	233,270		$	34,145
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization		39,456			31,693			27,227
Goodwill impairment		—			38,998			—
Impairment charges		24,348			—			13,451
Risk-management activities		3,559			—			—
Gain on sale of assets		(689	)		—			—
Cumulative effect of change in accounting principle		—			(1,030	)		—
Other, non-cash and adjustments		(1,313	)		—			—
Changes in working capital:
Accounts receivable, net		(55,950	)		3,127			164,278
Inventory		1,281			1,164			11,617
Prepaid expenses		(11,584	)		(30,338	)		2,226
Accounts payable		14,949			(20,690	)		(17,269	)
Accrued liabilities and other current liabilities		(18,654	)		20,571			5,729
Other		(1,512	)		3,744			2,489
Net cash provided by operating activities		299,838			280,509			243,893
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(1,386	)		(25,709	)		(21,652	)
Decrease (increase) in restricted cash		—			69,362			(69,362	)
Proceeds from asset sales, net		3,278			—			—
Net cash provided by (used in) investing activities		1,892			43,653			(91,014	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments of borrowings		—			(10,000	)		(140,057	)
Contributions		—			—			13,516
Distributions		(217,245	)		(226,000	)		(64,525	)
Net cash used in financing activities		(217,245	)		(236,000	)		(191,066	)
Net increase (decrease) in cash and cash equivalents		84,485			88,162			(38,187	)
Cash and cash equivalents, beginning of period		124,245			36,083			74,270
Cash and cash equivalents, end of period	$	208,730		$	124,245		$	36,083
Supplemental Disclosure of Cash Flow Information:
Interest paid		82			178			4,336
Other non-cash investing and financing activity:
Contribution of El Segundo Power II LLC by NRG		5,000			—			—

See the notes to the consolidated financial statements.

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WEST COAST POWER LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Organization and Operations of the Company

      Effective June 30, 1999, Dynegy Power Corp. (“DPC”), an indirect wholly owned subsidiary of Dynegy Holdings Inc. (“Dynegy”), and NRG Energy, Inc. (“NRG”), a subsidiary of Xcel Energy, Inc (collectively, the “Sponsors”) formed WCP (Generation) Holdings LLC (“Holdings”) and West Coast Power LLC (“WCP”, “we”, “us” or “our”), both of which are Delaware limited liability companies. The Sponsors have an equal interest in Holdings and share in profits and losses equally. WCP is wholly owned by Holdings and serves as a holding company for El Segundo Power, LLC (“ESP”), El Segundo Power II LLC (“ESP II”), Long Beach Generation LLC (“LBG”), Cabrillo Power I LLC (“Cabrillo I”) and Cabrillo Power II LLC (“Cabrillo II”). NRG became an independent public company upon its emergence from bankruptcy on December 5, 2003 and no longer has any material affiliation or relationship with Xcel Energy.

      Upon formation of WCP, the assets and liabilities of ESP, LBG, Cabrillo I and Cabrillo II (collectively, the “LLCs”) were contributed to WCP by the Sponsors and were recorded at their historical costs because the transfer represented a reorganization of entities under common control. Operations are governed by the executive committee, which consists of two representatives from each Sponsor.

      From March 2001 through December 2004, WCP’s facilities operated under a contract with the California Department of Water Resources (“CDWR”) Sales to CDWR represented a substantial portion of WCP’s capacity.

      ESP owns a 670-megawatt (“MW”) plant located in EI Segundo, California, consisting of two operating steam electric generating units. The facility has operated as a merchant plant, selling energy and ancillary services through the deregulated California wholesale electric market and other western markets. In December 2004, the California Independent System Operator (“Cal ISO”), pursuant to its tariff, designated ESP units 3 and 4 as Reliability Must Run (“RMR”) units for the calendar year 2005. On December 21, 2004 ESP filed with the Federal Energy Regulatory Commission (“FERC), an application for approval of its rates as an RMR designated facility. ESP made the election to collect rates as a “Condition 2” plant, effective January 1, 2005. On February 11, 2005 FERC issued an order that accepted the rates for filing, subject to refund, set the matter for hearing, and held the hearing in abeyance to permit the parties to continue to engage in negotiations and resolve any outstanding issues. ESP expects that FERC will issue an order approving its rates in the third quarter of 2005.

      In October 2004, the FERC approved WCP’s settlement of FERC claims relating to western energy market transactions that occurred from January 2000 through June 2001. (See Note 9 — Commitments and Contingencies for further discussion of this settlement). Included in this settlement was a payment of $22,544,942. In order to provide the funds for this settlement, Dynegy has agreed to forego approximately $17,000,000 of distributions from WCP, and NRG has agreed to forego approximately $5,500,000 of distributions and contribute El Segundo Power II LLC valued at $5,000,000 to WCP. The contribution of these assets is reflected as a contribution in the Consolidated Statements of Changes in Equity. $6,244,942 of the settlement was paid by WCP on behalf of Dynegy in accordance with the settlement agreement, and is recorded as a reduction of Dynegy’s member’s equity on the Consolidated Statements of Changes in Equity.

      On December 30, 2004, NRG West Coast LLC, a Delaware limited liability company, assigned its right, title, and interest in El Segundo Power II LLC to Holdings, which in turn assigned its interest to WCP, as part of the funding of the settlement agreement with the FERC. On February 3, 2005, the California Energy Commission approved the certificate for the construction and operation of a proposed 630-megawatt combined-cycle facility by ESP II on the site previously used by ESP units 1 and 2. ESP II became 100% owned by WCP on December 30, 2004. No date has been set to commence construction, although California state law requires that construction commence five years after the issuance of the certificate.

      On January 27, 2005, Dynegy Power Marketing Inc, an affiliate of ESP, acting as its fully authorized agent, entered into a power purchase agreement with a major California utility for a term commencing May 1, 2005 and ending December 31, 2005. As part of that agreement, ESP is required to obtain certain consents and waivers from

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WEST COAST POWER LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Cal ISO and to file for an application with FERC to change from “Condition 2” to “Condition 1” under the Cal ISO tariff.. Once all approvals are obtained, the utility will acquire all dispatch rights from ESP for the term of the agreement and assume responsibility for all Cal ISO grid reliability dispatched as permitted under the RMR contract (See Note 7 for a more detailed explanation).

      LBG owns a 560-MW plant located in Long Beach, California. On January 1, 2005, after due notice to the Cal ISO, the plant was shut down and the operator began decommissioning and environmental remediation of the plant site and equipment salvage and investment recovery efforts.

      Cabrillo I owns a 970-MW Plant located in Carlsbad, California, consisting of five steam electric generating units and one combustion turbine. The facility has operated as a merchant plant, selling energy and ancillary services through the deregulated California wholesale electric market and other western markets. Cabrillo I was designated as a RMR unit by the Cal ISO for 2004 and 2005. Pursuant to an uncontested settlement agreement filed in December 2004 with the Cal ISO and various interveners in FERC Docket No. ER04-308, RMR rates for the years 2004 through 2006 were agreed upon between the parties. As a part of that settlement, Cabrillo chose to collect rates as a “Condition 2” plant, effective January 1, 2005 (See Note 7 below for a more detailed explanation). On February 14, 2005, FERC issued an order approving these rates. Rates for 2006 will only be effective if the Cabrillo I units are designated RMR units by the Cal ISO in the third or fourth quarter of 2005.

      Cabrillo II owns 13 combustion turbines with an aggregate capacity of 202-MW located throughout San Diego County, California. The facility has operated as a merchant plant, selling energy and ancillary services through the deregulated California wholesale electric market and other western markets. Cabrillo II combustion turbines were designated as RMR units by the Cal ISO for 2004 and 2005. Pursuant to an uncontested settlement agreement filed in December 2004 with the Cal ISO and various interveners in FERC Docket No. ER04-308, RMR rates for the years 2004 through 2006 were agreed upon between the parties. As a part of that settlement, Cabrillo II chose to continue collecting rates as a “Condition 2”plant, effective January 1, 2005 (See Note 7 below for a more detailed explanation). On February 11, 2005, FERC issued an order approving these rates. Rates for 2006 will only be effective if the Cabrillo II units are designated RMR units by the CAISO in the third or fourth quarter of 2005.

Note 2—Accounting Policies

      Our accounting policies conform to GAAP. Our most significant accounting policies are described below. The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and judgments that affect our reported financial position and results of operations. We review significant estimates and judgments affecting our consolidated financial statements on a recurring basis and record the effect of any necessary adjustments prior to their publication. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things, (1) developing fair value assumptions, including estimates of future cash flows and discounts rates, (2) analyzing tangible and intangible assets for possible impairment, (3) estimating the useful lives of our assets and (4) determining amounts to accrue for contingencies, guarantees and indemnifications.

      Principles of Consolidation.The accompanying consolidated financial statements include our accounts after eliminating intercompany accounts and transactions. Certain reclassifications have been made to prior-period amounts to conform with current-period financial statement classifications.

      Cash and Cash Equivalents.Cash and cash equivalents consist of all demand deposits and funds invested in short-term investments with original maturities of three months or less.

      Accounts Receivable and Allowance for Doubtful Accounts.We establish provisions for losses on accounts receivable if it becomes probable we will not collect all or part of outstanding balances. Trade accounts receivable

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WEST COAST POWER LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

are recorded at the invoiced amount and do not bear interest. We review collectibility and establish or adjust our allowance as necessary using the specific identification method. As of December 31, 2004 and 2003,we have reserved $1,032,466 and $391,819,281, respectively, as an allowance for doubtful accounts relating to receivables owed to us by the CDWR, the Cal ISO and the California Power Exchange (“PX”). As described in Note 9, in October 2004, we settled our historical disputes with FERC parties.

      Concentration of Credit Risk.We sell our electricity production to purchasers of electricity in California, which includes the Cal ISO and Dynegy Power Marketing, Inc. (“DYPM”). These industry and geographical concentrations have the potential to impact our overall exposure to credit risk either positively or negatively because the customer base may be similarly affected by changes in economic industry, weather or other conditions.

      Inventory.Inventories are valued at the lower of market or cost using the last-in, first-out (“LIFO”) or the average cost methods and are comprised of the following:

	December 31,
	2004		2003
	(in thousands)
Emissions credits (average cost)	$	4,496	$	5,366
Materials and supplies (average cost)		3,446		6,418
Fuel oil (LIFO)		13,376		13,842
	$	21,318	$	25,626

      In conjunction with the retirement of the Long Beach facility, a lower of cost or market analysis was performed on the facility’s materials and supplies balance. The vast majority of the materials and supplies were designed for use specifically at the Long Beach facility or are otherwise obsolete. As a result, an adjustment of $3,027,613, which is included in Operating costs on the consolidated statement of operations, was made to reduce the inventory to net realizable value as of December 31, 2004.

      Emission credits represent costs paid by us to acquire additional NOx credits. We use these credits to comply with emission caps imposed by various environmental laws under which we must operate. As individual credits are used, costs are recognized as operating expense. See additional discussion below at “Other Contingencies.”

      Property Plant and Equipment.Property, plant and equipment, which consists primarily of power generating facilities, furniture and fixtures and computer equipment, is recorded at historical cost. Expenditures for major replacements, renewals and major maintenance are capitalized. We consider major maintenance to be expenditures incurred on a cyclical basis in order to maintain and prolong the efficient operation of our assets. Expenditures for repairs and minor renewals to maintain assets in operating condition are expensed. Depreciation is provided using the straight-line method over the estimated economic service lives of the assets, ranging from 3 to 25 years. The estimated economic service lives of our asset groups are as follows:

	Range of
Asset Group	Years
Power Generation Facilities		7 to 25
Furniture and Fixtures		3 to 5
Other Miscellaneous		5 to 20

      Gains and losses on sales of individual assets are reflected in gain on sale of assets in the consolidated statements of operations. We assess the carrying value of our plant and equipment in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”. If an impairment has occurred, the amount of the impairment loss recognized would be determined by estimating the related discounted cash flows of the assets and recording a loss if the resulting estimated fair value is less than the book value. For assets identified as held for sale, the book value is compared to comparable market prices or the estimated fair value if comparable market prices are not readily available to determine if an impairment loss is required.

9

WEST COAST POWER LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

      On September 30, 2004, the WCP executive committee consented to a plan to retire the Long Beach facilities effective January 1, 2005. The revision of the expected useful life of Long Beach is a change in accounting estimate, per the guidance in APB 20, “Accounting Changes.” This change is accounted for in the current and future periods if the change affects both. The remaining asset value, excluding land, as of September 30, 2004 was $9.9 million. The depreciation was accelerated so that the Long Beach facilities were fully depreciated by December 31, 2004.

      Asset Retirement Obligations.We adopted SFAS No. 143, “Asset Retirement Obligations,” effective January 1, 2003. Under the provisions of SFAS No. 143, we are required to record legal obligations to retire tangible, long-lived assets on our balance sheet as liabilities, which are recorded at a discount when the liability is incurred. Significant judgment is involved in estimating future cash flows associated with such obligations, as well as the ultimate timing of the cash flows. If our estimates on the amount or timing of the cash flow change, the change may materially affect earnings.

      Upon adoption of SFAS No. 143, existing environmental liabilities in the amount of $5,200,000 were reversed in the first quarter 2003. The fair value of the remediation costs estimated to be incurred upon retirement of the respective assets is included in the asset retirement obligation (“ARO”) and was recorded upon adoption of SFAS No. 143. Since the previously accrued liabilities exceeded the fair value of the future retirement obligations, the impact of adopting SFAS No. 143 was an increase in earnings of $1,029,756 in 2003, which is the cumulative effect of change in accounting principle in the consolidated statement of operations.

      The following pro forma financial information has been prepared to give effect to the adoption of Statement No. 143 as if it had been adopted January 1, 2002:

	Year Ended December
	31, 2002
Net income, as reported	$	34,144,995
Pro forma adjustments to reflect retroactive adoption of Statement No. 143		(1,224,171	)
Pro forma net income	$	32,920,824

      During 2004, the timing or fair value of the estimated cost to be incurred upon retirement related to the dismantlement and remediation changed for four of the Cabrillo II facilities. These changes resulted in an $896,809 decrease in our ARO liability. Since the change in the ARO liability associated with one of the facilities exceeded the asset retirement cost net of accumulated depreciation, an increase in earnings of $641,236 was recorded during 2004, which is included in Non-affiliate operating costs on the consolidated statements of operations.

      At January 1, 2004, our ARO liabilities totaled $7,631,979, which includes monitoring charges related to El Segundo Units 1 and 2 as well as dismantlement and remediation at the Cabrillo II facilities since these assets reside on leased property. Annual depreciation of the ARO assets resulting from adoption of this standard and the accretion of the liability towards the ultimate obligation amount were $404,559 and $628,290, respectively, during 2004. Annual depreciation of the ARO assets and the accretion of the liability towards the ultimate obligation amount were $644,483 and $697,472, respectively, during 2003. During 2004, we settled $2,140,550 relating to our ARO. At December 31, 2004, our ARO liabilities totaled $5,222,910.

      In addition to these liabilities, we also have potential retirement obligations for dismantlement of our other power generation facilities. Our current intent is to maintain these facilities in a manner such that they will be operated indefinitely. Liabilities will be recorded in accordance with SFAS No. 143 at such time as our operations change and a liability is incurred.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

      Other Contingencies. Environmental costs relating to current operations are expensed or capitalized, as appropriate, depending on whether they provide future economic benefit. Liabilities are recorded when environmental assessment indicate remedial efforts are probable and the costs can be reasonably estimated. Measurement of liabilities is based on currently enacted laws and regulations, existing technology and site-specific costs. Liabilities may be recognized on a discounted basis if the amount and timing of anticipated expenditures are fixed or reliably determinable; otherwise, such liabilities are recognized on an undiscounted basis. Liabilities incurred by providing indemnification in connection with assets sold or closed are recognized upon such sale or closure to the extent they are probable, can be estimated and have not previously been reserved. In assessing liabilities, no offset is made for potential insurance recoveries. Recognition of any joint and several liability is based upon our best estimate of our final pro rata share of such liability.

      Liabilities for other contingencies are recognized in accordance with SFAS No. 5, “Accounting for Contingencies,” upon identification of an exposure, which, when fully analyzed, indicates that it is both probable a liability has been incurred and the loss amount can be reasonably estimated. Non-capital costs to remedy such contingencies or other exposures are charged to a reserve, if one exists, or otherwise to current-period operations. We accrue the lesser end of the range when a range of probable loss exists.

      Goodwill. Goodwill represents, at the time of an acquisition, the amount of purchase price paid in excess of the fair value of net assets acquired. We follow the guidance set forth in SFAS No. 142, “Goodwill and Other Intangible Assets,” when assessing the carrying value of our goodwill. Accordingly, we evaluate our goodwill for impairment on an annual basis or when events warrant an assessment. Our evaluation is based, in part, on our estimate of future cash flows. The estimation of fair value is highly subjective, inherently imprecise and can change materially from period to period based on, among other things, an assessment of market conditions, projected cash flows and discount rate. In 2003, all goodwill was impaired (See Note 3).

      Revenue Recognition. Revenues from the sale of energy and ancillary services are recorded based upon output delivered and/or service provided priced at market or by contract. Revenues received from the RMR agreement with the Cal ISO are primarily derived from availability payments and amounts based on reimbursing variable costs. Revenues identified as being subject to future resolution are accounted for as discussed above at “Allowance for Doubtful Accounts.”

      Federal Income Taxes.We are not a taxable entity for federal income tax purposes. Accordingly, there is no provision for income taxes in the accompanying consolidated financial statements.

      Fair Value of Financial Instruments.Our financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable and derivative instruments to hedge commodity price and interest rate risk. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable are representative of their respective fair values due to the short-term maturities of these instruments. Additionally, we had entered into fair value hedges and electricity options. The fair value of these instruments is discussed in Note 5.

      Accounting for Derivative Instruments.We may enter into various derivative instruments to hedge the risks associated with changes in commodity prices and interest rates. We use physical forward contracts to hedge a portion of our exposure to price fluctuations of natural gas and electricity.

      Under SFAS No. 133, as amended, we recognize all derivative instruments on the balance sheet at their fair values, and changes in fair value are recognized immediately in earnings, unless the derivatives qualify, and are designated, as hedges of future cash flows or fair values, or qualify, and are designated, as normal purchases and sales. For derivatives treated as hedges of future cash flows, we record the effective portion of changes in the fair value of the derivative instrument in other comprehensive income until the related hedged items impact earnings. Any ineffective portion of a cash flow hedge is reported in earnings immediately. For derivatives treated as fair value hedges, we record changes in the fair value of the derivative and changes in the fair value of the hedged risk

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

attributable to the related asset, liability or firm commitment in current period earnings. Derivatives treated as normal purchases or sales are recorded and recognized in income using accrual accounting.

Note 3—Goodwill

      We recognized a $39 million impairment charge in 2003 based on our annual goodwill impairment test. We calculated our fair value using a discounted future cash flows methodology. Fair value was negatively impacted by the expiration of the CDWR contract in December 2004 coupled with decreasing power prices and current market conditions. Please read Note 7. The impairment charge is included in goodwill impairment on the consolidated statements of operations.

Note 4—Impairment of Long-Lived Assets

      In December 2004, we tested our long-lived assets for impairment in accordance with SFAS No. 144. As a result of the expiration of the CDWR contract (See Note 7), our impairment analysis of our Cabrillo II facility indicated future cash flows were insufficient to recover the carrying value of the long-lived assets. As a result, we recorded an impairment of $24,348,534, which is included in impairment and other charges on the consolidated statements of operations.

      In July 2002, we were notified that land leases associated with four Cabrillo II combustion turbines would not be renewed. We determined that these turbines would be sold rather than relocated to an alternate site for continued use. As a result, an impairment charge of $13,400,000 was recognized in 2002 and represented the difference between the carrying value of the four turbines and the estimated net proceeds from their prospective sale. In addition, a $5,200,000 liability was recorded for the estimated cost of restoring the land on which the turbines are located to its original condition. This reserve was reversed upon adoption of SFAS No. 143 on January 1, 2003. Please read Note 2 — Accounting Policies — Asset Retirement Obligations. During 2004, three of these turbines were sold. We recognized a gain of $689,144.

Note 5—Derivatives and Hedging

      We entered into a series of fixed price electricity purchases to hedge a portion of the fair value of our fixed price CDWR Power Purchase Agreement (“PPA”). During the years ended December 31, 2004, 2003 and 2002, there was no ineffectiveness from changes in fair value of hedge positions and no amounts were excluded from the assessment of hedge effectiveness. Additionally, no amounts were reclassified to earnings in connection with forecasted transactions that were no longer considered probable.

      The value of the fair value hedges at December 31, 2004 and 2003, were approximately zero and $(8,739,539) and is included in liabilities from risk-management activities on the consolidated balance sheets. The corresponding value of the hedged risk is approximately zero and $8,739,539 and is included in assets from risk-management activities on the consolidated balance sheets.

      Upon acceptance of RMR Condition 2 on December 31, 2004, we are not exposed to the variability of cash flow from sales of power on a merchant basis. Please read Note 7.

      We have also entered into interest rate swap agreements, which effectively exchanged variable interest rate debt for fixed interest rate debt. The agreements were used to reduce the exposure to possible increases in interest rates. We entered into these swap agreements with major financial institutions. On June 28, 2002, we terminated the interest rate swap agreements concurrently with the refinancing of our debt. Brokerage fees of approximately $5,200,000 were expensed at the time of refinancing. No interest rate swaps were outstanding at December 31, 2004 or 2003.

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Note 6—Related Parties

      We purchase fuel for our plants under full requirement natural gas supply agreements (“GSAs”) with Dynegy Marketing and Trade (“DMT”), one of our affiliates. Charges for fuel are based upon similar terms and conditions as could be obtained from unrelated third parties. Fuel purchases from DMT are included in affiliated operating costs in the consolidated statement of operations.

      We contracted with DYPM to provide all power scheduling, power marketing and risk management for us under an energy management agreement (the “EMA”). Sales of power under the EMA through DYPM were $502,554,381, $617,370,571, and $540,114,356 for the years ended December 31, 2004, 2003, and 2002 respectively. Additionally, we contracted with DMT to provide all scheduling of fuel supply.

      We entered into Operation and maintenance (“O&M”) agreements with NRG Cabrillo Power Operations Inc. and NRG El Segundo Operations Inc., two of our affiliates, for Cabrillo I and Cabrillo II effective May 2001 and for ESP and LBG effective April 2000. Their fees for services primarily include recovery of the costs of operating the plant as approved in the annual budget as well as a base monthly fee. When NRG became operator, we contracted with NRG Development Company, Inc., one of our affiliates, to provide services under the Administrative Management Agreement (the “AMA”). Services they provided under the AMA included environmental, engineering, legal and public relations services not covered under the O&M agreements. Fees for such services are subject to executive committee approval if the amounts exceed a certain percentage of the applicable annual approved budget.

      We entered into an administrative services management agreement (the “ASMA”) with Dynegy Power Management Services, L.P., one of our affiliates, under which Dynegy Power Management Services, L.P. provides administrative services such as business management and accounting to us. Fees for such services are subject to executive committee approval if the amounts exceed a certain percentage of the applicable annual approved budget.

      In addition to the related-party transactions listed above, we made $14,200,000 in interest payments in 2002 to DMT under a forbearance agreement with DMT with respect to noncompliance with the GSA. The effective interest rate on the deferred balance was prime rate plus 2%. All amounts due under the forbearance agreement have been paid and the forbearance agreement terminated. In 2004 and 2003, no interest was paid to DMT.

      As described above, our affiliates provide various services for us. Charges for these services are included in our operating and general and administrative expenses in the consolidated statements of operations and consisted of the following costs:

	Years Ended December 31,
	2004		2003		2002
			(in thousands)
Dynegy’s Related Cost
Fuel	$	267,844	$	258,134	$	401,650
EMA Charges		9,216		9,141		10,346
ASMA Charges		55		207		—
Charges included in operating costs	$	277,115	$	267,482	$	411,996
ASMA fees included in general and administrative expenses	$	1,209	$	1,331	$	1,298

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NRG’s Related Cost
O&M and AMA charges included in operating costs	$	39,517	$	35,472	$	44,531

Note 7—Power Purchase Agreement

      We entered into a long-term Power Purchase Agreement with the CDWR in March 2001. From January 2002 through December 31, 2004, the CDWR contracted for fixed price firm energy and system contingent capacity and energy representing a substantial portion of WCP’s capacity. Sales to CDWR constituted approximately 71%, 88%, and 93% of revenues, net of reserves, in 2004, 2003 and 2002, respectively.

      The CDWR contract expired by its terms on December 31, 2004. For 2005, all of our assets will be operating under RMR Condition 2 contracts with the Cal ISO, except for the Long Beach facility, which was retired effective January 1, 2005 (See Note 2—Accounting Policies—Property, Plant and Equipment). Under the terms of these RMR contracts, Cal ISO reimburses WCP for 100% of approved costs plus a rate of return specified in the contracts. When the facilities are instructed to provide power by the Cal ISO, they are reimbursed for their variable production costs. Under RMR Condition 2, the facilities are 100% committed to the Cal ISO and, therefore, do not experience changes in market conditions through bilateral energy or capacity sales to third parties that might otherwise be entered. The RMR contracts are effective for calendar year 2005. The Cal ISO may renew or terminate the RMR contracts at its sole option on an annual basis as of the first of the following year.

      In addition, ESP has entered into a power sales agreement with a major California utility for 100% of the capacity and associated energy from the El Segundo facility from May 2005 through December 2005. During the term of this agreement, the utility will be entitled to primary energy dispatch right for the facility’s generating capacity. The agreement is subject to an amendment to the El Segundo RMR agreement to switch to RMR Condition I and to permit the utility to exercise primary dispatch rights under the agreement while preserving Cal ISO’s ability to call on the El Segundo facility as a reliability resource under the RMR agreement, if necessary. The agreement will be accounted for as an operating lease of the facility under the requirements of EITF Issue 01-8.

Note 8—Debt

      In August 1999, we entered into a credit agreement with a five-year, $322,500,000 amortizing term loan with a balloon payment and a $40,000,000 working capital facility line of credit (the “Credit Agreement”). The Credit Agreement was scheduled to mature in June 2004.

      In September 1999, we entered into two interest rate swap agreements related to the Credit Agreement. One agreement effectively fixed the interest rate at 6.435% for the first $60,000,000 and matured in June 2002. The second agreement effectively fixed the interest rate at 6.230% for an incremental $40,000,000 and was scheduled to mature in June 2003. These swaps were designated as hedges of the future cash outflows associated with interest payments on the debt. The second agreement was terminated in 2002 as part of the refinancing discussed below, and the remaining deferred loss was reclassified from other comprehensive income to interest expense.

      In June 2002, we refinanced our Credit Agreement with a 364-day bank facility consisting of a $100,000,000 letter of credit line, a $10,000,000 term loan commitment and a $10,000,000 working capital loan commitment (the “Refinanced Credit Agreement”). In conjunction with the refinancing, $3,400,000 of deferred financing costs related to the original Credit Agreement were expensed. We incurred additional debt issuance costs of $4,900,000 in connection with the refinancing. Such costs were capitalized and amortized over the remaining term of the Credit Agreement and are included in prepaid expenses and other current assets.

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      In June 2003, we replaced the Refinanced Credit Agreement with an 18-month $50,000,000 letter of credit facility. With the replacement of the Refinanced Credit Agreement, we are no longer required to maintain restricted cash funds. This agreement requires us to post equal amounts of cash collateral for all letters of credit issued. This letter of credit facility incurs fees at the rate of 0.50% on any outstanding letters of credit plus a commitment fee at the rate of 0.25% on any unused amount of the commitment.

      In November 2004, the letter of credit facility was extended until December 31, 2005 and increased from $50,000,000 to $85,000,000 effective January 1, 2005. We incurred financing costs of $275,000 in connection with the renewal of the agreement. Such costs have been capitalized and will be amortized over the remaining term of the renewed agreement and are included in prepaid expenses and other current assets. At December 31, 2004, our deposit for collateral was $35,300,000. Of this deposit, $28,450,000 was issued in letters of credit.

      Our interest costs on the term loans, working capital loans and interest rate swaps (including swap termination costs and amortization costs, which are included in depreciation and amortization on the consolidated statements of operations) totaled approximately $500,000, $2,900,000, and $15,400,000 for 2004, 2003, and 2002 respectively.

Note 9—Commitments and Contingencies

      Set forth below is a description of our material legal proceedings. In addition to the matters described below, we are party to legal proceedings arising in the ordinary course of business. In management’s opinion, the disposition of these matters will not materially adversely affect our financial condition, results of operations, or cash flows.

      We record reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss is reasonably estimable under SFAS No. 5. For environmental matters, we record liabilities when remedial efforts are probable and the costs can be reasonably estimated. Please see Note 2 for further discussion. Environmental reserves do not reflect management’s assessment of the insurance coverage that may be applicable to the matters at issue. We cannot guarantee that the amount of any reserves will cover any cash obligations we might incur as a result of litigation or regulatory proceedings, payment of which could be material.

      With respect to some of the items listed below, management has determined that a loss is not probable or that any such loss, to the extent probable, is not reasonably estimable. In some cases, management is not able to predict with any degree of certainty the range of possible loss that could be incurred. Notwithstanding these facts, management has assessed these matters based on current information and made a judgment concerning their potential outcome, giving due consideration to the nature of the claim, the amount and nature of damages sought and the probability of success. Management’s judgment may, as a result of facts arising prior to resolution of these matters or other factors, prove inaccurate and investors should be aware that such judgment is made subject to the known uncertainty of litigation.

      California Market Litigation.We and numerous other power generators and marketers were the subject of numerous lawsuits arising from our participation in the western power markets during the California energy crisis. Eight of these lawsuits, which primarily alleged manipulation of the California wholesale power markets and sought unspecified treble damages, were consolidated before a single federal judge. WCP was identified as a defendant in one of those lawsuits, which was dismissed, together with another of the eight lawsuits, in the first quarter 2003 on the grounds of FERC preemption and the filed rate doctrine. The Ninth Circuit Court of Appeals affirmed this dismissal in June 2004. The plaintiffs have not appealed.

      In addition to the lawsuit discussed above, WCP and/or the LLCs were named as defendants in eight other putative class actions and/or representative actions that were filed in state and federal court on behalf of business and residential electricity consumers against numerous power generators and marketers between April and October

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2002. The complaints alleged unfair, unlawful and deceptive practices in violation of the California Unfair Business Practices Act and sought an injunction, restitution and unspecified damages. While some of the allegations in these lawsuits were similar to the allegations in the eight lawsuits described above, these lawsuits included additional allegations relating to, among other things, the validity of the contracts between these power generators and the CDWR. The court dismissed these actions, although the plaintiffs have appealed, and the briefing on that appeal was completed in October 2004. The Ninth Circuit affirmed the denial of remand and dismissal of these lawsuits in February 2005.

      In December 2002, two additional actions naming WCP and/or the LLCs as defendants were filed with similar allegations on behalf of residents of Washington and Oregon. In May 2003, the plaintiffs voluntarily dismissed these actions and refiled them in California Superior Court as a class action complaint. The complaint, which was brought on behalf of consumers and businesses in Oregon, Washington, Utah, Nevada, Idaho, New Mexico, Arizona and Montana that purchased energy from the California market, alleges violations of the Cartwright Act and unfair business practices. We have removed the action from state court and consolidated it with existing actions pending before the United States District Court for the Northern District of California. The hearing on plaintiffs’ appeal to remand to state court occurred in February 2004. The judge stayed his ruling on the appeal pending the Ninth Circuit’s ruling on the six remaining lawsuits described in the first paragraph above.

      In June 2004, the City of Tacoma public utility filed a lawsuit in Washington federal court against a number of energy companies, including us, alleging it paid inflated prices for electricity due to the defendants’ manipulation of the California wholesale power markets. The defendants filed a motion to dismiss this case in December 2004. On February 11, 2005, defendants’ motion to dismiss was granted.

      We believe that we have meritorious defenses to these claims and intend to defend against them vigorously. We cannot predict with certainty whether we will incur any liability or estimate the range of possible loss, if any, that we might incur in connection with these lawsuits. However, given the nature of the claims, an adverse result in any of these proceedings could have a material adverse effect on our financial condition, results of operations and cash flows.

      FERC and Related Regulatory Investigations—Requests for Refunds and RMR Complaints. In October 2004, the FERC approved in all respects the agreement announced by Dynegy and WCP in April 2004 which provides for the settlement of FERC claims relating to western energy market transactions that occurred from January 2000 through June 2001, including:

•   FERC’s June 2003 order to show cause why the activities of certain participants in the California power markets from January 2000 to June 2001, including WCP, did not constitute gaming and/or anomalous market behavior as defined in the ISO and PX tariffs, which matter was resolved by the January 2004 settlement providing that WCP will pay approximately $3 million into a fund for the benefit of California and Western electricity consumers, which January 2004 settlement was incorporated into the broader settlement described below; and

•   FERC’s July 2001 hearings and October 2003 orders relating to the establishment of (i) refunds to electricity customers, or offsets against amounts owed to electricity suppliers, during the period of October 2000 through June 2001 and (ii) a methodology to calculate mitigated market clearing prices in the ISO and the PX markets.

      The parties to this settlement other than Dynegy and WCP include NRG Energy, Inc., FERC Office of Market Oversight and Investigations, Pacific Gas and Electric Company, Southern California Edison, San Diego Gas & Electric Company, the CDWR, the California Electricity Oversight Board and the California Attorney General. Other market participants are permitted to opt into this settlement and share in the distribution of the settlement proceeds. Most of these other market participants have agreed to participate in the settlement. The entitlement to

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

refund and/or the liability of each of the non-settling market participants will be determined by the Cal ISO. Under the terms of the settlement, WCP will have no further liability to these non-settling parties.

      As part of the settlement agreement, WCP agreed to (i) forego its right to collect approximately $259 million in past-due receivables, plus interest, from the Cal ISO and the PX related to the settlement period, (ii) forego natural gas cost recovery claims against the California settling parties related to the settlement period, and (iii) place into escrow accounts a total of $22.5 million, which includes the above-referenced $3 million settlement with the FERC staff, for subsequent distribution to various California energy purchasers. In exchange, the settling parties agreed to forego (i) all claims relating to refunds or other monetary damages for sales of electricity during the settlement period, and (ii) claims alleging receipt of unjust or unreasonable rates for the sale of electricity during the settlement period.

      The settlement further provides that WCP is entitled to pursue claims for reimbursement of fuel costs against non-settling market participants. WCP is currently pursuing these claims but is unable to predict the amounts that may be recovered from such parties.

      The settlement does not apply to the ongoing civil litigation related to the California energy markets described above in which Dynegy and WCP are defendants. The settlement also does not apply to the pending appeal by the CPUC and the California Electricity Oversight Board of the FERC’s prior decision to affirm the validity of the CDWR contract. We are currently awaiting a ruling on this appeal and related filings and cannot predict their outcome.

      In Docket Nos. EL02-15-000 and EL03-22-000 there is a dispute regarding various payment provisions in previous RMR Contracts with Cabrillo I and II. Certain California parties and the California ISO have proposed to apply to the Cabrillo RMR Contracts, any changes required by the Commission in similar agreements entered into between the ISO and Mirant Corporation, a matter which is pending in Docket Nos. ER98-495-000, et al. In a settlement between Mirant and the California parties filed in February, 2005, Mirant and the California parties have requested that the FERC rule on the initial decision in the ER98-495 docket. An adverse ruling by FERC could have an material adverse impact on WCP in Dockets Nos. EL02-15-000 and EL03-22-000.

      We are unable to predict with any certainty how FERC may ultimately decide ER98-495 and to what extent such ruling might have an adverse impact on WCP.

      Gas Index Pricing Litigation.We are defending the following suits claiming damages resulting from the alleged manipulation of gas index publications and prices by WCP and/or the LLCs and numerous other power generators and marketers:ABAG v. Sempra Energy et al.(filed in state court in November 2004);Bustamante v. The McGraw Hill Companies et al.(class action filed in state court in November 2002);City and County of San Francisco v. Dynegy Inc. et al.(filed in state court in July 2004);County of San Diego v. Dynegy Inc., Dynegy Marketing and Trade, West Coast Power, et al.(filed in state court in July 2004);County of San Mateo v. Sempra Energy et al. (filed in state court in December 2004);County of Santa Clara v. Dynegy Inc., Dynegy Marketing and Trade, West Coast Power, et al.(filed in state court in July 2004);Fairhaven Power Company v. Encana Corp. et al.(class action filed in federal court in September 2004);Nurserymen’s Exchange v. SempraEnergy et al.(filed in state court in October 2004);Older v. Dynegy Inc. et al. (filed in federal court in September 2004);Sacramento Municipal Utility District (SMUD) v. Reliant Energy Services, et al.(filed in state court in November 2004);Texas-Ohio Energy, Inc. v. CenterPoint Energy Inc., et al.(class action filed in federal court in November 2003); andUtility Savings & Refund v. Reliant Energy Services, et al. (class action filed in federal court in November 2004). In each of these suits, the plaintiffs allege that we and other energy companies engaged in an illegal scheme to inflate natural gas prices by providing false information to gas index publications, thereby manipulating the price. All of the complaints rely heavily on the FERC and CFTC investigations into and report concerning index-reporting manipulation in the energy industry. The plaintiffs generally seek unspecified actual and punitive damages relating to costs they claim to have incurred as a result of the alleged conduct.

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      Pursuant to various motions filed by the parties to the litigation described above, the gas index pricing lawsuits pending in state court have been consolidated before a single judge in state court in San Diego. These cases are now entitled the “Judicial Counsel Coordinated Proceeding (JCCP) 4221, 4224, 4226, and 4228, the Natural Gas Anti-Trust Cases, I, II, III, & IV”, which we refer to as the “Coordinated Gas Index Cases.” A case management conference is expected in the next 60 days.

      As to the gas index pricing lawsuits that have been filed in federal court, inTexas-Ohio, the defendants filed a motion to dismiss in May 2004, on which the court held a hearing in January 2005. We are awaiting the court’s ruling. The remaining federal court cases are pending transfer, or have already been transferred, to the federal judge in Nevada who is also currently presiding over theTexas-Ohiomatter.

      We are analyzing all of these claims and intend to defend against them vigorously. We cannot predict with certainty whether we will incur any liability or to estimate the damages, if any, that might be incurred in connection with these lawsuits. We do not believe that any liability that we might incur as a result of this litigation would have a material adverse effect on our financial condition, results of operations or cash flows.

      U.S. Attorney Investigations.The United States Attorney’s office in the Northern District of California issued a Grand Jury subpoena requesting information related to our activities in the California energy markets in November 2002. We have been, and intend to continue, cooperating fully with the U.S. Attorney’s office in its investigation of these matters, including production of substantial documents responsive to the subpoena and other requests for information. We cannot predict the ultimate outcome of this investigation.

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