Edgar Filing: AES CORPORATION

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 8-K

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES AND EXCHANGE ACT OF 1934

Date of Report (date of earliest event reported): November 21, 2003

THE AES CORPORATION
(exact name of registrant as specified in its charter)

DELAWARE	0-19281	54-1163725
(State of Incorporation)	(Commission File No.)	(IRS Employer Identification No.)

Registrant’s telephone number, including area code:
(703) 522-1315

NOT APPLICABLE
(Former Name or Former Address, if changed since last report)

ITEM 5 – OTHER EVENTS

The Company is filing the selected financial data for the five years ended December 31, 2002, certain sections of Management’s Discussion and Analysis for the three years ended December 31, 2002, and consolidated financial statements as of December 31, 2002 and 2001 and for the three years ended December 31, 2002 in order to report the impact of our classification of AES Barry, AES Haripur Private Ltd., and AES Meghnaghat Ltd., during the three months ended March 31, 2003 as well as AES Mtkvari, AES Khrami, AES Telasi, AES Communications Bolivia, AES Whitefield and Drax Power Limited during the quarters ended June 30, 2003 and September 30, 2003, as discontinued operations pursuant to Statement of Financial Accounting Standards No. 144 – Accounting for the Impairment or Disposal of Long Lived Assets (“SFAS No. 144”). Except for the foregoing, and, as otherwise expressly stated herein, we have not updated any of the information herein for events occurring after December 31, 2002.

Forward-looking statements

Certain statements contained in this Form 8-K are forward-looking statements as that term is defined in the Private Securities Litigation Reform Act of 1995. These forward-looking statements speak only as of the date hereof. Forward-looking statements can be identified by the use of forward-looking terminology such as “believe,” “expects,” “may,” “intends,” “will,” “should” or “anticipates” or the negative forms or other variations of these terms or comparable terminology, or by discussions of strategy. Future results covered by the forward-looking statements may not be achieved. Forward-looking statements are subject to risks, uncertainties and other factors, which could cause actual results to differ materially from future results expressed or implied by such forward-looking statements. The most significant risks, uncertainties and other factors are discussed in the Company’s Annual Report on Form 10-K. You are urged to read this document and carefully consider such factors.

Selected Financial Data

Please note that acquisitions, disposals, reclassifications and changes in accounting principles affect the comparability of information included in the tables below. Please refer to the Notes to the consolidated financial statements for further explanation of the effect of such activities.

	Year Ended December 31,
	2002			2001			2000		1999		1998
	(in millions, except per share data)
Statement of Operations Data:
Revenues	$	7,642		$	6,631		$	5,157	$	3,589	$	3,214

(Loss) income from continuing operations	(1,635		)	413			691		330		451

Discontinued operations, net of tax	(1,528		)	(140		)	104		27		(10		)
Cumulative effect of change in accounting principle, net of tax	(346		)	—			—		—		—
Net (loss) income	$	(3,509	)	$	273		$	795	$	357	$	441
Basic (loss) earnings per share:

(Loss) income from continuing operations	$	(3.03	)	$	0.78		$	1.43	$	0.78	$	1.14

Discontinued operations	(2.83		)	(0.26		)	0.23		0.06		(0.03		)
Cumulative effect of change in accounting principle	(0.65		)	—			—		—		—

Basic (loss) earnings per share	$	(6.51	)	$	0.52		$	1.66	$	0.84	$	1.11

Diluted (loss) earnings per share:

(Loss) income from continuing operations	$	(3.03	)	$	0.77		$	1.39	$	0.76	$	1.09

Discontinued operations	(2.83		)	(0.26		)	0.20		0.06		(0.02		)
Cumulative effect of change in accounting principle	(0.65		)	—			—		—		—
Diluted (loss) earnings per share	$	(6.51	)	$	0.51		$	1.59	$	0.82	$	1.07

	December 31,
	2002			2001		2000		1999		1998
	(in millions)
Balance Sheet Data:
Total assets	$	34,230		$	36,812	$	33,038	$	23,222	$	12,900

Non-recourse debt (long-term)	10,628			11,303		9,356		6,086		4,448

Non-recourse debt (long-term)—Discontinued operations	3,542			3,520		3,507		3,435		57
Recourse debt (long-term)	5,778			4,913		3,458		2,167		1,644
Mandatorily redeemable preferred stock of subsidiary	22			22		22		22		—
Company obligated convertible mandatorily redeemable preferred securities of subsidiary trust holding solely junior subordinated debentures of AES	978			978		1,228		1,318		550
Stockholders’ (deficit) equity	(341		)	5,539		5,542		3,315		2,368

Discussion and Analysis of Financial Condition and Results of Operations

RESULTS OF OPERATIONS

2002 COMPARED TO 2001

Revenues

Revenues increased $1.0 billion, or 15%, to $7.6 billion in 2002 from $6.6 billion in 2001. The increase in revenues is due to the acquisition of new businesses, new operations from greenfield projects and positive improvements from existing operations. Excluding businesses acquired or that commenced commercial operations in 2002 or 2001, revenues decreased 19% to $5.2 billion in 2002. AES is a global power company which operates in 30 countries around the world. The breakdown of AES’s revenues for the years ended December 31, 2002 and 2001, based on the business segment and geographic region in which they were earned, is set forth below.

	Twelve Months Ended December 31, 2002		Twelve Months Ended December 31, 2001		% Change
	(in $millions)
Large Utilities:
North America	$	818	$	836	(2	)%
South America	1,685		—		NM
Caribbean*	634		806		(21	)%
Total Large Utilities	$	3,137	$	1,642	91	%

Growth Distribution:
South America	$	263	$	781	(66	)%
Caribbean*	559		635		(12	)%
Europe/Africa	295		143		106	%
Total Growth Distribution	$	1,117	$	1,559	(28	)%

Total Regulated Revenues	$	4,254	$	3,201	33	%

* Includes Venezuela and Colombia

NM - Not Meaningful

Regulated revenues. Regulated revenues increased 33% or $1.1 billion to $4.3 billion in 2002 compared to $3.2 billion in 2001. The $1.5 billion increase in large utilities revenues was offset by a $442 million decline in growth distribution revenues. Weather generally impacts the demand for electricity, and therefore, extreme temperatures will impact the amount of revenues recorded. Excluding businesses acquired or that commenced operations in 2002 or 2001, regulated revenues decreased 28% to $2.2 billion during 2002.

Large Utilities

Large utilities revenues increased 91% or $1.5 billion to $3.1 billion in 2002 compared to $1.6 billion in 2001. This change was primarily due to the consolidation of Eletropaulo in Brazil partially offset by an $18 million decrease in North America and a $172 million decrease in the Caribbean. The North America change was primarily due to lower revenues at IPALCO in Indiana resulting from low wholesale electricity prices. The Caribbean decline occurred at EDC in Venezuela and was primarily caused by the devaluation of the Venezuelan Bolivar. The Company began consolidating Eletropaulo in February 2002 when control of the business was obtained. Please see Note 2 to the Consolidated Financial Statements for a complete description of the Eletropaulo swap transaction. If Eletropaulo had been consolidated during the comparable period in 2001, revenues compared to the prior period would have been lower due to rationing in Brazil in early 2002. Although rationing ended in February 2002 customer demand has not returned to the level it was prior to rationing. As customer demand builds, Eletropaulo believes it will experience benefits through increased revenues.

Growth Distribution

Growth distribution revenues decreased 28% or $0.5 billion to $1.1billion in 2002 compared to $1.6 billion in 2001. Growth distribution revenues decreased $518 million and $76 million in South America and the Caribbean, respectively. This was offset by a $152 million increase in Europe/Africa. South America revenues decreased due to the impact of the devaluation of the Argentine peso at Eden-Edes and Edelap, as well as due to the provision for the Brazilian regulatory decision at Sul. During the second quarter of 2002, ANEEL announced an order to retroactively change the calculation methods of the Wholesale Energy Markets (“MAE”). As a result the company recorded a provision for the Brazilian regulatory decision at Sul of approximately $146 million against revenues. The Caribbean decreased primarily due to lower revenues in El Salvador. Increases in Europe/Africa are due to the acquisitions of Sonel in Cameroon and Kievoblenergo and Rivnooblenergo in the Ukraine.

	Twelve Months Ended December 31, 2002		Twelve Months Ended December 31, 2001		% Change
	(in millions)

Contract Generation:
North America	$	830	$	742	12	%
South America	738		807		(9	)%
Caribbean*	180		204		(12	)%
Europe/Africa	355		300		18	%
Asia	303		300		1	%
Total Contract Generation	$	2,406	$	2,353	2	%

Competitive Supply:
North America	$	439	$	503	(13	)%
South America	87		155		(44	)%
Caribbean*	195		196		(1	)%
Europe/Africa	172		140		(23	)%
Asia	89		83		7	%
Total Competitive Supply	$	982	$	1,077	(9	)%

Total Non-Regulated Revenues	$	3,388	$	3,430	(1	)%

* Includes Venezuela and Colombia

Non-regulated revenues. Non-regulated revenues decreased 1% or $42 million in 2002 from 2001 due to reductions in competitive supply revenues offset in part by an increase in contract generation revenues. Non-regulated revenues will continue to be impacted by weather and market prices for electricity in the Northeastern U.S. Excluding businesses acquired or that commenced operations in 2002 or 2001, non-regulated revenues decreased 11% to $3.0 billion in 2002.

Contract Generation

Contract generation revenues increased 2% or $53 million in 2002 from 2001. Increases in contract generation revenues during 2002 in North America, Europe/Africa and Asia were offset by declines in South America and the Caribbean. North America revenues increased $88 million mainly due to the start of operations at Ironwood in Pennsylvania, Red Oak in New Jersey, increased revenues from Warrior Run in Maryland and the acquisition of Mendota in California and Hemphill in New Hampshire as part of the Thermoecotek acquisition, offset by declines at Southland in California. South America revenues decreased $69 million mainly due to declines at the Gener plants in Chile and Tiete and Uruguaiana in Brazil. Caribbean revenues decreased $24 million due to lower revenues from Los Mina in the Dominican Republic and Merida III in Mexico. Europe/Africa revenues increased $55 million due to the acquisition of Ebute in Nigeria and Bohemia in the Czech Republic, and improved operations at Tisza in Hungary offset by lower revenues from Kilroot in Northern Ireland, which experienced an outage in the second quarter of 2002. Asia revenues increased $3 million most significantly at Jiaozuo in China.

Competitive Supply

Competitive supply revenues decreased 9% or $95 million to $1.0 billion in 2002 compared to $1.1 billion in 2001 due to decreases in all geographic regions except for Asia and Europe/Africa. North America revenues declined $64 million primarily due to lower market prices in the Northeastern U.S. combined with a decline in demand in California due to mild weather. The decline in California was partially offset by additional revenue associated with the acquisition of Delano in California. South America revenues

decreased $68 million primarily due to the devaluation of the Argentine peso in February 2002 offset slightly by the start of operations at Parana in Argentina. Caribbean revenues increased slightly due to declines at Colombia I and Panama offset in part by an increase at Chivor in Colombia. Europe/Africa revenues increased $32 million due primarily from the acquisition of Ottana in Italy. Asia revenues increased $6 million primarily due to increases at our business in Kazakhstan.

Gross Margin

Gross margin decreased $34 million, or 2%, to $2.0 billion in 2002 from $2.0 billion in 2001. Gross margin as a percentage of revenues decreased to 25% in 2002 from 30% in 2001. The decrease in gross margin is due to lower market prices in the U.S., and elsewhere partially offset by the acquisition of new businesses and new operations from greenfield projects. Gross margin as a percentage of revenues declined for each segment except contract generation. Excluding businesses acquired or that commenced commercial operations in 2002 or 2001, gross margin decreased 18% to $1.6 billion in 2002. Gross margin in future periods will be negatively impacted by the expensing of stock options and other long-term incentive compensation.

	Twelve Months Ended December 31, 2002			% of Revenue		Twelve Months Ended December 31, 2001			% of Revenue		% Change
	(in $millions)					(in $millions)

Large Utilities:
North America	$	302		37	%	$	290		35	%	4	%
South America	163			10	%	(14		)	—		NM
Caribbean*	220			35	%	342			42	%	(36	)%
Total Large Utilities:	$	685		22	%	$	618		38	%	11	%

Growth Distribution:
South America	(61		)	(23	)%	249			32	%	(124	)%
Caribbean*	53			9	%	31			5	%	71	%
Europe/Africa	30			10	%	(13		)	(9	)%	NM	%
Asia	(3		)	NM		(3		)	NM		—
Total Growth Distribution	$	19		2	%	$	264		17	%	(92	)%

Total Regulated Gross Margin	$	704		17	%	$	882		28	%	(20	)%

* Includes Venezuela and Colombia

NM - Not Meaningful

Regulated gross margin. Regulated gross margin decreased 20% or $178 million to $704 million in 2002 compared to $882 million in 2001. The decrease is primarily due to weakening margins in our South American growth distribution businesses and our Caribbean large utility business offset by increases at our North and South American large utilities and Europe/Africa growth distribution businesses. Regulated gross margin as a percentage of revenues decreased to 17% in 2002 from 28% in 2001. Excluding businesses acquired or that commenced operations in 2002 or 2001, regulated gross margin decreased 44% to $509 million in 2002.

Large Utilities

Large utilities gross margin increased 11% or $67 million to $685 million in 2002 compared to $618 million in 2001 primarily due to increases in North and South America offset in part by a decrease in the Caribbean. North America increased $12 million due to increased contributions from IPALCO. South America increased $177 million due to the consolidation of Eletropaulo. The decrease of $122 million in the Caribbean is due to the devaluation of the Venezuelan Bolivar and its impacts on EDC. EDC’s tariff is adjusted semi-annually to reflect fluctuations in inflation and the currency exchange rate. However, a failure to receive such an adjustment to reflect changes in the exchange rate and inflation could adversely affect their results of operations in the future. The large utilities gross margin as a percentage of revenues decreased to 22% for 2002 from 38% in 2001. Eletropaulo’s 2002 gross margin was negatively impacted by the write off approximately $80 million of other receivables. Our distribution concession contracts in Brazil provide for annual tariff adjustments based upon changes in the local inflation rates and, generally, significant devaluations are followed by increased local currency inflation. However, because of the lack of adjustment to the current exchange rate, the in arrears nature of the respective tariff adjustment, or the potential delays or magnitude of the resulting local currency inflation of the tariff, the future results of operations of Eletropaulo could be adversely affected by the continued devaluation of the Brazilian Real.

Growth Distribution

Growth distribution gross margin decreased 92% or $245 million to $19 million in 2002 compared to $264 million in 2001. The decline of $310 million in South America gross margin was offset in part by increases of $43 million and $22 million in Europe/Africa and the Caribbean, respectively. South America gross margin declined primarily due to devaluation of the Argentine peso and the reduction in gross margin from Sul due to the $146 million provision for the Brazilian Regulatory decision. Europe/Africa gross margin increased due to the acquisitions of Kievoblenergo and Rivnooblenergo in the Ukraine. Caribbean gross margin increased due primarily to operational improvements at EDE Este in the Dominican Republic. The growth distribution gross margin as a percentage of revenues decreased to 2% in 2002 from 17% in 2001.

	Twelve Months Ended December 31, 2002		% of Revenue		Twelve Months Ended December 31, 2001		% of Revenue		% Change
	(in millions)				(in millions)
Contract Generation:
North America	$	426	51	%	$	368	50	%	16	%
South America	280		38	%	253		31	%	11	%
Caribbean*	32		18	%	27		13	%	19	%
Europe/Africa	139		39	%	94		31	%	48	%
Asia	146		48	%	91		30	%	60	%
Total Contract Generation	$	1,023	43	%	$	833	35	%	23	%
Competitive Supply:
North America	$	94	21	%	$	131	26	%	(28	)%
South America	21		24	%	40		26	%	(48	)%
Caribbean*	66		34	%	56		29	%	18	%
Europe/Africa	18		10	%	22		16	%	(18	)%
Asia	19		21	%	15		18	%	27	%
Total Competitive Supply	$	218	22	%	$	264	25	%	(17	)%
Total Non-Regulated Gross Margin	$	1,241	37	%	$	1,097	32	%	(13	)%

* Includes Venezuela and Colombia

NM - Not Meaningful

Non-regulated gross margin. Non-regulated gross margin decreased 13% or $144 million to $1.2 billion in 2002 compared to $1.1 billion in 2001. This decrease is primarily due to lower margins at our North American, South American, European and African competitive supply businesses partially offset by increased margins in all regions of our contract generation segment. Non-regulated gross margin as a percentage of revenues increased to 37% in 2002 from 32% in 2001. Excluding businesses acquired or that commenced operations in 2002 or 2001, non-regulated gross margin increased 5% to $1.1 billion in 2002.

Contract Generation

Contract generation gross margin increased 23% or $190 million to $1.0 billion in 2002 compared to $0.8 billion in 2001 primarily due to improvements at existing businesses and operations from new businesses. The contract generation gross margin as a percentage of revenues increased to 43% in 2002 from 35% in 2001. Gross margin increased in all geographic regions. North America gross margin increased $58 million due to the start of commercial operations at Ironwood in Pennsylvania, Red Oak in New Jersey and improvements at Warrior Run in Maryland and Beaver Valley in Pennsylvania. South America gross margin increased $27 million due to increases at Gener, Tiete and Uruguaiana. Europe/Africa gross margin increased $45 million mainly due to the acquisition of Ebute in Nigeria and improvements at Kilroot in Northern Ireland and Tisza II in Hungary. Asia gross margin increased $55 million mainly due to increased contributions from Jiaozuo and Hefei in China.

Competitive Supply

Competitive supply gross margin decreased 17% or $46 million to $218 million in 2002 compared to $264 million in 2001. Decreases in North America, South America, Europe and Africa gross margins were offset slightly by increases from the Caribbean and Asia. North America gross margin decreased $37 million mainly due to the lower energy prices in New York and milder weather in California. South America gross margin decreased $19 million mainly due to the devaluation of the peso in Argentina. Europe/Africa gross margin decreased $4 million mainly due to lower energy prices in the United Kingdom. Caribbean gross margin increased $10 million mainly due to increases from Panama and Chivor in Colombia. The competitive supply gross margin as a percentage of revenues decreased to 22% in 2002 from 25% in 2001.

Selling, general and administrative expenses. SG&A decreased $8 million, or 7%, to $112 million in 2002 from $120 million in 2001. SG&A as a percentage of revenues decreased to 1% in 2002 from 2% in 2001. The overall decrease in SG&A is due to the Company’s increased focus on cost cutting. However, the Company has undertaken several corporate initiatives that require additional personnel and infrastructure, and these may result in increased selling, general and administrative expenses in future periods. Additionally, the expensing of stock options and other long-term incentive compensation will increase selling, general and administrative expenses in future periods.

Severance and transaction costs. During 2001, the Company incurred approximately $131 million of transaction and contractual severance costs related to the acquisition of IPALCO.

Interest expense. Interest expense increased $419 million, or 31%, to $1.8 billion in 2002 from $1.3 billion in 2001. Interest expense as a percentage of revenues was 23% in 2002 and 20% in 2001. Overall interest expense increased primarily due to the consolidation of Eletropaulo in February 2002, issuance of senior secured notes at IPALCO, interest expense from new businesses, as well as additional corporate interest costs arising from a higher outstanding balance during 2002 on the Company’s revolving loan. During December 2002, the Company refinanced a significant amount of

debt at terms less favorable than the original debt. As a result, the amount of interest expense recorded in future periods is expected to increase.

Interest income. Interest income increased $98 million, or 55%, to $276 million in 2002 from $178 million in 2001. Interest income as a percentage of revenues was 4% in 2002 and 3% in 2001. The increase in interest income during 2002 is due primarily to the consolidation of Eletropaulo partially offset by a decline in interest income from Thames due to the collection of its contract receivable.

Other income. Other income increased $23 million, or 21%, to $133 million in 2002 from $110 million in 2001. Approximately $85 million of the amount recorded in 2002 is attributable to gains on the extinguishment of liabilities and market-to-market gains on commodity derivatives. See Note 16 to the consolidated financial statements for an analysis of other income.

Other expense. Other expense increased $18 million, or 31%, to $77 million in 2002 from $59 million in 2001. Approximately $67 million of the amount recorded in 2002 is attributable to losses on the sale of assets or extinguishment of liabilities and other non-operating expenses. See Note 16 to the consolidated financial statements for an analysis of other expense.

Foreign currency transaction losses. Foreign currency transaction losses increased $468 million to $484 million in 2002 from $16 million in 2001. Foreign currency transaction losses increased primarily due to a 50% devaluation in the Argentine peso from 1.65 at December 31, 2001 to 3.32 at December 31, 2002, which resulted in $143 million of foreign currency transaction losses for the year ended December 31, 2002. Additionally, a 32% devaluation occurred in the Brazilian Real during 2002 from 2.41 at December 31, 2001 to 3.53 at December 31, 2002. Furthermore, the Company recorded more foreign currency losses due to the consolidation of Eletropaulo, and since there was less allocation to the minority partners because their investment has been reduced to zero. As a result, the Company recorded net Brazilian foreign currency losses of $357 million during 2002, of which approximately $83 million is included in equity in pre-tax (losses) earnings of affiliates. These decreases were offset by $39 million of foreign currency transaction gains recorded at EDC during 2002 due to a 46% devaluation of the Venezuelan Bolivar from 758 at December 31, 2001 to 1,403 at December 31, 2002. EDC uses the U.S. dollar as its functional currency but a portion of its debt is denominated in the Venezuelan Bolivar.

Equity in pre-tax (losses) earnings of affiliates. Equity in pre-tax (losses) earnings of affiliates declined by $383 million to a loss of $207 million in 2002 compared to income of $176 million in 2001. The overall decrease is due primarily to declines in equity in earnings of Brazilian large utility affiliates, including the impairment charge associated with the other than temporary decline in value of CEMIG.

Additionally, a share swap was completed during February 2002 which gave the Company control of Eletropaulo. In 2001, the Company recorded $134 million of equity in Eletropaulo’s pre-tax earnings; however, this amount decreased to $18 million due to consolidation of Eletropaulo’s results subsequent to the share swap and the ongoing devaluation of the Brazilian Real. Equity in pre-tax (losses) earnings of our large utilities included non-cash Brazilian foreign currency transaction losses of $83 million and $210 million during 2002 and 2001, respectively, due to the devaluation of the Brazilian Real during both periods.

Equity in (losses) earnings of growth distribution affiliates improved from a loss of $13 million in 2001 to $0 in 2002. The improvement is primarily due to a change in accounting for our investment in CESCO.

Equity in earnings of contract generation affiliates increased to $75 million in 2002 from $54 million in 2001. The increase is due primarily to contributions from several Chinese equity affiliates and from Elsta offset by a decrease from OPGC.

Equity in earnings of competitive supply affiliates improved from a loss of $9 million in 2001 to a loss of $7 million in 2002. The improvement is primarily due to the sale of Infovias, a Brazilian company, during the second quarter of 2002.

(Loss) gain on sale of assets and asset impairment expense. (Loss) gain on sale of assets and asset impairment expense changed from a gain of $18 million for 2001 to a loss of $473 million in 2002 primarily resulting from impairment charges taken in 2002.

In the fourth quarter of 2002, the Company decided not to provide any further funding to Lake Worth and to sell the project. As a result, the carrying amount of AES’s investment in the Lake Worth project is not expected to be recovered. Accordingly, in accordance with SFAS No. 144, an impairment charge of $78 million was recorded to write-down the net assets of Lake Worth to their fair market value.

In September 2002, AES Greystone, LLC and its subsidiary Haywood Power I, LLC, sold the Greystone gas-fired peaker assets then under construction in Tennessee to Tenaska Power Equipment for $36 million including cash and assumption of certain obligations. With this sale, AES and its subsidiaries have eliminated any future capital expenditures related to the facility, and also settled all major outstanding obligations with parties involved in this project. AES recorded a loss of approximately $168 million associated with this sale. Greystone was previously recorded as a competitive supply business.

Additionally, during 2002, the Company recorded $86 million of other losses which resulted from the sale of assets to third parties, and $141 million of other asset impairment charges taken to reflect the net realizable value of discontinued development projects and other non-recoverable assets.

Goodwill impairment expense. During 2002, the Company recorded a goodwill impairment charge of $612 million primarily related to all of the goodwill at Eletropaulo in Brazil. The Company recognizes as goodwill the excess of the cost of an acquired entity over the net amount assigned to assets acquired and liabilities assumed. The Company evaluates goodwill for impairment on an annual basis and

whenever events or changes in circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying value. The Company’s annual impairment testing date is October 1^st. Prior to January 1, 2002, goodwill was amortized on a straight-line basis over the estimated benefit period, which ranged from 10 to 40 years, and total accumulated amortization amounted to $190 million at December 31, 2001. As of January 1, 2002, goodwill is no longer amortized.

Income taxes. Income tax expense (including income taxes on equity in earnings) on continuing operations increased to $297 million in 2002 from expense of $276 million in 2001. The Company’s tax position changed from tax expense at a 40% effective tax rate in 2001 to (22)% in 2002. The 2002 effective tax rate resulted from a small tax expense on the pre-tax book loss, which was primarily due to the book write off of non-deductible foreign goodwill, and the recording of valuation allowances against deferred tax assets from translation losses and various capital losses.

Minority interest (income) expense. Pre-tax minority interest changed $138 million, or 133%, to a benefit of $34 million in 2002 from an expense of $104 million in 2001. Increases in minority interest income in large utilities and competitive supply were somewhat offset by greater minority interest expense in growth distribution and contract generation.

Large utilities minority interest changed by $124 million to a benefit of $36 million for 2002 from expense of $88 million for 2001. Increases in minority interest income from EDC and CEMIG were slightly offset by increased expense from Eletropaulo. The change is mainly due to the sharing of losses that resulted from currency devaluations and impairment charges with the minority shareholders. The change in large utilities minority interest would have been somewhat greater; however, the minority interest in Eletropaulo was reduced to zero during the third quarter of 2002 and the Company began picking up all of the losses.

Growth distribution minority interest changed to an expense of $6 million for 2002 compared to a benefit of $16 million for 2001. The change in growth distribution minority interest is due to additional expense from Sonel, Kievoblenergo, and Ede Este partially offset by lower expense at Eden Edes, Edelap, and CAESS.

Contract generation minority interest expense increased $26 million to $48 million for 2002 compared to expense of $23 million for 2001. The change is due to the sharing of earnings by the minority partners of Tiete in Brazil and at several of our Chinese businesses.

Competitive supply minority interest changed by $60 million to a benefit of $51 million in 2002 compared to expense of $9 million in 2001. The change in competitive supply minority interest is primarily due to sharing of losses that resulted from the devaluation of the Argentine peso with the minority shareholders.

(Loss) income from continuing operations. (Loss) income from continuing operations decreased $2.0 billion to a loss of $1.6 billion for 2002 from income of $413 million for 2001. The loss recorded in 2002 resulted primarily from asset and goodwill impairments as well as foreign currency transaction losses.

Discontinued operations. Loss from operations of discontinued businesses, net of tax, were $1,528 million and $140 million, respectively, in 2002 and 2001. During 2001, the Company discontinued certain of its operations, including Power Direct, Ib Valley, Power Northern, Geoutilities, TermoCandelaria and several telecommunications businesses in the United States and Brazil. During 2002, the Company discontinued certain of its operations including Fifoots, CILCORP, NewEnergy, Eletronet, Mt. Stuart, Ecogen, two Altai businesses, Mountainview and Kelvin. Subsequently, during 2003, the Company discontinued certain of its operations including Barry, Haripur, Meghnaghat and Drax. The Company closed the sale of both CILCORP and Mt. Stuart in January 2003 and the sale of Ecogen in February 2003. All of the operations for these businesses and the related write offs from dispositions in 2002 and 2001 are reported in this line item. Pursuant to SFAS No. 144, if any of these businesses are not sold or disposed of within one year of the date they were classified as discontinued operations they must be reclassified as continuing operations.

Accounting change. On April 1, 2002, the Company adopted Derivative Implementation Group (“DIG”) Issue C-15 which established specific guidelines for certain contracts to be considered normal

purchases and normal sales contracts under SFAS No. 133. As a result of this adoption, the Company had two contracts which no longer qualified as normal purchases and normal sales contracts and were required to be treated as derivative instruments under SFAS No. 133. The adoption of DIG Issue C-15, effective April 1, 2002, resulted in a cumulative increase to income of $127 million, net of income tax effects.

Effective January 1, 2002, the Company adopted SFAS No. 142, “Goodwill and Other Intangible Assets” which establishes accounting and reporting standards for goodwill and other intangible assets. The adoption of SFAS No. 142 resulted in a cumulative reduction to income of $473 million, net of income tax effects. SFAS No. 142 adopts a fair value model for evaluating impairment of goodwill in place of the recoverability model used previously. The Company wrote-off the goodwill associated with certain acquisitions where the current fair market value of such businesses is less than the current carrying value of the business, primarily as a result of reductions in fair value associated with lower than expected growth in electricity consumption compared to the original estimates made at the date of acquisition. The Company’s annual impairment testing date is October 1^st.

Net (loss) income. Net (loss) income decreased $3.8 billion to a loss of $3.5 billion in 2002 from net income of $273 million in 2001. This effect was due to lower gross margin from the growth distribution and competitive supply segments, increased interest expense, increased foreign currency losses due to devaluation in Brazil and Argentina, impairment charges taken on goodwill and other assets, and losses from discontinued operations offset by greater interest income, higher gross margin from the large utilities and contract generation segments, and greater sharing of losses with minority partners.

2001 COMPARED TO 2000

Revenues

Revenues increased $1.4 billion, or 29% to $6.6 billion in 2001 from $5.2 billion in 2000. The increase in revenues is due to the acquisition of new businesses, new operations from greenfield projects and positive improvements from existing operations. Excluding businesses acquired or that commenced commercial operations in 2001 or 2000, revenues increased 3% to $4.5 billion in 2001. AES is a global power company which operates in 30 countries around the world. The breakdown of AES’s revenues for the years ended December 31, 2001 and 2000, based on the business segment and geographic region in which they were earned, is set forth below.

	Twelve Months Ended December 31, 2001		Twelve Months Ended December 31, 2000		% Change
	(in $millions)		(in $millions)
Large Utilities:
North America	$	836	$	892	(6	)%
Caribbean*	806		493		63	%
Total Large Utilities	$	1,642	$	1,385	19	%

Growth Distribution:
South America	$	781	$	767	2	%
Caribbean*	635		338		88	%
Europe/Africa	143		—		NM
Asia	—		131		NM
Total Growth Distribution	$	1,559	$	1,236	26	%

Total Regulated Revenues	$	3,201	$	2,621	22	%

* Includes Venezuela and Colombia

NM - Not Meaningful

Regulated revenues. Regulated revenues increased $580 million, or 22%, to $3.2 billion in 2001 from $2.6 billion in 2000. Regulated revenues increased in both the large utilities and growth distribution segments due to the contributions of acquired businesses as well as improved operations. Weather generally impacts the demand for electricity, and therefore, extreme temperatures will impact the amount of revenues recorded. Excluding businesses acquired or that commenced operations in 2001 or 2000, regulated revenues increased 8% to $2.1 billion during 2001.

Large Utilities

Large utilities revenues increased $257 million, or 19%, to $1.6 billion in 2001 from $1.4 billion in 2000 principally resulting from the addition of revenues attributable to businesses acquired during 2001 or 2000. The majority of the increase occurred within the Caribbean, offset by a decrease of $56 million in North America. In the Caribbean, revenues increased $313 million due to a full year of revenues from EDC, which was acquired in June 2000.

Growth Distribution

Growth distribution revenues increased $323 million, or 26%, to $1.6 billion in 2001 from $1.2 billion in 2000. Revenues increased most significantly in the Caribbean and to a lesser extent in South America and Europe/Africa. Revenues decreased in Asia. In the Caribbean, growth distribution segment revenues increased $297 million due primarily to a full year of operations at CAESS, which was acquired in 2000, and improved operations at EDE Este. In South America, growth distribution segment revenues increased $14 million due to the significant revenues at Sul from our settlement with the Brazilian government offset by declines in revenues at our Argentine distribution businesses. The settlement with the Brazilian government confirmed the sales price that Sul would receive from its sales into the southeast market (where rationing occurred) under its Itaipu contract. The Brazilian government reversed this decision retroactively in 2002. In Europe/Africa, growth distribution segment revenues increased $143 million primarily from the acquisition of SONEL. In Asia, growth distribution segment revenues decreased $131 million mainly due to the change in the way in which we are accounting for our investment in CESCO. CESCO was previously consolidated but was changed to equity method during 2001 when the Company was removed from management and the Board of Directors. This decline was partially offset by the increase in revenues from the distribution businesses that we acquired in Ukraine.

	Twelve Months Ended December 31, 2001		Twelve Months Ended December 31, 2000		% Change
	(in $millions)		(in $millions)
Contract Generation:
North America	$	742	$	696	7	%
South America	807		286		182	%
Caribbean*	204		193		6	%
Europe/Africa	300		213		41	%
Asia	300		308		(3	)%
Total Contract Generation	$	2,353	$	1,696	39	%

Competitive Supply:
North America	$	503	$	506	(1	)%
South America	155		109		42	%
Caribbean*	196		74		165	%
Europe/Africa	140		80		75	%
Asia	83		71		17	%
Total Competitive Supply	$	1,077	$	840	28	%
Total Non-Regulated Revenues	$	3,430	$	2,536	35	%

* Includes Venezuela and Colombia

Non-regulated revenues. Non-regulated revenues increased $894 million, or 35%, to $3.4 billion in 2001 from $2.5 billion in 2000. Non-regulated revenues increased in both the contract generation and competitive supply segments due to the acquisition of new businesses as well as improved operations at existing businesses. Excluding businesses acquired or that commenced operations in 2001 or 2000, non-regulated revenues decreased 1% to $2.4 billion during 2001

Contract Generation

Contract generation revenues increased $657 million, or 39% to $2.4 billion in 2001 from $1.7 billion in 2000, principally resulting from the addition of revenues attributable to businesses acquired during 2001 or 2000. Contract generation revenues increased in all geographic regions, but most significantly in South America. South America revenues grew $521 million due mainly to the acquisition of Gener and the full year of operations at Uruguaiana offset by reduced revenues at Tiete from the electricity rationing in Brazil. In Europe/Africa, contract generation segment revenues increased $87 million, and the acquisition of a controlling interest in Kilroot during 2000 was the largest contributor to the increase. North America contract generation revenues increased $46 million. Caribbean contract generation revenues increased $11 million due to a full year of operations at Merida III offset by a lower capacity factor at Los Mina. Asia contract generation decreased $8 million.

Competitive Supply

Competitive supply revenues increased $237 million or 28% to $1.1 billion in 2001 from $0.8 billion in 2000. The most significant increases occurred within the Caribbean where revenues increased $122 million due primarily to the acquisition of Chivor. Slight increases were recorded within South America and Asia. Europe/Africa reported a $ 60 million increase due to the acquisition of Ottana. In North America, competitive supply segment revenues decreased $3 million due primarily to increased operations at Placerita offset by lower market prices at our New York businesses.

Gross Margin

Gross margin increased $369 million, or 23%, to $2.0 billion in 2001 from $1.6 billion in 2000. Gross margin as a percentage of revenues decreased to 30% in 2001 from 31% in 2000. The increase in gross margin is due to the acquisition of new businesses and new operations from greenfield projects. The decrease in gross margin as a percentage of revenues is due to a decline in the contract generation and competitive supply gross margin percentages offset slightly by increased gross margin percentages from large utilities and growth distribution. Excluding businesses acquired or that commenced commercial operations in 2001 or 2000, gross margin decreased 4% to $1.5 billion in 2001.

	Twelve Months Ended December 31, 2001			% of Revenue		Twelve Months Ended December 31, 2000			% of Revenue		% Change
	(in $millions)					(in $millions)

Large Utilities:
North America	$	290		35	%	$	262		29	%	11	%
South America	(14		)	—		(2		)	—		NM
Caribbean*	342			42	%	177			36	%	93	%
Total Large Utilities	$	618		38	%	$	437		32	%	41	%

Growth Distribution:
South America	$	249		32	%	$	169		22	%	47	%
Caribbean*	31			5	%	(8		)	(2	)%	NM
Europe/Africa	(13		)	(9	)%	—			—		NM
Asia	(3		)	NM		(16		)	(12	)%	81	%
Total Growth Distribution	$	264		17	%	$	145		12	%	82	%

Total Regulated Gross Margin	$	882		28	%	$	582		22	%	52	%

* Includes Venezuela and Colombia

NM - Not Meaningful

Regulated gross margin. Regulated gross margin increased $300 million, or 52%, to $882 million in 2001 from $582 million in 2000. Regulated gross margin increased in both the large utilities and growth distribution segments.

Regulated gross margin as a percentage of revenues increased to 28% during 2001 from 22% for 2000. Excluding businesses acquired or that commenced operations in 2001 or 2000, regulated gross margin increased 43% to $592 million during 2001.

Large Utilities

Large utilities gross margin increased $181 million, or 41%, to $618 million in 2001 from $437 million in 2000. Large utilities gross margin as a percentage of revenues increased to 38% in 2001 from 32% in 2000. In the Caribbean, large utility gross margin increased $165 million and was due to a full year of contribution from EDC which was acquired in June 2000. Additionally, increased margins at IPALCO contributed to a $28 million improvement in North American gross margin.

Growth Distribution

Growth distribution gross margin increased $119 million, or 82%, to $264 million in 2001 from $145 million in 2000. Growth distribution gross margin as a percentage of revenue increased to 17% in 2001 from 12% in 2000. Growth distribution gross margin, as well as gross margin as a percentage of sales, increased in South America, the Caribbean, and Asia but decreased in Europe/Africa. In South America, growth distribution margin increased $80 million and was 32% of revenues. The increase is due primarily to Sul’s sales of excess energy at prices determined under an initial decision made by ANEEL into the southeast market where rationing was taking place; however, the Brazilian government reversed this decision retroactively in 2002. In the Caribbean, growth distribution margin increased $39 million and was 5% of revenues mainly due to lower losses at Ede Este and an increase in contribution from CAESS. In Europe/Africa, growth distribution margin decreased $13 million and was negative due to losses at SONEL. In Asia, growth distribution margin improved $13 million but remained negative. The improvement was primarily due to the change in accounting for CESCO.

CESCO was previously consolidated but was changed to equity method accounting in the third quarter of 2001 when the Company was removed from management and lost operational control.

	Twelve Months Ended December 31, 2001		% of Revenue		Twelve Months Ended December 31, 2000		% of Revenue		% Change
	(in $millions)				(in $millions)

Contract Generation:
North America	$	368	50	%	$	360	52	%	2	%
South America	253		31	%	189		66	%	34	%
Caribbean	27		13	%	16		8	%	69	%
Europe/Africa	94		31	%	46		22	%	104	%
Asia	91		30	%	135		44	%	(33	)%
Total Contract Generation	$	833	35	%	$	746	44	%	12	%

Competitive Supply:
North America	$	131	26	%	$	145	29	%	(10	)%
South America	40		26	%	63		58	%	(41	)%
Caribbean	56		29	%	41		55	%	37	%
Europe/Africa	22		16	%	20		25	%	(10	)%
Asia	15		18	%	13		18	%	15	%
Total Competitive Supply	$	264	25	%	$	282	34	%	(6	)%

Total Non-Regulated Gross Margin	$	1,097	32	%	$	1,028	41	%	7	%

Non-regulated gross margin. Non-regulated gross margin remained relatively consistent at $1.0 billion in both 2001 and 2000. Non-regulated gross margin as a percentage of revenues decreased to 32% during 2001 from 41% in 2000 due to a decline in market prices in the U.S. which resulted in a decrease in competitive supply gross margin that was offset by an increase in contract generation gross margin. Excluding businesses acquired or that commenced operations in 2001 or 2000, non-regulated gross margin decreased 13% to $0.9 billion in 2001.

Contract Generation

Contract generation gross margin increased $87 million, or 12%, to $ 833 million in 2001 from $746 million in 2000. Contract generation gross margin increased in all geographic regions except Asia. The contract generation gross margin as a percentage of revenues decreased to 35% in 2001 from 44% in 2000. In South America, contract generation gross margin increased $64 million and was 31% of revenues. The increase is due to the acquisition of Gener offset by a decline at Tiete from the rationing of electricity in Brazil. In North America, contract generation gross margin increased $8 million and was 50% of revenues. The increase is due to improvements at Shady Point and Beaver Valley partially offset by a decrease at Thames from the contract buydown. In Europe/Africa, contract generation gross margin increased $48 million and was 31% of revenues. The increase is due primarily to our additional ownership interest in Kilroot and the acquisition of Ebute in Nigeria. In Asia, contract generation gross margin decreased $44 million and was 30% of revenues. The decrease is due mainly to additional bad debt provisions at Jiaozuo, Hefei and Aixi in China. The decrease in contract generation gross margin as a percentage of revenue is due to the acquisition of generation businesses with overall gross margin percentages lower than the overall portfolio of generation businesses. As a percentage of sales, contract generation gross margin declined in North America, South America and Asia, and increased in Europe/Africa and the Caribbean.

Competitive Supply

The competitive supply gross margin decreased $18 million, or 6%, to $264 million in 2001 from $282 million in 2000. The overall decrease is due to declines in North America and South America that were partially offset by slight increases in the Caribbean, Europe/Africa and Asia. The competitive supply gross margin as a percentage of revenues decreased to 25% in 2001 from 34% in 2000. In South America, competitive supply segment gross margin decreased $23 million and was 26% of revenues due to declines at several of our businesses in Argentina. In Europe/Africa, competitive supply segment gross margin increased $2 million and was 16% of revenues. In North America, competitive supply segment gross margin decreased $14 million and was 26% of revenues. The decrease was due to decreases at Somerset in New York and Deepwater in Texas. In the Caribbean, the competitive supply gross margin increased $15 million and was 29% of revenues. The increase is due primarily to the acquisition of Chivor offset by lower margin at Panama. As a percentage of sales, competitive supply gross margin declined in all regions except Asia where it remained relatively flat.

Selling, general and administrative expenses. Selling, general and administrative expenses increased $38 million, or 46%, to $120 million in 2001 from $82 million in 2000. Selling, general and administrative expenses as a percentage of revenues was 2% in 2001 and 2% in 2000. The overall increase in selling, general and administrative expenses was due to increased development activities.

Severance and transaction costs. During the first quarter of 2001, the Company incurred approximately $94 million of transaction and contractual severance costs related to the acquisition of IPALCO. During the third quarter of 2001, the Company recorded an additional $37 million in contractual severance costs related to the IPALCO transaction.

Interest expense. Interest expense increased $292 million, or 28%, to $1,342 million in 2001 from $1,050 million in 2000. Interest expense as a percentage of revenues was 20% in 2001 and 2000. Interest expense increased overall primarily due to interest expense at new businesses, additional corporate interest expense arising from senior debt issued during 2001 to finance new investments and mark-to-market losses on interest rate related derivative instruments. In December 2002, the Company refinanced $2.1 billion of bank debt and debt securities at terms less favorable than the original debt. As a result, the amount of interest expense recorded in future periods is expected to increase.

Interest income. Interest income decreased $3 million, or 2%, to $178 million in 2001 from $181 million in 2000. Much of the decrease occurred at Thames due to receiving payment of the contract receivable from Connecticut Light and Power, plus generally lower interest rates in 2001.

Other income. Other income increased $59 million, or 115%, to $110 million in 2001 from $51 million in 2000. See Note 16 to the consolidated financial statements for an analysis of other income.

Other expense. Other expense increased $7 million, or 13%, to $59 million in 2001 from $52 million in 2000. See Note 16 to the consolidated financial statements for an analysis of other expense.

Foreign currency transaction losses. Foreign currency transaction losses increased $6 million, or 60%, to $16 million in 2001 from $10 million in 2000. Foreign currency transaction losses increased primarily due to devaluations in Argentina, offset by income received on foreign currency forward contracts.

Equity in pre-tax (losses) earnings of affiliates. Equity in pre-tax earnings of affiliates decreased $299 million, or 63%, to $176 million in 2001 from $475 million in 2000. The overall decrease in equity in earnings is due primarily to declines in equity in earnings of Brazilian large utility affiliates which

primarily resulted from the devaluation of the Brazilian Real, as well as the rationing of electricity in Brazil.

Equity in earnings of large utilities decreased $282 million to $144 million in 2001 from $426 million in 2000 and included non-cash Brazilian foreign currency transaction losses on a pretax basis of $210 million and $64 million in 2001 and 2000, respectively. Our distribution concession contracts in Brazil provide for annual tariff adjustments based upon changes in the local inflation rates and generally significant devaluations are followed by increased local currency inflation. However, because of the lack of adjustment to the current exchange rate, the in arrears nature of the respective adjustment to the tariff or the potential delays or magnitude of the resulting local currency inflation of the tariff, the future results of operations of the company’s distribution companies in Brazil could be adversely affected by the continued devaluation of the Brazilian Real.

Equity in earnings of growth distribution affiliates decreased to an expense of $13 million in 2001 from $0 million in 2000. The decrease is primarily due to the change in the way in which we account for our investment in CESCO. CESCO was previously consolidated but was changed to equity method during 2001 when the Company was removed from management and the Board of Directors.

Equity in earnings of contract generation affiliates increased to $54 million in 2001 from $49 million in 2000. The increase is due primarily to contributions from equity affiliates of Gener and the contribution from Itabo offset by a decrease in Kilroot related to the Company’s purchase of an additional interest thereby making it a consolidated subsidiary.

Equity in earnings of competitive supply affiliates decreased to expense of $9 million in 2001 from $0 million in 2000. The decrease is due to losses incurred at Infovias, a Brazilian company.

Income taxes. Income taxes (including income taxes on equity in earnings and minority interests) decreased $92 million to $276 million in 2001 from $368 million in 2000. The Company’s effective tax rate was 40% in 2001 and 35% in 2000. The increase in the tax rate was primarily due to additional taxes on foreign earnings.

Minority interest (income) expense. Minority interest expense (before income taxes) decreased $21 million, or 17%, to $104 million in 2001 from $125 million in 2000. Minority interest expense decreased in contract generation and competitive supply. Minority interest income decreased in growth distribution, and large utilities minority interest expense increased.

Large utilities minority interest expense increased $3 million to $88 million in 2001 from $85 million in 2000. Increased expense at EDC was almost entirely offset by declines at CEMIG.

Growth distribution minority interest income decreased $10 million to $16 million in 2001 from $26 million in 2000. The decrease was mainly due to the deconsolidation of CESCO, and sharing the effect of a full year’s results of CAESS with our minority partners.

Contract generation minority interest expense decreased $14 million to $22 million in 2001 from $36 million in 2000. The decrease in contract generation minority interest expense was due primarily to lower contributions from Tiete and Jiaozuo.

Competitive supply minority interest expense decreased $21 million to $9 million in 2001 from $30 million in 2000. The decrease in competitive supply minority interest expense is due primarily to lower contributions from Panama and CTSN.

Discontinued operations. Loss from operations of discontinued businesses, net of tax, were $140 million and $104 million, respectively, in 2001 and 2000. During 2001, the Company discontinued certain of its operations, including Power Direct, Ib Valley, Power Northern, Geoutilities, TermoCandelaria and several telecommunications businesses in the United States and Brazil. Subsequently, during 2002, the Company discontinued certain of its operations, including Fifoots, CILCORP, NewEnergy, Eletronet, Mt. Stuart, Ecogen, two Altai businesses, Mountainview and Kelvin. During 2003, the Company discontinued certain of its operations including, Barry, Haripur, Meghnaghat and Drax. The Company closed the sale of both CILCORP and Mt. Stuart in January 2003, the sale of Ecogen in February 2003. All of the operations for these businesses and the related write offs from dispositions in 2001 are reported in this line item. Pursuant to SFAS No. 144, if any of these businesses are not sold or disposed of within one year of the date they were classified as discontinued operations they must be reclassified as continuing operations.

Net income. Net income decreased $522 million to $273 million in 2001 from $795 million in 2000. The overall decrease in net income is due to decreased gross margin from competitive supply due to lower market prices in the United Kingdom and the decline in the Brazilian Real during 2001 resulting in foreign currency transaction losses of approximately $210 million. Additionally the Company recorded severance and transaction costs related to the IPALCO pooling-of-interest transaction and a loss from discontinued operations of $220 million. This decrease was partially offset by increased gross margins from large utilities, growth distribution and contract generation.

Off balance sheet arrangements

As of December 31, 2002, the Company’s known contractual obligations are as follows, excluding discontinued operations and businesses held for sale.

	Payment due by period (amounts in millions)
Contractual obligations	Total		Less than 1 year		1 to 3 years		3 to 5 years		Over 5 years

Indebtedness (excluding interest)	$	19,723	$	3,317	$	4,704	$	2,931	$	8,771
Trust preferred securities (excluding dividends)	$	978	—		—		—		$	978
Construction commitments	$	65	$	65	—		—		—
Operating lease obligations	$	1,719	$	86	$	155	$	143	$	1,335
Purchase obligations	$	14,991	$	1,654	$	2,512	$	1,433	$	9,392
Total	$	37,415	$	5,138	$	7,374	$	4,518	$	20,385

Please refer to Note 11 to the consolidated financial statements for additional disclosure regarding these obligations.

Parent company liquidity

While the Company believes that its sources of liquidity will be adequate to meet its needs through the end of 2003, this belief is based on a number of material assumptions, including, without limitation, assumptions about exchange rates, power market pool prices, the ability of its subsidiaries to pay dividends and the timing and amount of asset sale proceeds. In addition, there can be no assurance that these sources will be available when needed or that its actual cash requirements will not be greater than anticipated.

The parent company’s non-contingent contractual obligations are set forth below:

	Payment due by period (amounts in millions)
Non-contingent contractual obligation	Less than 1 year		1 to 3 years		Over 3 years		Total

Indebtedness (excluding interest)	$	26	$	1,810	$	3,968	$	5,804
Trust preferred securities (excluding dividends)	—		—		$	978	$	978
Construction commitments	$	65	—		—		$	65
Total	$	91	$	1,810	$	4,946	$	6,847

The parent company’s contingent contractual obligations are set forth below (in millions, except for number of agreements):

Contingent contractual obligations	Amount		Number of Agreements	Exposure Range for Each Agreement	Recorded On Balance Sheet

Guarantees	$	652	52	<$1 - $100	$	273
Letters of credit-under the Revolver	$	104	14	<$1 - $36	$	51
Letters of credit-outside the Revolver	$	109	5	<$1 - $84	$	84
Surety bonds	$	6	6	<$1 - $3	—
Total	$	871	77		$	408

FINANCIAL POSITION AND CASH FLOWS

Consolidated cash flows

At December 31, 2002, AES had a consolidated net working capital deficit of $2.2 billion as compared to negative working capital of ($236) million at the end of 2001. The decrease in net working capital was due primarily to an increase in the current portion of debt, accounts payable, and accrued and other liabilities, partially offset by an increase in other current assets. Cash and short-term investments were $1.0 billion at December 31, 2002. Included in the net working capital deficit is approximately $3.3 billion from the current portion of long-term debt. The Company expects to refinance a significant amount of the current portion of long-term debt. There can be no guarantee that these refinancings will have terms as favorable as those currently in existence. There are some subsidiaries that issue short-term debt and commercial paper in the normal course of business and continually refinance these obligations.

Property, plant and equipment, net of accumulated depreciation, accounts for 54% of the Company’s total assets and was $18.4 billion at December 31, 2002. Net property, plant and equipment increased $677 million, or 4%, during 2002. The increase was due primarily to construction activities at the Company’s greenfield projects and the consolidation of Eletropaulo, offset by the reclassification of certain businesses to discontinued operations.

AES continuously monitors both actual and potential changes to environmental regulations and plans for the associated costs. As a result of such events, the Company expects to spend approximately $105 million in 2003 to comply with environmental laws and regulations and to raise our level of preparedness for future regulations that may be enacted. The Company expects to obtain third party financing for a portion of these capital expenditures. The planned 2003 capital expenditures include anticipated construction costs associated with new environmental standards imposed by the EPA relating to NOx emission reductions, as well as the installation of low NOx burners, additional monitoring equipment, and other environmental-related projects.

In total, the Company’s consolidated debt increased $1.1 billion, or 6%, to $19.7 billion at December 31, 2002. The increase is due primarily to the addition of debt held on the books of Eletropaulo which was consolidated during 2002, and borrowings used to fund the construction of the

Company’s greenfield projects. This increase was partially offset by the reclassification of certain businesses to discontinued operations.

At December 31, 2002, the Company had $797 million of cash and cash equivalents representing a increase of $37 million from December 31, 2001. The $1.4 billion provided by operating activities and the $172 million of cash raised by financing activities was used to fund the $1.6 billion of investing activities.

Cash flows provided by operating activities totaled $1.4 billion during 2002. The decrease in cash provided by operating activities during 2002 is due to the one-time collection of a contract prepayment in 2001, partially offset by improved cash flows from operations at several North American businesses. Net cash used in investing activities totaled $1.6 billion during 2002. The cash used in investing activities includes $2.1 billion for property additions, primarily representing new greenfield construction efforts. Net cash provided by financing activities was $172 million during 2002, which primarily consists of net borrowings.

Financial Statements and Supplementary Data

INDEPENDENT AUDITORS’ REPORT

To the Stockholders of The AES Corporation:

We have audited the accompanying consolidated balance sheets of The AES Corporation and subsidiaries (the Company) as of December 31, 2002 and 2001, and the related consolidated statements of operations, changes in stockholders’ equity (deficit), and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based on our audits. We did not audit the financial statements of C.A. La Electricidad de Caracas and Corporation EDC, C.A. and their subsidiaries (“EDC”), a majority-owned subsidiary, for the years ended December 31, 2001 and 2000, which statements reflect total assets constituting 9% of consolidated total assets as of December 31, 2001, total revenues constituting 11% and 8% of consolidated total revenues and total income from continuing operations constituting 51% and 14% of consolidated total income from continuing operations for 2001 and 2000, respectively. Those statements were audited by other auditors who have ceased operations and whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for EDC, is based solely on the report of such other auditors.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits, and the report of the other auditors, provide a reasonable basis for our opinion.

In our opinion, based on our audits and the report of the other auditors, such consolidated financial statements present fairly, in all material respects, the financial position of The AES Corporation and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 10 to the financial statements, the Company changed its method of accounting for derivative instruments and hedging activities effective January 1, 2001 to conform with Statement of Financial Accounting Standards No. 133. Also, as discussed in Note 10 to the financial statements, the Company changed its method of accounting for certain contracts for the purchase or sale of electricity effective April 1, 2002 to conform with Derivative Implementation Group Issue C-15. As discussed in Note 6 to the financial statements, the Company changed its method of accounting for goodwill and other intangible assets effective January 1, 2002 to conform with Statement of Financial Accounting Standards No. 142.

Deloitte & Touche LLP

McLean, VA

February 12, 2003 (October 28, 2003 as to Note 4,

March 21, 2003 as to Note 9, and October 31, 2003 as to Note 11)

Due to the Company’s inability to obtain an accountants’ report from Porta, Cachafeiro, Laría Y Asociados (a Member Firm of Andersen), we have included this copy of their latest signed and dated accountants’ report on the financial position and results of operations of C.A. La Electricidad de Caracas and Corporación EDC, C.A. and their subsidiaries as of December 31, 2001 and 2000, the results of their operations and their cash flows for the year ended December 31, 2001, and the results of their operations and cash flows for the period from June 1 through December 31, 2000. This report is a copy of the original and has not been reissued by Porta, Cachafeiro, Laría Y Asociados. Porta, Cachafeiro, Laría Y Asociados has not provided a consent to the inclusion of its report in this Form 10-K. See Exhibit 23.2 for additional information regarding our inability to obtain this consent and the limitations imposed on investors as a result.

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Stockholders and the Board of Directors of

C.A. La Electricidad de Caracas and Corporación EDC, C.A.:

We have audited the accompanying combined balance sheets of C.A. La Electricidad de Caracas and Corporación EDC, C.A. and their Subsidiaries (Venezuelan corporations), translated into U.S. dollars, as of December 31, 2001 and 2000, and the related translated combined statements of income, stockholders’ investment and cash flows for the year ended December 31, 2001 and for the period from June 1 through December 31, 2000. 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 in accordance with auditing standards generally accepted in the 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

These translated combined financial statements have been prepared for use in the preparation of the consolidated financial statements of AES Corporation and, accordingly, they translate the assets, liabilities, stockholders’ investment, revenues and expenses of C.A. La Electricidad de Caracas and Corporación EDC, C.A. and their Subsidiaries for that purpose. The translated combined financial statements have not been prepared for use by other parties and may not be appropriate for such use.

In our opinion, the translated financial statements referred to above present fairly, in all material respects and for the purpose described in the preceding paragraph, the financial position of C.A. La Electricidad de Caracas and Corporación EDC, C.A. and their Subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for the year ended December 31, 2001 and for the period from June 1 through December 31, 2000, in conformity with accounting principles generally accepted in the United States.

Porta, Cachafeiro, Laría

Y Asociados

A Member Firm of Andersen

Hector L. Gutierrez D.

Public Accountant CPC N° 24,321

Caracas, Venezuela

January 18, 2002 (except with respect
to the matter discussed in Note 18, as
to which the dates are February 20, 2002)

THE AES CORPORATION

CONSOLIDATED BALANCE SHEETS

DECEMBER 31, 2002 AND 2001

	2002			2001
	(Amounts in Millions, Except Shares and Par Value)
ASSETS
Current Assets:
Cash and cash equivalents	$	797		$	760
Restricted cash	160			357
Short-term investments	177			215
Accounts receivable - net of reserves of $375-2002; $206 -2001	1,078			1,069
Inventory	366			453
Receivable from affiliates	25			10
Deferred income taxes - current	130			244
Prepaid expenses	64			145
Other current assets	923			400
Current assets of discontinued operations and businesses held for sale	629			1039
Total current assets	4,349			4,692
Property, Plant and Equipment:
Land	699			538
Electric generation and distribution assets	18,313			15,860
Accumulated depreciation and amortization	(4,049		)	(2,983		)
Construction in progress	3,211			4,108
Property, plant, and equipment — net	18,174			17,523
Other Assets:
Deferred financing costs – net	397			333
Project development costs	15			66
Investments in and advances to affiliates	678			3,031
Debt service reserves and other deposits	508			433
Goodwill – net	1,388			2,367
Deferred income taxes – noncurrent	939			—
Long-term assets of discontinued operations and businesses held for sale	6111			7,632
Other assets	1,671			735
Total other assets	11,707			14,597
Total	$	34,230		$	36,812
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current Liabilities:
Accounts payable	$	1,107		$	700
Accrued interest	362			260
Accrued and other liabilities	1,118			622
Current liabilities of discontinued operations and businesses held for sale	607			902
Recourse debt - current portion	26			488
Non-recourse debt - current portion	3,291			1,956
Total current liabilities	6,511			4,928
Long-Term Liabilities:
Non-recourse debt	10,628			11,303
Recourse debt	5,778			4,913
Deferred income taxes	981			627
Pension liabilities	1,166			232
Long-term liabilities of discontinued operations and businesses held for sale	5,127			5,044
Other long-term liabilities	2,584			1718
Total long-term liabilities	26,264			23,837
Minority Interest (including discontinued operations of $41 - 2002; $126 - 2001)	818			1,530
Commitments and Contingencies (Note 11)	—			—
Company-Obligated Convertible Mandatorily Redeemable Preferred Securities of Subsidiary Trusts Holding Solely Junior Subordinated Debentures of AES	978			978
Stockholders’ Equity (Deficit):
Preferred stock, no par value - 50 million shares authorized; none issued	—			—
Common stock, $.01 par value - 1,200 million shares authorized for 2002 and 2001, 776 million issued and 558 million outstanding in 2002, 645 million issued and 533 million outstanding in 2001	6			5
Additional paid-in capital	5,312			5,225
Retained earnings (accumulated deficit)	(700		)	2,809
Accumulated other comprehensive loss	(4,959		)	(2,500		)
Total stockholders’ (deficit) equity	(341		)	5,539
Total	$	34,230		$	36,812

See notes to consolidated financial statements.

THE AES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000

	2002			2001			2000
	(Amounts in Millions, Except Shares and Par Value)
Revenues
Regulated	$	4,254		$	3,201		$	2,621
Non-regulated	3,388			3,430			2,536
Total Revenues	7,642			6,631			5,157
Cost of sales
Regulated	(3,550		)	(2,319		)	(2,039		)
Non-regulated	(2,147		)	(2,333		)	(1,508		)
Total cost of sales	(5,697		)	(4,652		)	(3,547		)
Selling, general and administrative expenses	(112		)	(120		)	(82		)
Severance and transaction costs	—			(131		)	(79		)

Interest expense	(1,761		)	(1,342		)	(1,050		)
Interest income	276			178			181
Other income	133			110			51
Other expense	(77		)	(59		)	(52		)

(Loss) gain on sale of investments and asset impairment expense	(473		)	18			140
Goodwill impairment expense	(612		)	—			—
Foreign currency transaction losses	(484		)	(16		)	(10		)
Equity in pre-tax (loss) earnings of affiliates	(207		)	176			475
(LOSS) INCOME BEFORE INCOME TAXES AND MINORITY INTEREST	(1,372		)	793			1,184
Income tax expense	297			276			368
Minority interest (income) expense	(34		)	104			125
(LOSS) INCOME FROM CONTINUING OPERATIONS	(1,635		)	413			691
(Loss) Income from operations of discontinued businesses (net of income tax benefit of $414, $80 and $5, respectively)	(1,528)			(140)			104
(LOSS) INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE	(3,163		)	273			795
Cumulative effect of change in accounting principle (net of income tax benefit of $72)	(346		)	—			—
Net (loss) income	$	(3,509	)	$	273		$	795
BASIC (LOSS) EARNINGS PER SHARE:
(Loss) income from continuing operations	$	(3.03	)	$	0.78		$	1.43
Discontinued operations	(2.83		)	(0.26		)	0.23
Cumulative effect of accounting change	(0.65		)	—			—
BASIC (LOSS) EARNINGS PER SHARE	$	(6.51	)	$	0.52		$	1.66
DILUTED (LOSS) EARNINGS PER SHARE:
(Loss) income from continuing operations	$	(3.03	)	$	0.77		$	1.39
Discontinued operations	(2.83		)	(0.26		)	(0.20		)
Cumulative effect of accounting change	(0.65		)	—			—
DILUTED (LOSS) EARNINGS PER SHARE	$	(6.51	)	$	0.51		$	1.59

See notes to consolidated financial statements.

THE AES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000

	2002			2001			2000
	(Amounts in Millions)
OPERATING ACTIVITIES:
Net (loss) income	$	(3,509	)	$	273		$	795
Adjustments to net (loss) income:
Cumulative effect of change in accounting principle	418			—			—
Depreciation and amortization — continuing and discontinued operations	837			859			697
Loss (gain) from sale of investments and asset impairment expense	1,600			(18		)	(143		)
Goodwill impairment expense	612			—			—
Loss on disposal and impairment write-down associated with discontinued operations	784			193			27
Provision for deferred taxes	(315		)	47			(2		)
Minority interest (earnings) expense	(34		)	103			120
Foreign currency transaction losses	456			30			4
Loss (earnings) of affiliates, net of dividends	285			(140		)	(320		)
Other	16			(61		)	(56		)
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable	128			712			(270		)
Decrease (increase) in inventory	129			(10		)	(56		)
Increase in prepaid expenses and other current assets	(301		)	(34		)	(156		)
Decrease (increase) in other assets	(160		)	295			(132		)
(Decrease) increase in accounts payable	286			(125		)	257
(Decrease) increase in accrued interest	98			(148		)	126
Increase (decrease) in accrued and other liabilities	73			(368		)	(225		)
Increase (decrease) in other liabilities	41			83			(160		)
Net cash provided by operating activities	1,444			1,691			506
INVESTING ACTIVITIES:
Property additions	(2,116		)	(3,173		)	(2,226		)
Acquisitions-net of cash acquired	(35		)	(1,365		)	(1,818		)
Increase in cash from Eletropaulo share swap	162			—			—
Proceeds from the sales of assets	375			505			234
Sale of short-term investments	101			670			81
Purchase of short-term investments	(166		)	(649		)	(96		)
Proceeds from sale of available-for-sale securities	92			59			114
Affiliate advances and equity investments	(29		)	(133		)	(515		)
Decrease (increase) in restricted cash	25			832			(1,110		)
Project development costs	(22		)	(105		)	(96		)
Debt service reserves and other assets	23			45			(101		)
Net cash used in investing activities	(1,590		)	(3,314		)	(5,533		)
FINANCING ACTIVITIES:
Borrowings (repayments) under the revolving credit facilities, net	158			(70		)	(195		)
Issuance of non-recourse debt and other coupon bearing securities	3,481			5,935			7,081
Repayments of non-recourse debt and other coupon bearing securities	(3,389		)	(4,015		)	(2,831		)
Payments for deferred financing costs	(67		)	(153		)	(136		)
Distributions to minority interests, net	(11		)	(70		)	(54		)
Issuance of common stock, net	—			14			1,508
Common stock dividends paid	—			(15		)	(55		)
Net cash provided by financing activities	172			1,626			5,318
Effect of exchange rate changes on cash	(81		)	(31		)	(34		)
Total (decrease) increase in cash and cash equivalents	(55		)	(28		)	257
(Increase) decrease in cash and cash equivalents of discontinued operations and businesses held for sale	91			74			(52)
Cash and cash equivalents, beginning	760			714			509
Cash and cash equivalents, ending	$	797		$	760		$	714
SUPPLEMENTAL DISCLOSURES:
Cash payments for interest-net of amounts capitalized	$	2,007		$	1,846		$	1,191
Cash payments for income taxes-net of refunds	(3		)	254			216
SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:
Common stock issued for acquisitions	—			511			67
Common stock issued for debt retirement	73			—			—
Liabilities assumed in purchase transactions	—			1,362			2,098
Liabilities consolidated in Eletropaulo transaction	4,907			—			—
Conversion of AES Trust I and AES Trust II (see Note 12)	—			—			550

See notes to consolidated financial statements.

THE AES CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY (DEFICIT)

YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000

				Additional Paid-In Capital			Retained Earnings (Accumulated Deficit)			Accumulated Other Comprehensive Loss			Treasury Stock			Comprehensive

	Common Stock
	Shares	Amount
	(Amounts in Millions)
Balance at December 31, 1999	453.4	$	4	$	3,052		$	1,811		$	(995	)	$	(557	)	$	(295	)

Net income	—	—		—			795			—			—			$	795
Foreign currency translation adjustment (net of income tax benefit of $20)	—	—		—			—			(575		)	—			(575		)
Reclassification to earnings of realized gains on marketable securities (net of income tax benefit of $65)	—	—		—			—			(107		)	—			(107		)
Minimum pension liability adjustment (net of income tax benefit of $1)	—	—		—			—			(2		)	—			(2		)
Comprehensive income																$	111

Dividends declared	—	—		—			(55		)	—			—
Issuance of common stock through public offerings and Tecon conversions	59.2	1		1,946			—			—			—
Issuance of common stock pursuant to acquisitions	1.3	—		67			—			—			—
Issuance of common stock under benefit plans and exercise of stock options and warrants	7.8	—		50			—			—			50
Tax benefit associated with the exercise of options	—	—		57			—			—			—
Balance at December 31, 2000	521.7	5		5,172			2,551			(1,679		)	(507		)
Cumulative effect of adopting SFAS No. 133 on January 1, 2001 (net of income tax benefit of $50)	—	—		—			—			(93		)	—			$	(93	)
Net income	—	—		—			273			—			—			273
Foreign currency translation adjustment (net of reclassification to earnings of $12, net of tax, for the sale or write off of investments in foreign entities and an income tax benefit of $38)	—	—		—			—			(636		)	—			(636		)
Unrealized losses on marketable securities (no income tax effect)	—	—		—			—			(48		)	—			(48		)
Minimum pension liability adjustment (net of income tax benefit of $10)	—	—		—			—			(16		)	—			(16		)
Change in derivative fair value (including a reclassification to earnings of ($32) million, net of tax, and an income tax benefit of $11)	—	—		—			—			(28		)	—			(28		)
Comprehensive loss																$	(548	)

Dividends declared	—	—		—			(15		)	—			—
Issuance of common stock pursuant to acquisitions	9.4	—		511			—			—
Retirement of treasury stock	—	—		(507		)	—			—			507
Issuance of common stock under benefit plans and exercise of stock options and warrants	2.1	—		34			—			—			—
Tax benefit associated with the exercise of options	—	—		15			—			—			—
Balance at December 31, 2001	533.2	$	5	$	5,225		$	2,809		$	(2,500	)	$	—

Net loss	—	—		—			(3,509		)	—			—			$	(3,509	)
Foreign currency translation adjustment (net of reclassification to earnings of $65, net of tax, for the sale or write off of investments in foreign entities (no income tax effect)	—	—		—			—			(1,677		)	—			(1,677		)
Realized losses on marketable securities (no income tax effect)	—	—		—			—			48			—			48
Minimum pension liability adjustment (net of income tax benefit of $229)	—	—		—			—			(553		)	—			(553		)
Change in derivative fair value (including a reclassification to earnings of ($106) million, net of tax, and an income tax benefit of $41)	—	—		—			—			(277		)	—			(277		)

Comprehensive loss																$	(5,968	)

Issuance of common stock in exchange for cancellation of debt	21.6	1		73			—			—			—
Issuance of common stock under benefit plans and exercise of stock options and warrants	3.1	—		14			—			—			—
Balance at December 31, 2002	557.9	$	6	$	5,312		$	(700	)	$	(4,959	)	$	—

See notes to consolidated financial statements.

THE AES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, 2001 AND 2000

1. GENERAL AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The AES Corporation and its subsidiaries and affiliates, (collectively, “AES” or “the Company”) is a global power company primarily engaged in owning and operating electric power generation and distribution businesses in many countries around the world. The revenues and cost of sales of our large utilities and growth distribution segments are reported as regulated, and the revenues and cost of sales of our contract generation and competitive supply segments are reported as non-regulated.

The consolidated financial statements have been prepared to give retroactive effect to the merger with IPALCO Enterprises, Inc. (“IPALCO”), which has been accounted for as a pooling of interests as more fully discussed in Note 3.

PRINCIPLES OF CONSOLIDATION—The consolidated financial statements of the Company include the accounts of The AES Corporation, its subsidiaries, and controlled affiliates. Investments, in which the Company has the ability to exercise significant influence but not control, are accounted for using the equity method. Intercompany transactions and balances have been eliminated. A loss in value of an equity method investment which is other than a temporary decline is recognized in earnings as an impairment.

CASH AND CASH EQUIVALENTS—The Company considers unrestricted cash on hand, deposits in banks, certificates of deposit, and short-term marketable securities with an original maturity of three months or less to be cash and cash equivalents.

INVESTMENTS—Securities that the Company has both the positive intent and ability to hold to maturity are classified as held-to-maturity and are carried at historical cost. Other investments that the Company does not intend to hold to maturity are classified as available-for-sale or trading. Unrealized gains or losses on available-for-sale investments are recorded as a separate component of stockholders’ equity. Investments classified as trading are marked to market on a periodic basis through the statement of operations. Interest and dividends on investments are reported in interest income. Gains and losses on sales of investments are recorded using the specific identification method. Short-term investments consist of investments with original maturities in excess of three months but less than one year. Debt service reserves and other deposits are treated as non-current assets (see Note 8).

INVENTORY—Inventory, valued at the lower of cost or market (first in, first out method) consists of the following (in millions):

	December 31,
	2002			2001

Coal, fuel oil, and other raw materials	$	281		$	334
Spare parts and supplies	217			292
Total	498			626
Less: Inventory of discontinued operations	(132		)	(173		)
	$	366		$	453

PROPERTY, PLANT, AND EQUIPMENT—Property, plant, and equipment is stated at cost. The cost of renewals and betterments that extend the useful life of property, plant and equipment are also capitalized. Depreciation, after consideration of salvage value, is computed using the straight-line method over the estimated composite useful lives of the assets. Depreciation expense stated as a

percentage of average cost of depreciable property, plant and equipment was, on a composite basis, 3.93%, 3.65% and 3.76% for the years ended December 31, 2002, 2001 and 2000, respectively.

The components of our electric generation and distribution assets and the related rates of depreciation are as follows:

	Composite Rate		Useful Life

Generation and Distribution Facilities	2.0% - 10.0	%	10 - 50 yrs.
Other Buildings	2.5% - 5.0	%	20 - 40 yrs.
Leasehold Improvements	3.3% - 10.0	%	10 - 30 yrs.
Furniture and Fixtures	14.3% - 50.0	%	2 - 7 yrs.

Maintenance and repairs are charged to expense as incurred. Emergency and rotable spare parts inventories are included in electric generation and distribution assets and are depreciated over the useful life of the related components.

CONSTRUCTION IN PROGRESS—Construction progress payments, engineering costs, insurance costs, salaries, interest, and other costs relating to construction in progress are capitalized during the construction period. Construction in progress balances are transferred to electric generation and distribution assets when each asset is ready for its intended use. Interest capitalized during development and construction totaled $ 287 million, $ 283 million, and $ 215 million in 2002, 2001, and 2000, respectively. Recoveries of liquidating damages from construction delays are recorded as a reduction in the related projects’ construction costs.

GOODWILL—The Company recognizes as goodwill the excess of the cost of an acquired entity over the net amount assigned to assets acquired and liabilities assumed. The Company evaluates goodwill for impairment on an annual basis and whenever events or changes in circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying value. The Company’s annual impairment testing date is October 1^st. Prior to January 1, 2002, goodwill was amortized on a straight-line basis over the estimated benefit period, which ranged from 10 to 40 years, and total accumulated amortization amounted to $190 million at December 31, 2001. As of January 1, 2002, goodwill is no longer amortized.

LONG-LIVED ASSETS—In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting for the Impairment or Disposal of Long-lived Assets,” the Company evaluates the impairment of long-lived assets based on the projection of undiscounted cash flows whenever events or changes in circumstances indicate that the carrying amounts of such assets may not be recoverable. In the event such cash flows are not expected to be sufficient to recover the recorded value of the assets, the assets are written down to their estimated fair values (see Note 5).

DEFERRED FINANCING COSTS—Financing costs are deferred and amortized over the related financing period using the effective interest method or the straight- line method when it does not differ materially from the effective interest method. Deferred financing costs are shown net of accumulated amortization of $ 175 million and $138 million as of December 31, 2002 and 2001, respectively.

PROJECT DEVELOPMENT COSTS—The Company capitalizes the costs of developing new construction projects after achieving certain project-related milestones which indicate that the project’s completion is probable. These costs represent amounts incurred for professional services, permits, options, capitalized interest, and other costs directly related to construction. These costs are transferred to construction in progress when significant construction activity commences, or expensed at the time the Company determines that development of a particular project is no longer probable. The continued capitalization of such costs is subject to ongoing risks related to successful completion, including those related to government approvals, siting, financing, construction, permitting, and contract compliance.

INCOME TAXES—The Company follows SFAS No. 109, “Accounting for Income Taxes.” Under the asset and liability method of SFAS No. 109, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities, and their respective income tax bases.

FOREIGN CURRENCY TRANSLATION—A business’s functional currency is the currency of the primary economic environment in which the business operates and is generally the currency in which the business generates and expends cash. Subsidiaries and affiliates whose functional currency is other than the U.S. dollar translate their assets and liabilities into U.S. dollars at the current exchange rates in effect at the end of the fiscal period. The revenue and expense accounts of such subsidiaries and affiliates are translated into U.S. dollars at the average exchange rates that prevailed during the period. The translation differences that result from this process, and gains and losses on intercompany foreign currency transactions which are long-term in nature, and which the Company does not intend to settle in the foreseeable future, are shown in accumulated other comprehensive loss in the stockholders’ equity section of the balance sheet. Gains and losses that arise from exchange rate fluctuations on transactions denominated in a currency other than the functional currency are included in determining net income. For subsidiaries operating in highly inflationary economies, the U.S. dollar is considered to be the functional currency, and transaction gains and losses are included in determining net income.

During 2002, the Brazilian Real experienced a significant devaluation relative to the U.S. dollar, declining from 2.41 Reais to the U.S. dollar at December 31, 2001 to 3.53 Reais at December 31, 2002. Also, during 2001, the Brazilian Real experienced a significant devaluation relative to the U.S. dollar declining from 1.96 Reais to the U.S. dollar at December 31, 2000 to 2.41 Reais to the dollar at December 31, 2001. This continued devaluation resulted in significant foreign currency translation and transaction losses. The Company recorded $357 million, $210 million, and $64 million before income taxes of non-cash foreign currency transaction losses on the U.S. dollar denominated debt at its investments in Brazilian businesses during 2002, 2001 and 2000, respectively. The 2002 amount of $357 million is reported as $317 million of foreign currency transaction losses, $43 million of related minority interest (income) expense, and $83 million of equity in pre-tax (loss) earnings of affiliates on the consolidated statement of operations that primarily arises from Eletropaulo which was consolidated beginning in February 2002. The 2001 and 2000 amounts of $210 million and $64 million, respectively, are recorded in equity in pre-tax (loss) earnings of affiliates in the accompanying consolidated statements of operations because Eletropaulo was accounted for as an equity method investment during those years. The cash flow impacts of these losses will be realized when the principal balance of the related debt is paid or subsequent refinancing of such principal are paid. In Brazil, the Company has total investments at December 31, 2002 in large utilities businesses of approximately negative $1.5 billion, in growth distribution businesses of approximately $146 million and in contract generation businesses of approximately $298 million, which are net of foreign currency translation losses and other comprehensive losses arising from minimum pension obligations.

changed the functional currency for its businesses in Argentina to the peso effective January 1, 2002. The Argentine peso experienced a significant devaluation relative to the U.S. dollar during 2002. The Company recorded pre-tax foreign currency transaction losses on the U.S. dollar denominated net liabilities of its Argentine subsidiaries during 2002 of approximately $143 million representing a decline in the Argentine peso to the U.S. dollar from 1.65 used at December 31, 2001 to 3.32 at December 31, 2002. In Argentina, the Company has total investments at December 31, 2002 in growth distribution businesses of approximately negative $61 million and in competitive supply businesses of approximately $141 million. These investment amounts are net of foreign currency translation losses. In combination these circumstances create significant uncertainty surrounding the performance, cash flow and potential for profitability of the electricity industry in Argentina, including the Argentine subsidiaries of AES.

In February 2002, the Venezuelan government decided not to continue support of the Venezuelan currency. As a result, the Venezuelan Bolivar has experienced significant devaluation relative to the U.S. dollar during 2002. EDC, a subsidiary of the company, uses the U.S. dollar as its functional currency. A portion of its debt is denominated in the Venezuelan Bolivar, and as of December 31, 2002, EDC has net Venezuelan Bolivar monetary liabilities thereby creating the foreign currency gains when the Venezuelan Bolivar devalues. During 2002, the Company recorded pre-tax foreign currency transaction gains of approximately $39 million, as well as $40 million of pre-tax mark to market gains on a foreign currency forward contract due to a decline in the Venezuelan Bolivar to the U.S. dollar exchange rate from 758 at December 31, 2001 to 1,403 at December 31, 2002. At December 31, 2002, the Company’s total investment in EDC, a large utility business, was approximately $1.8 billion, which is net of foreign currency translation losses.

REVENUE RECOGNITION AND CONCENTRATION—Electricity distribution revenues are reported as regulated. Revenues from the sale of energy are recognized in the period during which the sale occurs. The calculation of revenues earned but not yet billed is based on the number of days not billed in the month, the estimated amount of energy delivered during those days and the average price per customer class for that month. Revenues from the sale of electricity and steam generation are reported as non-regulated and are recorded based upon output delivered and capacity provided at rates as specified under contract terms or prevailing market rates. Revenues from power sales contracts entered into after 1991 with decreasing scheduled rates are recognized based on the output delivered at the lower of the amount billed or the average rate over the contract term. Several of the Company’s power plants rely primarily on one power sales contract with a single customer for the majority of revenues (see Note 11). No single customer accounted for 10% or more of revenues in 2002, 2001 or 2000. The prolonged failure of any of the Company’s customers to fulfill contractual obligations or make required payments could have a substantial negative impact on AES’s revenues and profits.

Within our regulated businesses, sales of purchased power amounted to approximately $1.3 billion, $1.5 billion and $1.1 billion for the years ended December 31, 2002, 2001 and 2000, respectively. The related power purchased by the regulated businesses amounted to approximately $921 million, $919 million and $594 million for the years ended December 31, 2002, 2001 and 2000, respectively. Our non-regulated businesses consist primarily of generation businesses, and therefore, do not generally purchase power for resale.

REGULATION—The Company has investments in large utilities and growth distribution businesses located in the United States and certain foreign countries that are subject to regulation by the applicable regulatory authority. Our distribution businesses generally operate in markets that are subject to electricity price regulation as compared with regulation based solely on the cost of the electricity or the allowed rate of return on a specific distribution company’s assets or net assets. For the regulated portion of these businesses, the Company capitalizes incurred costs as deferred regulatory assets when there is a probable expectation that future revenue equal to the costs incurred will be billed and collected as a direct result of the inclusion of the costs in an increased tariff set by the regulator or as permitted under the electricity sales concession for that business. The deferred

regulatory asset is eliminated when the Company collects the related costs through billings to customers, or when recovery is no longer probable. Regulators in the respective jurisdictions typically perform a tariff review for the distribution companies on an annual basis. If a regulator excludes all or part of a cost from recovery, that portion of the deferred regulatory asset is impaired and is accordingly reduced to the extent of the excluded cost. The Company has recorded deferred regulatory assets of $627 million and $390 million at December 31, 2002, and 2001, respectively, that it expects to pass through to its customers in accordance with and subject to regulatory provisions. These amounts include $76million and $71 million of assets classified as discontinued operations at December 31, 2002 and 2001, respectively. The deferred regulatory assets at entities, which are controlled and consolidated by the Company, are recorded in other assets on the consolidated balance sheets.

The electricity industry in Brazil reached a critical point in 2001 as a result of a series of regulatory, meteorological and market driven problems. The Brazilian government implemented a program for the rationing of electricity consumption effective as of June 2001. In December 2001, an industry-wide agreement was reached with the Brazilian government that applies to Eletropaulo, Tiete, CEMIG, and Sul.. There were three parts of the agreement that specifically affected AES. The terms of the agreement were implemented during 2002.

First, Annex V, a provision in the initial contracts between the generators and the distributors that was designed to protect the distribution companies from reduced sales volumes and to limit the financial burden of generation companies during periods of rationing, was replaced with a tariff increase that would compensate both generators and distributors for rationing related losses. The net ownership-adjusted impact to AES from the elimination of Annex V and the resulting tariff increase represented additional income before taxes of $60 million. However, the amount recorded under the new methodology at December 31, 2001 was substantially the same as the contractual receivable previously recorded under Annex V. Accordingly, the only impact was the balance sheet reclassification of the receivable to a regulatory asset. The tariff increase will remain in effect for 65 months from the date of the agreement, which the Company believes is sufficient to bill and collect all amounts recorded. The agreement also establishes that BNDES will fund 90% of the amounts recoverable under the tariff increase up front through loans prior to their recovery through tariffs. The loans are repayable over the tariff increase collection period.

The second part of the agreement relates to the Parcel A costs which are certain costs that each distribution company is permitted to defer and pass through to its customers via a future tariff adjustment. Parcel A costs are limited by the concession contracts to the cost of purchased power and certain other costs and taxes. The Brazilian regulator had granted tariff increases to recover a portion of previously deferred Parcel A costs. However, due to uncertainty surrounding the Brazilian economy, the regulator had delayed approval of some Parcel A tariff increases. As part of the agreement, a tracking account that was previously established was officially defined. Parcel A costs incurred previous to January 1, 2001 were not allowed under the definition of the tracking account. As a result, in 2001, the Company wrote-off approximately $160 million ($101 million representing the Company’s portion from equity affiliates), of Parcel A costs incurred prior to 2001 that will not be recovered.

Under the third part of the agreement, Sul was permitted to record additional revenue and a corresponding receivable from the spot market in 2001 and through May 2002. However, the electricity regulator, ANEEL promulgated Order 288 which retroactively changed certain previously communicated methodologies during May 2002, and resulted in a change in the calculation methods for electricity pricing in the Wholesale Energy Market. The Company recorded a pretax provision of approximately $160 million, including the amounts for Sul, against revenues during May 2002 to reflect the negative impacts of this retroactive regulatory decision. Sul filed an injunction in October 2002, which was upheld in December 2002, forcing MAE to keep its original values. The injunction was reversed in the beginning of February 2003. Sul continues to pursue judicial options to address this situation.

The Company does not believe that the terms of the industry-wide rationing agreement as currently being implemented restored the economic equilibrium of all of the concession contracts because the agreement covered only the rationing period, the consumption never returned to the previous levels and previously communicated methodologies for implementing the terms of the rationing agreement were retroactively changed.

On September 3, 2002, ANEEL issued an order providing that the formula for adjusting the tariffs applicable to distribution companies, which are scheduled to be reset in 2003, should be based on a replacement cost method. The Company, together with other electric distribution companies, disagrees with the proposed method and filed a lawsuit advocating that a minimum bid price methodology be used to set the rate base. The companies have not obtained an injunction to date, but the lawsuit is ongoing. Taken alone, the method proposed in the ANEEL order would lead to a significantly lower adjustment in the tariff than would methodologies proposed by the distribution companies. Because a number of other factors that affect the formula have yet to be determined, the Company is unable to predict the ultimate impact, if any, of this order. These other factors include an “X” factor. The X factor is intended to permit the regulator to adjust tariffs so that consumers may share in the distribution company’s realization of increased operating efficiencies. The revision, however, is entirely within the regulator’s discretion.

DERIVATIVES—The Company enters into various derivative transactions in order to hedge its exposure to certain market risks. The Company does not enter into derivative transactions for trading purposes. All derivative transactions are accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended and interpreted. SFAS No. 133 requires that an entity recognize all derivatives (including derivatives embedded in other contracts), as defined, as either assets or liabilities on the balance sheet and measure those instruments at fair value. Changes in the derivative’s fair value are to be recognized currently in earnings, unless specific hedge accounting criteria are met. Hedge accounting allows a derivative’s gains or losses in fair value to offset related results of the hedged item in the statement of operations and requires that a company formally document, designate and assess the effectiveness of transactions that receive hedge accounting. Prior to the adoption of SFAS No. 133 on January 1, 2001, derivatives were accounted for using settlement accounting (i.e. net settlements were accrued based on the current period cash settlement due under the contract).

SFAS No. 133 allows hedge accounting for fair value and cash flow hedges. SFAS No. 133 provides that the gain or loss on a derivative instrument designated and qualifying as a fair value hedge as well as the offsetting gain or loss on the hedged item attributable to the hedged risk be recognized currently in earnings in the same accounting period. SFAS No. 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedge be reported as a component of accumulated other comprehensive income in stockholders’ equity and be reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. The remaining gain or loss on the derivative, if any, must be recognized currently in earnings. If a cash flow hedge is terminated because it is probable that the hedged transaction or forecasted transaction will not occur, the related balance in other comprehensive income as of such date is immediately recognized. If a cash flow hedge is terminated early for other reasons, the related balance in other comprehensive income as of the termination date is recognized concurrently with the related hedged transaction.

The Company currently has outstanding interest rate swap, cap, and floor agreements that hedge against interest rate exposure on floating rate non-recourse debt. These transactions, which are classified as other than trading, are accounted for at fair value. The majority of these transactions are accounted for as cash flow hedges.

The Company enters into currency swaps and forwards to hedge against foreign currency risk on certain non-functional currency-denominated liabilities. These transactions are accounted for at fair value. A portion of these transactions are accounted for as either fair value hedges or cash flow hedges.

The Company enters into electric and gas derivative instruments, including swaps, options, forwards and futures contracts to manage its risks related to electric and gas sales and purchases. These transactions are accounted for at fair value. The majority of these transactions are accounted for as cash flow hedges, and as such, gains and losses arising from derivative financial instrument transactions that hedge the impact of fluctuations in energy prices are recognized in income concurrent with the related purchases and sales of the commodity.

Derivative fair values are reflected at quoted or estimated market value. The values are adjusted to reflect the potential impact of liquidating the Company’s position in an orderly manner over a reasonable period of time under present market conditions. In the absence of quoted market prices, other valuation techniques to estimate fair value are utilized. The use of these techniques requires the Company to make estimations of future prices and other variables, including market volatility, price correlation, and market liquidity.

In December 2001, the FASB revised its earlier conclusion, Derivatives Implementation Group (“DIG”) Issue C-15, related to contracts involving the purchase or sale of electricity. Contracts for the purchase or sale of electricity, both forward and option contracts, including capacity contracts, may qualify for the normal purchases and sales exemption and are not required to be accounted for as derivatives under SFAS No. 133. In order for contracts to qualify for this exemption, they must meet certain criteria, which include the requirement for physical delivery of the electricity to be purchased or sold under the contract only in the normal course of business. Additionally, contracts that have a price based on an underlying index that is not clearly and closely related to the electricity being sold or purchased or that are denominated in a currency that is foreign to the buyer or seller are not considered normal purchases and normal sales and are required to be accounted for as derivatives under SFAS No. 133. This revised conclusion became effective beginning April 1, 2002 (see Note 10).

EARNINGS PER SHARE—Basic and diluted earnings per share are based on the weighted average number of shares of common stock and potential common stock outstanding during the period, after giving effect to stock splits (see Note 15). Potential common stock, for purposes of determining diluted earnings per share, includes the effects of dilutive stock options, warrants, deferred compensation arrangements, and convertible securities. The effect of such potential common stock is computed using the treasury stock method or the if-converted method, as applicable.

USE OF ESTIMATES—The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires the Company to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements, as well as the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant items subject to such estimates and assumptions include the carrying value and estimated useful lives of long-lived assets; impairment of goodwill and equity method investments; valuation allowances for receivables and deferred tax assets; the recoverability of deferred regulatory assets and the valuation of certain financial instruments, pension liabilities, environmental liabilities and potential litigation claims and settlements (see Note 11).

STOCK OPTIONS—The Company accounts for its stock-based compensation plans under Accounting Principles Board Opinion (“APB”) No. 25, “Accounting for Stock Issued to Employees,” and has adopted SFAS No. 123, “Accounting for Stock-based Compensation,” for disclosure purposes. No compensation expense has been recognized in connection with the options, as all options have been granted only to AES people, including Directors, with an exercise price equal to the market price of the Company’s common stock on the date of grant. For SFAS No. 123 disclosure purposes, the

weighted average fair value of each option grant has been estimated as of the date of grant primarily using the Black-Scholes option-pricing model with the following weighted average assumptions:

	Years Ended December 31,
	2002		2001		2000

Interest rate (risk-free)	3.83	%	4.84	%	5.4	%
Volatility	68	%	86	%	41	%
Dividend yield	—		—		1	%

Using these assumptions, and an expected option life of approximately 9 years, the weighted average fair value of each stock option granted was $1.98, $14.87 and $18.99, for the years ended December 31, 2002, 2001 and 2000, respectively.

Had compensation expense been determined under the provisions of SFAS No. 123, utilizing the assumptions detailed in the preceding paragraph, the Company’s net income and earnings per share for the years ended December 31, 2002, 2001 and 2000 would have been reduced to the following pro forma amounts (in millions except per share amounts):

	Years Ended December 31,
	2002			2001		2000

NET INCOME:
As reported	$	(3,509	)	$	273	$	795
Pro forma	(3,657		)	179		753
BASIC EARNINGS PER SHARE:
As reported	$	(6.51	)	$	0.52	$	1.66
Pro forma	(6.79		)	0.34		1.56
DILUTED EARNINGS PER SHARE:
As reported	$	(6.51	)	$	0.51	$	1.59
Pro forma	(6.79		)	0.33		1.50

The disclosures of such amounts and assumptions are not intended to forecast any possible future appreciation of the Company’s stock or change in dividend policy.

Effective January 1, 2003, the Company has elected to adopt fair value accounting for its stock-based compensation as allowed under SFAS No. 123, as amended by SFAS No. 148. SFAS No. 123 allows for three alternative methods of accounting for stock-based compensation at fair value. The three methods are the prospective method, modified prospective method and the retroactive restatement method. The prospective method requires recognition of stock-based compensation expense at fair value for all awards granted in the year of adoption but not for previous awards. The modified prospective method requires recognition of stock-based compensation expense at fair value for the unvested portion of all stock options granted, modified or settled since 1994. The retroactive restatement method requires recognition of stock-based compensation expense at fair value for the unvested portion of all stock options granted, modified or settled since 1994 with all prior periods being restated. The Company has elected to use the prospective method for recognizing stock-based compensation expense.

The Company will continue to use an option-pricing model to determine the fair value of options issued. The expense for each award grant, including awards with graded vesting, will be recognized on a straight-line basis over the vesting period. Any forfeitures will be recognized when they occur. The above proforma disclosure has been calculated using these assumptions. Prior to the adoption of fair value accounting, the Company recognized compensation expense for stock options based on the intrinsic value of the option on the grant date, which was zero for all grants. Therefore, there has been no expense recorded for stock-based compensation for the year ended December 31, 2002 or any prior

periods. The Company’s Board of Directors have approved the issuance of approximately 11 million options in the first quarter of 2003. Approximately 8 million of the options will be issued under existing plans. The remaining options will be granted under a new plan that is subject to shareholder approval. The Black Scholes fair value is $2.01 per option for those to be issued under the existing plans. The Company will recognize the expense related to these options based on their fair value over the vesting period which is 2 years.

RECLASSIFICATIONS—Certain reclassifications have been made to prior-period amounts to conform to the 2002 presentation.

2. SWAP OF OWNERSHIP IN BRAZILIAN BUSINESS

On February 6, 2002, a subsidiary of the Company exchanged with EDF International S.A., its shares representing a 23.89% interest in Light Servicos de Eletricidade S.A. for 88% of the shares of AES Elpa S.A. (formerly Lightgas Ltda) (the “swap”). AES Elpa owns 77% of the voting capital (31% of the total capital) of Eletropaulo Metropolitana Eletricidade de Sao Paulo S.A. (“Eletropaulo”) and 100% of AES Communications Rio. In connection with the swap, AES Elpa assumed debt of $527 million of which approximately $85 million was due in October 2002 and the remainder due in 2003.

The swap was accounted for at historical cost as a reorganization of entities under common control. Pre-existing goodwill of approximately $780 million was recorded in conjunction with the swap at the March 31, 2002 exchange rate. In conjunction with the Company’s annual goodwill impairment review and as a result of the unfavorable economic and regulatory environment in Brazil, AES determined the entire goodwill amount was impaired and recorded a charge of $607 million, after income taxes, at the October 1, 2002 exchange rate (see Note 6).

As a result of the swap, the Company has a controlling interest through a 70.37% ownership interest in Eletropaulo and consolidates its activity. Previously the Company had accounted for its investment in Eletropaulo using the equity method. At December 31, 2002, Eletropaulo had total assets of approximately $3.6 billion and total liabilities of approximately $3.9 billion, including the debt of AES Elpa.

3. BUSINESS COMBINATIONS

On March 27, 2001, AES completed its merger with IPALCO through a share exchange transaction in accordance with the Agreement and Plan of Share Exchange dated July 15, 2000, between AES and IPALCO, and IPALCO became a wholly owned subsidiary of AES. The Company accounted for the combination as a pooling of interests. Each of the outstanding shares of IPALCO common stock was converted into the right to receive 0.463 shares of AES common stock. The Company issued approximately 41.5 million shares of AES common stock. The consideration consisted of newly issued shares of AES common stock. IPALCO is an Indianapolis- based utility with approximately 3,400 MW of gross generation capacity and 450,000 customers in and around Indianapolis.

The Company issued approximately 346,000 options for the purchase of AES common stock in exchange for IPALCO outstanding options using the exchange ratio. All unvested IPALCO options became vested pursuant to the existing stock option plan upon the change in control.

In connection with the merger with IPALCO, the Company incurred contractual liabilities associated with existing termination benefit agreements and other merger related costs for investment banking, legal and other fees. These costs, which were $131 million in 2001 are shown separately in the accompanying consolidated statements of operations. All of the amounts for the plan were expensed as incurred. As a result of the plan, the workforce was reduced by 480 people.

The table below sets forth revenues, net income and comprehensive loss for AES and IPALCO for the period from January 1, 2001 through the date of the merger (amounts in millions).

Revenues:
AES	$	1,531
IPALCO	215
Consolidated Revenues	$	1,746

Net Income:
AES	$	129
IPALCO	(18		)
Consolidated Net Income	$	111

	AES			IPALCO			Combined

Comprehensive Loss:
Net Income (Loss)	$	129		$	(18	)	$	111
Foreign currency translation adjustment	(236		)	—			(236		)
Change in derivative fair value	(50		)	—			(50		)
Minimum pension liability	—			(2		)	(2		)
Cumulative effect of adopting SFAS No. 133 on Jan. 1, 2001	(93		)	—			(93		)
Comprehensive Loss	$	(250	)	$	(20	)	$	(270	)

There have been no changes to the significant accounting policies of AES or IPALCO due to the merger. Both AES and IPALCO have the same fiscal years. There were no intercompany transactions between the two companies prior to the merger date.

The tables below set forth revenues, net income and comprehensive income for AES and IPALCO for the year ended December 31, 2000.

	2000

Revenues:
AES	$	4,266
IPALCO	891
Consolidated Revenues	$	5,157

Net Income:
AES	$	640
IPALCO	155
Consolidated Net Income	$	795

	AES			IPALCO			Combined

Comprehensive Income:
Year ended December 31, 2000
Net Income	$	640		155			$	795
Foreign currency translation adjustment	(575		)	—			(575		)
Realized gains on marketable securities	—			(107		)	(107		)
Minimum pension liability adjustment	—			(2		)	(2		)

Comprehensive income	$	65		$	46		$	111

The Company has accounted for the following transactions, completed in 2001, using the purchase method of accounting. Accordingly, the purchase price of each transaction has been allocated based upon the estimated fair value of the assets and the liabilities acquired as of the acquisition date, with the excess, if any, reflected as goodwill. The results of operations of the acquired companies have been included in the consolidated results of operations since the date of each acquisition.

In January 2001, following the expiration on December 28, 2000 of a Chilean tender offer, Inversiones Cachagua Limitada, a Chilean subsidiary of AES, paid cash for 3,466,600,000 shares of common stock of Gener S.A (“Gener”). Also in January 2001, following the expiration on December 29, 2000 of the simultaneous United States offer to exchange all American Depositary Shares (“ADS”) of Gener for AES common stock, AES issued 9.1 million shares of common stock with a value of approximately $511 million in exchange for Gener ADSs tendered pursuant to the United States offer, which, together with the shares acquired in the Chilean offer, resulted in AES’s acquisition of approximately 96.5% of the capital stock of Gener. Subsequently, the Company’s total ownership reached approximately 99% due to a stock buyback program initiated by Gener in February 2001. The purchase price for the acquisition of Gener was approximately $1.4 billion before asset sales of $318 million, plus the assumption of approximately $700 million of non-recourse debt. Approximately $865 million of goodwill was recorded as part of the purchase and was being amortized over 40 years until January 1, 2002 when the Company adopted SFAS No. 142. See Note 6 for further disclosure of the financial statement impact of this accounting pronouncement. In conjunction with its tender offer, the Company agreed to sell two of Gener’s generating assets (Central Puerto and Hidronequen) to TotalFinaElf. In March 2001, Gener and TotalFinaElf executed a purchase and sale agreement which granted to

TotalFinaElf the option to purchase three of Gener’s generating assets in Argentina: Central Puerto, Hidronequen and TermoAndes. Pursuant to this agreement, in August, 2001, AES sold Gener’s interest in Central Puerto to a TotalFinaElf subsidiary for $255 million. In addition, in September TotalFinaElf purchased Gener’s interest in Hidronequen for $72.5 million as well as subordinated debt related to Hidronequen held by Gener for approximately $50 million. The option to purchase TermoAndes expired unexercised. Upon completion of the purchase, Gener implemented an employee severance plan. As of December 31, 2001, the severance plan was completed and the workforce was reduced by 187 people. All of the approximately $9 million cost related to the plan was recorded in 2001 and all cash payments were made in 2001. The purchase price allocation for Gener was finalized during 2001.

In April 2001, the Company acquired a 75% controlling interest in Kievoblenergo, a distribution company that serves the region that surrounds Kiev, the capital city of Ukraine, for approximately $46 million in cash. The remaining 25% interest is either publicly owned or owned by the employees of the distribution company.

In May 2001, the Company acquired a 75% controlling interest in Rivnooblenergo, a distribution company that serves the Rivno region in Ukraine, for approximately $23 million in cash. The remaining 25% interest is either publicly owned or owned by the employees of the distribution company.

In July 2001, a subsidiary of the Company completed the final phase of its acquisition of the energy assets of Thermo Ecotek Corporation, a wholly owned subsidiary of Thermo Electron Corporation of Waltham, Massachusetts. The transaction was consummated in two phases. The initial phase of the transaction, which occurred on June 29, 2001, was closed at a price of $242 million in cash. The purchase price for the second and final phase was $18 million in cash. This resulted in a total purchase price for the two phases of the Thermo Ecotek acquisition of $260 million. No material long-term liabilities were assumed at the acquisition date. The portfolio of assets acquired by the Company included approximately 500 MW of gas-fired, biomass-fired (agricultural and wood waste) and coal-fired operating power assets in the United States, the Czech Republic, and Germany, a natural gas storage project in the United States, and over 1,250 MW of advanced development power projects in the United States.

In July 2001, a subsidiary of the Company acquired a 56% interest in SONEL, an integrated electricity utility in Cameroon, with a 20-year concession on generation, transmission and distribution country-wide. The purchase price was approximately $70 million in cash, plus the assumption of approximately $260 million of long-term liabilities. The other 44% will remain with the government. SONEL is one of the largest African electricity utilities with approximately 800 MW of installed capacity and 452,000 customers.

The purchase price allocations for Thermo Ecotek, SONEL, Kievoblenergo and Rivnooblenergo were finalized during 2002 with no material adjustments to the preliminary purchase accounting. Proforma disclosures for the 2002, 2001 and 2000 purchase business combinations have not been presented as the effects would be immaterial.

There were no material business combinations initiated in 2002.

4. DISCONTINUED OPERATIONS

Effective January 1, 2001, AES adopted SFAS No. 144. This statement addresses financial accounting and reporting for the impairment or disposal of long-lived assets. SFAS No. 144 requires a component of an entity that either has been disposed of or is classified as held for sale to be reported as discontinued operations if certain conditions are met.

In September 2003, AES reached an agreement to sell 100% of its ownership interest in AES Whitefield, a generation business. The sale is structured as a stock purchase agreement. At September 30, 2003 this business was classified as held for sale in accordance with SFAS No. 144. AES Whitefield was previously reported in the contract generation segment.

On August 8, 2003, the Company decided to sell AES Communications Bolivia, located in La Paz, Bolivia and has reported this business as an asset held for sale. As a result of this decision, the Company recorded a pre-tax impairment charge of $29 million during the third quarter of 2003 to reduce the carrying value of the assets to their estimated fair value in accordance with SFAS No. 144. AES expects to complete the sale during the first half of 2004. AES Communications Bolivia was previously reported in the competitive supply segment.

In July 2003, AES reached an agreement to sell 100% of its ownership interest in AES Mtkvari, AES Khrami and AES Telasi for gross proceeds of $23 million. At June 30, 2003 these businesses were classified as held for sale and the Company recorded a pre-tax impairment charge of $204 million during the second quarter of 2003 to reduce the carrying value of the assets to their estimated fair value in accordance with SFAS No. 144. This transaction was closed in August 2003 and resulted in a total write-off of approximately $210 million. AES Mtkvari and AES Khrami were previously reported in the contract generation segment and AES Telasi was previously reported in the growth distribution segment.

During the first quarter of 2003, AES committed to a plan to sell its ownership in AES Barry Limited (“AES Barry”), and had classified it in discontinued operations. On July 24, 2003, the Company reached an agreement to sell substantially all the physical assets of AES Barry to an unrelated third party for £40 million (or approximately $62 million). The sale proceeds were used to discharge part of AES Barry’s debt and to pay certain transaction costs and fees. The Company will continue to own the stock of AES Barry while AES Barry pursues a £60 million claim against TXU EET, which is currently in bankruptcy administration. AES Barry will receive 20% of amounts recovered from the administrator. If the proceeds from TXU EET are not sufficient to repay the bank debt, the banks have recourse to the shares of AES Barry, but have no recourse to the Company for a default by AES Barry.

An amended credit agreement for the sale of the AES Barry assets was signed on July 24, 2003. As a result of the amended credit agreement, AES forfeited control over the remaining assets of AES Barry, namely the claim against TXU EET. Accordingly, the Company deconsolidated AES Barry and began accounting for its investment using the equity method prospectively from the date of the credit agreement. AES Barry was previously reported in the competitive supply segment.

On March 14, 2003 AES reached an agreement to sell 100% of its ownership interest in both AES Haripur Private Ltd. (“Haripur”) and AES Meghnaghat Ltd. (“Meghnaghat”), both generation businesses in Bangladesh, to CDC Globeleq, the completion of which sale is subject to certain conditions, including obtaining governmental and lender consents. Those governmental and lender consents were

not obtained by the August 14, 2003, termination date in the original share purchase agreement (“SPA”). On September 17, 2003, AES and CDC Globeleq agreed to extend until February 17, 2004, the date by which the conditions to the sale must be satisfied, including obtaining governmental and lender consents, or the SPA will terminate. AES and CDC Globeleq on September 17, 2003 also agreed to increase the equity purchase price for the sale from $127 million to $137 million, subject to purchase price adjustments at the time of completion of the sale which we currently estimate to be an additional $10 to 15 million. While the Company believes that these consents can be obtained prior to the February 17, 2004 termination date, there can be no assurance that the consents will be obtained by that date or that the sale will ultimately be completed. The total AES book value in AES Haripur and AES Meghnaghat, including other comprehensive loss, wasapproximately $190 million as of February 28, 2003 which resulted in an impairment loss being recorded in the first quarter of 2003.These two businesses were previously reported in the contract generation segment.

As a result of a significant reduction in electricity prices in Great Britain during the first quarter of 2002, operating revenues at the Company’s Fifoots Point subsidiary were insufficient to cover operating expenses and debt service costs. Accordingly, the subsidiary was placed in administrative receivership by its project financing lenders and the Company’s ownership of the subsidiary was terminated. This resulted in a write off of the Company’s investment of $53 million, net of income taxes. The Company has no continuing involvement in the Fifoots Point subsidiary which was previously reported in the competitive supply segment.

In April 2002, AES reached an agreement to sell 100 percent of its ownership interest in CILCORP, a utility holding company whose largest subsidiary is Central Illinois Light Company (“CILCO”), to Ameren Corporation in a transaction valued at $1.4 billion including the assumption of debt and preferred stock at the closing. During the year ended December 31, 2002, a pre-tax goodwill impairment expense of approximately $104 million was recorded to reduce the carrying amount of the Company’s investment to its estimated fair market value. The goodwill was considered impaired since the current fair market value of the business was less than its carrying value. The fair market value of AES’s investment in CILCORP was estimated using as a basis the expected sale price under the related sales agreement. The transaction also includes an agreement to sell AES Medina Valley Cogen, a gas-fired cogeneration facility located in CILCO’s service territory. The sale of CILCORP by AES was required under the Public Utility Holding Company Act (PUHCA) when AES merged with IPALCO, a regulated utility in Indianapolis, Indiana in March 2001. The transaction closed in January 2003, and generated approximately $495 million in cash proceeds, net of transaction expenses. CILCORP was previously reported in the large utilities segment.

On October 3, 2003, AES Drax Power Limited (“Drax”) changed its name to Drax Power Limited to reflect the withdrawal of AES from the operation of the Drax power plant in August 2003. Drax Power Limited, a former subsidiary of AES, is the operator of the Drax power plant, Britain’s largest power station.

In November 2002, Drax terminated its Hedging Agreement with TXU Europe Energy Trading Limited (“TXU EET”). In November 2002, TXU Europe Group plc (“TXU Group”), the guarantor under the power supply hedging agreement between Drax Power and TXU EET, filed for administration in the United Kingdom. As a result of the termination of the Hedging Agreement, which provided Drax above-market prices for the contracted output (equal to approximately 60 percent of the total output of the plant), Drax became fully exposed to power prices in the United Kingdom. The termination of the Hedging Agreement constituted a change in circumstance as defined by Statement of Financial Accounting Standard (SFAS) No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, that indicated that the carrying value of Drax’s net assets may not be recoverable. Accordingly, in the fourth quarter of 2002, a pre-tax impairment charge of $1,170 million ($893 million after-tax) was recorded to write-down the net assets of Drax to their fair value. This charge includes a write off of $215 million of trade receivables and a $955 million write-down of the investment to net realizable value. The approximate fair value of net assets was determined by discounting future projected future cash flows of the business. Additionally, in the fourth quarter of 2002, the Company approved and committed to a plan to sell the business. The business was available for immediate sale, and a plan was established to locate a buyer at a reasonable fair market price. At December 31, 2002 the Company believed it would sell the business within one year and it was unlikely that significant changes would be made to the plan to sell. The Company expected to have a significant continuing involvement in the operations of the business after the sale transaction.

Since December 12, 2002, Drax has been operating under standstill arrangements with its senior creditors. These standstill arrangements were initially included in the “Original Standstill Agreement”, and, after expiration thereof on May 31, 2003, under the “Further Standstill Agreement,” and, after expiration thereof on June 30, 2003 under the “Third Standstill Agreement” and, after expiration thereof on August 14, 2003, under the Fourth Standstill Agreement, which expired on September 30, 2003. We understand, solely based on the publicly filed information contained in Drax’s Form 6-K filed on October 28, 2003, that Drax has entered into an additional standstill agreement, called the “Long Term Standstill Agreement” which became effective on October 9, 2003 and will expire on December 31, 2003, unless terminated earlier or extended in accordance with its terms. Drax has publicly disclosed that these standstill agreements have been entered into for the purpose of providing Drax and its senior creditors with a period of stability during which discussions regarding a consensual restructuring (the “Restructuring”) could take place. The standstill agreements provide temporary and/or permanent waivers by certain of the senior lenders of defaults that have occurred or could occur up to the expiration of the standstill period, including a permanent waiver resulting from termination of the Hedging Agreement.

Based on negotiations through the end of June 2003, Drax, AES and the steering committee (the “Steering Committee”) representing the syndicate of banks (the “Senior Lenders”), which financed the Eurobonds issued by Drax to finance the acquisition of the Drax power plant, and the ad hoc committee formed by holders of Drax’s Senior Bonds (the “Ad Hoc Committee” and, together with the Steering Committee, the “Senior Creditors Committees”), reached agreement on more detailed terms of the Restructuring, and each of the Senior Creditors Committees, Drax and AES indicated their support for a Restructuring to be implemented based upon the proposed restructuring terms (the “June Restructuring Proposal”) that was published by Drax on Form 6-K on June 30, 2003.

On July 23, 2003, Drax received a letter from International Power plc., pursuant to which it offered to replace AES in the Restructuring and to purchase certain debt to be issued in the Restructuring described in the June Restructuring Proposal (the “IP Proposal”). On July 28, 2003, AES sent a letter to the Senior Creditors Committees and to Drax indicating that AES would withdraw its support for, and participation in, the Restructuring unless each member of the Senior Creditors Committees met certain conditions by no later than August 5, 2003, including support for the June Restructuring Proposal (subject to documentation), rejection of the IP Proposal and inclusion in the extended standstill agreement of an agreement not to discuss or negotiate with any person regarding the sale of the Drax power station or the participation of any person in the Restructuring in lieu of AES.

Because none of the written confirmations requested by AES were received, on August 5, 2003 AES withdrew its support for, and

participation in, the June Restructuring Proposal. Subsequently, the directors appointed by AES resigned from the boards of Drax, as well as from the boards of all other relevant Drax companies below Drax Energy.

On September 30, 2003, the security trustee delivered enforcement notices to Drax, thereby effecting the revocation of voting rights in the shares in AES Drax Acquisition Limited, Drax’s parent company which were mortgaged in favor of the security trustee.

AES has no continuing involvement in Drax and has classified Drax within discontinued operations as of September 30, 2003. We understand, based solely on the publicly filed information contained in Drax’s Form 6-K filed on October 28, 2003, that Drax has received irrevocable undertakings from certain creditors to vote in favor of a restructuring proposal which was described in the Form 6-K filed by Drax on September 15, 2003 and that Drax has entered into a definitive agreement with International Power plc within which International Power plc has agreed to fund the cash-out option for a proportion of the restructured debt as described in Drax’s Form 6-Ks filed on September 15, 2003 and October 28, 2003.

Since certain of Drax’s forward looking debt service cover ratios as of June 30, 2002 were below required levels, Drax was not able to make any cash distributions to Drax Energy, the holding company high-yield note issuer, at that time. Drax expects that the ratios, if calculated as of December 31, 2002 or as of June 30, 2003, would also have been below the required levels at December 31, 2002 or June 30, 2003, as applicable. In addition, as part of the standstill arrangements, Drax deferred a certain portion of the principal payments due to its Senior Lenders as of December 31, 2002 and as of June 30, 2003.

During the second quarter of 2002, after exploring several strategic options related to Eletronet, a telecommunication business in Brazil, AES committed to a plan to sell its 51% ownership interest in this business. The estimated realizable value was less than the book value of AES’s investment and as a result, the investment in Eletronet was written down to its estimated realizable value. The Eletronet sale will close in two parts, the first of which occurred on December 31, 2002. The total loss for Eletronet for 2002, including results of operations, write downs, and the effect of the first closing was $149 million, net of income taxes. Eletronet was previously reported in the competitive supply segment.

In September 2002, AES sold 100 percent of its ownership interest in AES NewEnergy to Constellation Energy Group for approximately $260 million, which resulted in a loss on sale of approximately $29 million. AES NewEnergy was previously reported in the competitive supply segment.

In December 2002, AES reached an agreement to sell 100 percent of its ownership interest in both AES Mt. Stuart and AES Ecogen, both generation businesses in Australia, to Origin Energy Limited and to a consortium of Babcock & Brown and Prime Infrastructure Group, respectively. The total sales price for both businesses is approximately $171 million, which equates to an equity purchase price of approximately $59 million, which represents a premium to AES’s book investment. The sale of AES Mt. Stuart closed in January 2003. The sale of AES Ecogen closed in February 2003. AES Mt. Stuart and AES Ecogen were previously reported in the contract generation segment.

In December 2002, AES reached an agreement to sell 100 percent of its ownership interests in Songas Limited and AES Kelvin Power (Pty.) Ltd. to CDC Globeleq for approximately $329 million, which includes the assumption of debt. These two businesses were previously reported in the contract generation segment.

In December 2002, AES classified its investment in Mountainview as held for sale. In the fourth quarter of 2002, the Company recorded a pre-tax impairment charge of $415 million ($270 million after-tax) to reduce the carrying value of Mountainview’s assets to estimated realizable value in accordance with SFAS No. 144. The determination of the realizable value was based on available market information obtained through discussions with potential buyers. In January 2003, the Company entered into an agreement to sell Mountainview for $30 million with another $20 million payment contingent on the achievement of project specific milestones. The transaction closed in March 2003. Mountainview was previously reported in the competitive supply segment.

During 2001, the Company decided to exit certain of its businesses. These businesses included Power Direct, Geoutilities, TermoCandelaria, Ib Valley and several telecommunications businesses in Brazil and the U.S. For those businesses disposed of or abandoned, the Company determined that significant adverse changes in legal factors and/or the business climate, such as unfavorable market conditions and low tariffs, negatively affected the value of these assets. The Company had certain businesses that were held for sale as of December 31, 2001, including TermoCandelaria. The sales of these assets were completed prior to December 31, 2002, and the resulting gains or losses on these sales were not material.

All of the business components discussed above are classified as discontinued operations in the accompanying consolidated statements of operations. Previously issued statements of operations have been restated to reflect discontinued operations reported subsequent to the original issuance date. The revenues associated with the discontinued operations were $2,704 million, $3,005 million and $2,449 million for the years ended December 31, 2002, 2001 and 2000, respectively. The pretax income/(loss) associated with the discontinued operations were $(1,158) million, $(61) million and $105 million for each of the years ended December 31, 2002, 2001 and 2000, respectively. The loss on disposal and impairment write-downs for those businesses sold or held for sale, net of tax associated with the discontinued operations, was $1,647 million and $145 million for the years ended December 31, 2002 and 2001, respectively.

The assets and liabilities associated with the discontinued operations and assets held for sale are segregated on the consolidated balance sheets at December 31, 2002 and 2001. The carrying amount of major asset and liability classifications for businesses recorded as discontinued operations and held for sale are as follows:

	December 31, 2002		December 31, 2001
	(in millions)		(in millions)

ASSETS:
Cash	$	144	$	100
Short-term investments	2		16
Accounts receivable, net	244		502
Inventory	132		174
PP&E	4,825		5,911
Other assets	1,393		1,968
Total assets	$	6,740	$	8,671

LIABILITIES:
Accounts payable	$	136	$	119
Current portion of long-term debt	194		229
Long-term debt	3,542		3,370
Other liabilities	1,862		2,228
Total liabilities	$	5,734	$	5,946

5. OTHER SALE OF ASSETS AND ASSET IMPAIRMENT EXPENSE

In the fourth quarter of 2002, circumstances surrounding the AES Lake Worth project indicated that the carrying amount of the Company’s investment in the Lake Worth project may not be recoverable. Therefore, in accordance with SFAS No. 144, a pre-tax impairment charge of $78 million ($51 million after-tax) was recorded to write-down the net assets of the project to their fair market value. The fair value of the net assets was estimated by analyzing the discounted future cash flows of the business as well as indications from unrelated third parties regarding the value of the project. The timing of this charge was due to a decision by the Company not to provide any further funding for this project and to sell the project. Lake Worth is a competitive supply business.

In September 2002, AES Greystone, LLC and its subsidiary Haywood Power I, LLC, sold the Greystone gas-fired peaker assets then under construction in Tennessee to Tenaska Power Equipment for $36 million including cash and assumption of certain obligations. With this sale, AES and its subsidiaries have eliminated any future capital expenditures related to the facility, and also settled all major outstanding obligations with parties involved in this project. AES recorded a pre-tax loss of approximately $168 million ($110 million after-tax) associated with this sale. Greystone was previously recorded as a competitive supply business.

In March 2002, AES’s 87 percent owned subsidiary, Corporacion EDC, C.A., sold its remaining shares in Compania Anonima Nacional Telefonos de Venezuela (“CANTV”) for cash proceeds of approximately $92 million. The loss realized on this transaction, before the effect of minority interest, was approximately $57 million. EDC is a large utility business.

In December 2001, AES’s 87 percent owned subsidiary, Corporacion EDC, C.A., sold a portion of its shares in CANTV as part of a share buyback program to CANTV for cash proceeds of approximately $59 million. The gain realized on this transaction, before the effect of minority interest, was approximately $18 million.

In 2000, a subsidiary of IPALCO sold approximately 1 million shares of its investment in an internet company which went public in 1999 for $114 million. This sale resulted in a gain to the Company of approximately $112 million before income taxes.

Also in 2000, IPALCO sold certain assets (the “Thermal Assets”) for approximately $162 million. The transaction resulted in a gain to the Company of approximately $31 million before income taxes ($19 million after income taxes). Of the net proceeds, $88 million was used to retire debt specifically assignable to the Thermal Assets. The related notes were retired in November and December 2000 and January 2001. In connection with the retirement of the debt, the Company incurred make-whole payments and wrote-off debt issuance costs of approximately $4 million. IPALCO is a large utility business.

6. GOODWILL AND OTHER INTANGIBLES

Effective January 1, 2002, the Company adopted SFAS No. 142, “Goodwill and Other Intangible Assets” which establishes accounting and reporting standards for goodwill and other intangible assets. The standard eliminates goodwill amortization and requires an evaluation of goodwill for impairment upon adoption of the standard, as well as annual subsequent evaluations. The Company’s annual impairment testing date is October 1st.

SFAS No. 142 requires that goodwill be evaluated for impairment at a level referred to as a reporting unit. A reporting unit is an operating segment as defined by SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information”, or one level below an operating segment, referred to as a component. Each AES business constitutes a reporting unit.

Generally, reporting units have been acquired in separate transactions. In the event that more than one reporting unit is acquired in a single acquisition, the fair value of each reporting unit is determined, and that fair value is allocated to the assets and liabilities of that unit. If the determined fair value of the reporting unit exceeds the amount allocated to the net assets of the reporting unit, goodwill is assigned to that reporting unit.

The adoption of SFAS No. 142 resulted in a cumulative reduction to income of $473 million, net of income tax effects, which was recorded as a cumulative effect of accounting change in the first quarter of 2002. SFAS No. 142 adopts a fair value model for evaluating impairment of goodwill in place of the recoverability model used previously. The reduction resulted from the write off of goodwill related to certain of our businesses in Argentina, Brazil and Colombia. The Company wrote-off the goodwill associated with certain acquisitions where the current fair market value of such businesses is less than the current carrying value of the business, primarily as a result of reductions in fair value associated with lower than expected growth in electricity consumption and lower electricity prices due in part to the devaluation of foreign exchange rates compared to the original estimates made at the date of acquisition. The fair value of these businesses was estimated using the expected present value of future cash flows and comparable sales, when available.

As part of the annual testing, the Company wrote-off an additional $610 million, net of income tax effects, which is recorded in goodwill impairment expense in the accompanying consolidated statement of operations. The impairment expense primarily related to Eletropaulo in Brazil which was not included in the testing as part of the adoption of SFAS No. 142 since it was an equity method investment at that time. The goodwill was considered impaired since the current fair market value of the business is less than the carrying value of the business, primarily as a result of slower than anticipated recovery to pre-rationing electricity consumption levels and lower electricity prices due to devaluation of foreign exchange rates. The amount of the impairment charge represents the write off required to reduce the carrying amount of the asset to its estimated fair value based on discounted cash flows of the business.

Changes in the carrying amount of goodwill, by segment, for the year ended December 31, 2002 are as follows (in millions):

	Contract Generation			Competitive Supply			Large Utilities			Growth Distribution			Total

Carrying amount at December 31, 2001	$	1,124		$	147		$	—		$	1,094		$	2,365
Goodwill acquired during the period	—			—			780			—			780
Impairment losses from annual analysis	—			(5		)	(607		)	—			(612		)
Impairment losses from adoption of SFAS No. 142	—			(80		)	—			(681		)	(761		)
Concessions reclassed to other assets	(11		)	—			—			(152		)	(163		)
Translation adjustments and other	(7		)	(2		)	(173		)	(41		)	(223		)
Carrying amount at December 31, 2002	$	1,106		$	60		$	—		$	220		$	1,386

Reported net income and earnings per share adjusted to exclude goodwill amortization expense for 2002, 2001 and 2000 are as follows (in millions, except per share amounts):

	Years Ended December 31,
	2002			2001		2000

Net (loss) income	$	(3,509	)	$	273	$	795
Add back: Goodwill amortization	—			70		47
Adjusted net (loss) income	$	(3,509	)	$	343	$	842
Basic (loss) earnings per share:
Reported basic (loss) earnings per share	$	(6.51	)	$	0.52	$	1.66
Goodwill amortization	—			0.13		0.10
Adjusted basic (loss) earnings per share	$	(6.51	)	$	0.65	$	1.76
Diluted (loss) earnings per share:
Reported diluted (loss) earnings per share	$	(6.51	)	$	0.51	$	1.59
Goodwill amortization	—			0.13		0.09
Adjusted diluted (loss) earnings per share	$	(6.51	)	$	0.64	$	1.68

Included in other assets in the accompanying consolidated balance sheets are concession agreements with a gross carrying amount of $184 million and accumulated amortization of $18 million. The agreements have a weighted average remaining amortization period of 17.3 years. For the year ended December 31, 2002 the amortization expense was $9.1 million. The estimated amortization expense for fiscal years 2003 through 2007 is $9.8 million each year.

7. INVESTMENTS IN AND ADVANCES TO AFFILIATES

The Company records its share of earnings from its equity investees on a pre-tax basis. The Company’s share of the investee’s income taxes is recorded in income tax expense.

CEMIG. The Company is a party to a joint venture/consortium agreement through which the Company has an equity investment in Companhia Energetica de Minas Gerais (“CEMIG”), an integrated utility in Minas Gerais, Brazil. The agreement prescribes ownership and voting percentages as well as other matters.

In the fourth quarter of 2002, a combination of events occurred related to the CEMIG investment. These events included consistent poor operating performance in part caused by continued depressed demand and poor asset management, the inability to adequately service or refinance operating company debt and acquisition debt, and a continued decline in the market price of CEMIG shares. Additionally,

our partner in one of the holding companies in the CEMIG ownership structure sold its interest in this holding company to an unrelated third party in December 2002 for a nominal amount. Upon evaluating these events in conjunction with each other, the Company concluded that an other than temporary decline in value of the CEMIG investment had occurred. Therefore, in December 2002, AES recorded a charge related to the other than temporary impairment of the investment in CEMIG, and the shares in CEMIG were written-down to fair market value. Additionally, AES recorded a valuation allowance against a deferred tax asset related to the CEMIG investment. The total amount of these charges, net of tax, was $587 million, of which $264 million relates to the other than temporary impairment of the investment and $323 million relates to the valuation allowance against the deferred tax asset. As a result of these charges, the Company’s investment in CEMIG, net of debt used to finance the CEMIG investment, is negative.

In the fourth quarter of 2002, AES lost management control of one of the holding companies in the CEMIG ownership structure. This holding company indirectly owns the shares related to the CEMIG investment and indirectly holds the project financing debt related to CEMIG. As a result of the loss of management control, AES deconsolidated this holding company at December 31, 2002, and will account for the investment in this holding company using the equity method in future periods.

Eletropaulo. In May 1999, a subsidiary of the Company acquired subscription rights from the Brazilian state-controlled Eletrobras, which allowed it to purchase preferred, non-voting shares in Light Servicos de Eletricidade S.A. (“Light”) and Eletropaulo Metropolitana Electricidade de Sao Paulo S.A. (“Eletropaulo”). The aggregate purchase price of the subscription rights and the underlying shares in Light and Eletropaulo was approximately $53 million and $77 million, respectively, and represented 3.7% and 4.4% economic ownership interest in their capital stock, respectively.

In January 2000, 59% of the preferred non-voting shares of Eletropaulo were acquired for approximately $1 billion at auction from BNDES, the National Development Bank of Brazil. The price established at auction was approximately $72.18 per 1,000 shares, to be paid in four annual installments. In May 2000, a subsidiary of the company acquired an additional 5% of the preferred, non-voting shares of Eletropaulo for approximately $90 million. At December 31, 2000, the Company had a total economic interest of 49.6% and a voting interest of 17.35% in Eletropaulo; therefore, the Company accounted for this investment using the equity-method based on the related consortium agreement that allows the exercise of significant influence.

In December 2000, a subsidiary of the Company, along with EDF International S.A. (“EDF”), completed the acquisition of an additional 3.5% interest in Light from two subsidiaries of Reliant Energy for approximately $136 million. Pursuant to the acquisition, the Company acquired 30% of the shares while EDF acquired the remainder. With the completion of this transaction, the Company owned approximately 21.14% of Light.

In December 2000, a subsidiary of the Company entered into an agreement with EDF to jointly acquire an additional 9.2% interest in Light, which is held by a subsidiary of Companhia Siderurgica Nacional (“CSN”). In January 2001, pursuant to this transaction, the Company acquired an additional 2.75% interest in Light for $114.6 million. At December 31, 2001, the Company owned approximately 23.89% of Light.

On February 6, 2002, a subsidiary of the Company exchanged with EDF, their shares representing a 23.89% interest in Light for 88% of the shares of AES Elpa S.A. (formerly Lightgas Ltda). AES Elpa owns 77% of the voting capital (31% of total capital) of Eletropaulo and 100% of AES Communications Rio. As a result of this transaction, AES acquired a controlling interest in Eletropaulo and began consolidating the subsidiary.

Other. In the second quarter of 2002, the Company sold its investment in Empresa de Infovias S.A. (“Infovias”), a telecommunications company in Brazil, for proceeds of $31 million to CEMIG, an

affiliated company. The loss recorded on the sale was approximately $14 million and is recorded as a loss on sale of assets and asset impairment expenses in the accompanying consolidated statements of operations.

In the second quarter of 2002, the Company recorded an impairment charge of approximately $40 million, after income taxes, on an equity method investment in a telecommunications company in Latin America held by EDC. The impairment charge resulted from sustained poor operating performance coupled with recent funding problems at the invested company.

During 2001, the Company lost operational control of Central Electricity Supply Corporation (“CESCO”), a distribution company located in the state of Orissa, India. CESCO is accounted for as a cost method investment.

In May 2000, the Company completed the acquisition of 100% of Tractebel Power Ltd (“TPL”) for approximately $67 million and assumed liabilities of approximately $200 million. TPL owned 46% of Nigen. The Company also acquired an additional 6% interest in Nigen from minority stockholders during the year ended December 31, 2000 through the issuance of approximately 99,000 common shares of AES stock valued at approximately $4.9 million. With the completion of these transactions, the Company owns approximately 98% of Nigen’s common stock and began consolidating its financial results beginning May 12, 2000. Approximately $100 million of the purchase price was allocated to excess of costs over net assets acquired and was amortized through January 1, 2002 at which time the Company adopted SFAS No. 142 and ceased amortization of goodwill.

In August 2000, a subsidiary of the Company acquired a 49% interest in Songas Limited (“Songas”) for approximately $40 million. The Company acquired an additional 16.79% of Songas for approximately $12.5 million, and the Company began consolidating this entity in 2002. Songas owns the Songo Songo Gas-to-Electricity Project in Tanzania. In December 2002, the Company signed a Sales Purchase Agreement to sell Songas. The sale is expected to close in early 2003. See Note 4 for further discussion of the transaction.

The following table presents summarized comparative financial information (in millions) for the Company’s investments in 50% or less owned investments accounted for using the equity method.

AS OF AND FOR THE YEARS ENDED DECEMBER 31,	2002		2001		2000

Revenues	$	2,832	$	6,147	$	6,241
Operating Income	695		1,717		1,989
Net Income	229		650		859
Current Assets	1,097		3,700		2,423
Noncurrent Assets	6,751		14,942		13,080
Current Liabilities	1,418		3,510		3,370
Noncurrent Liabilities	3,349		8,297		5,927
Stockholder’s Equity	3,081		6,835		6,206

In 2002, 2001 and 2000, the results of operations and the financial position of CEMIG were negatively impacted by the devaluation of the Brazilian Real and the impairment charge recorded in 2002. The Brazilian Real devalued 32%, 19% and 8% for the years ended December 31, 2002, 2001 and 2000, respectively.

The Company recorded $83 million, $210 million, and $64 million of pre-tax non-cash foreign currency transaction losses on its investments in Brazilian equity method affiliates during 2002, 2001 and 2000, respectively.

Relevant equity ownership percentages for our investments are presented below:

Affiliate	Country	2002		2001		2000
CEMIG	Brazil	21.62	%	21.62	%	21.62	%
Chigen affiliates	China	30.00		30.00		30.00
EDC affiliates	Venezuela	45.00		45.00		45.00
Eletropaulo	Brazil	—		50.43		49.60
Elsta	Netherlands	50.00		50.00		50.00
Gener affiliates	Chile	37.50		37.50		—
Infovias	Brazil	—		50.00		50.00
Itabo	Dominican Republic	25.00		25.00		25.00
Kingston Cogen Ltd	Canada	50.00		50.00		50.00
Light	Brazil	—		23.89		21.14
Medway Power, Ltd	United Kingdom	25.00		25.00		25.00
OPGC	India	49.00		49.00		49.00
Songas Limited	Tanzania	—		49.00		49.00

The Company’s after-tax share of undistributed earnings of affiliates included in consolidated retained earnings was $189 million, $462 million, and $370 million at December 31, 2002, 2001 and 2000, respectively. The Company charged and recognized construction revenues, management fee and interest on advances to its affiliates, which aggregated $7 million, $12 million, and $11 million for each of the years ended December 31, 2002, 2001 and 2000, respectively.

8. INVESTMENTS

The short-term investments were invested as follows (in millions):

	December 31,
	2002		2001

HELD-TO-MATURITY:
Certificates of deposit	$	135	$	106
Money market funds	40		1
Debt securities issued by foreign governments	—		2
Other	1		2
Subtotal	176		111
AVAILABLE-FOR-SALE:
Equity securities	—		103
Corporate Bonds	1		—
Subtotal	1		103
TRADING:
Equity securities	—		1
TOTAL	$	177	$	215

The Company’s investments are classified as held-to-maturity, available-for-sale or trading. The amortized cost and estimated fair value of the held-to-maturity and available-for-sale investments (other than the equity securities discussed below) were approximately the same. The trading investments are recorded at fair value. As of December 31, 2002 and 2001, approximately $170 million and $100 million, respectively, of investments classified as held-to-maturity, were restricted or pledged as collateral.

During the fourth quarter of 2001, the Company recorded gross unrealized losses of approximately $48 million related to available-for-sale equity securities, which were included in accumulated other comprehensive loss in the accompanying consolidated balance sheets.

9. LONG-TERM DEBT

NON-RECOURSE DEBT—Non-recourse debt at December 31, 2002 and 2001 consisted of the following (in millions):

	Interest Rate (1)		Final Maturity	December 31,
	Interest Rate (1)		Final Maturity	2002			2001

VARIABLE RATE:
Bank loans	7.75	%	2022	$	7,258		$	5,760
Commercial paper	5.72	%	2008	406			501
Notes and Bonds	8.82	%	2030	856			889
Debt to (or guaranteed by) multilateral or export credit agencies	5.16	%	2024	934			945
Other	13.14	%	2022	455			602
FIXED RATE:
Bank loans	9.43	%	2014	982			1,892
Commercial Paper	11.93	%	2005	146			63
Notes and bonds	8.82	%	2029	5,995			5,922
Debt to (or guaranteed by) multilateral or export credit agencies	4.89	%	2016	347			165
Other	1.72	%	2027	279			118
SUBTOTAL				17,658			16,857

Less: Non-recourse debt of discontinued operations				(3,739		)	(3,598		)

SUBTOTAL				13,919			13,259

Less: Current maturities				(3,291		)	(1,956		)

TOTAL				$	10,628		$	11,303

(1) Weighted average interest rate at December 31, 2002.

Non-recourse debt borrowings are primarily collateralized by the capital stock of the relevant subsidiary and in certain cases the physical assets of, and all significant agreements associated with, such business. Such debt is not a direct obligation of AES, the parent corporation. These non-recourse financings include structured project financings, acquisition financings, working capital facilities and all other consolidated debt of the subsidiaries. The Company has issued shares of common stock to consolidated subsidiaries as collateral under various borrowing arrangements (see Note 14).

The Company has interest rate swap and forward interest rate swap agreements for continuing operations, discontinued operations and businesses held for sale in an aggregate notional principal amount of approximately $4.4 billion at December 31, 2002. The interest rate swaps are accounted for at fair value (see Note 10). The swap agreements effectively change the variable interest rates on the portion of the debt covered by the notional amounts to fixed rates ranging from approximately 2.22% to 9.90%. The agreements expire at various dates from 2003 through 2023. In the event of nonperformance by the counter parties, the Company may be exposed to increased interest rates; however, the Company does not anticipate nonperformance by the counter parties, which are multinational financial institutions.

Certain commercial paper borrowings of subsidiaries are supported by letters of credit or lines of credit issued by various financial institutions. In the event of nonperformance or credit deterioration of these financial institutions, the Company may be exposed to the risk of higher effective interest rates. The Company does not believe that such nonperformance or credit deterioration is likely.

At December 31, 2002, Eletropaulo in Brazil and Edelap, Eden/Edes, Parana and TermoAndes, all in Argentina were each in default under certain of their outstanding project indebtedness. The total debt classified as current in the accompanying consolidated balance sheets related to such defaults was $1.4 billion at December 31, 2002.

None of the projects referred to above that are currently in default are owned by subsidiaries that currently meet the applicable definition of materiality in AES’s corporate debt agreements in order for such defaults to trigger an event of default or permit an acceleration under such indebtedness. However, as a result of additional dispositions of assets, other significant reductions in asset carrying values or other matters in the future that may impact the Company’s financial position and results of operations, it is possible that one or more of these subsidiaries could fall within the definition of a “material subsidiary” and thereby upon an acceleration trigger an event of default and possible acceleration of the indebtedness under the AES parent company’s senior notes, senior subordinated notes and junior subordinated notes.

As of December 31, 2002, AES Elpa and AES Transgas had approximately $542 million and $621 million of outstanding BNDES and BNDESPAR indebtedness, respectively. All of the common shares of Eletropaulo owned by AES Elpa are pledged to BNDES to secure the AES Elpa debt and all of the preferred shares of Eletropaulo owned by AES Transgas and AES Cemig Empreendimentos II, Ltd. (which owns approximately 7.4% of Eletropaulo’s preferred shares, representing 4.4% economic ownership of Eletropaulo) are pledged to BNDESPAR to secure AES Transgas debt. AES has pledged its share of the proceeds in the event of the sale of certain of its businesses in Brazil, including Sul, Uruguaiana, Eletronet and AES Communications Rio, to secure the indebtedness of AES Elpa to BNDES for the repayment of the debt of AES Elpa. The interests underlying the Company’s investments in Uruguaiana, AES Communications Rio and Eletronet have also been pledged as collateral to BNDES under the AES Elpa loan. As of December 31, 2002, Eletropaulo had $1.4 billion of outstanding indebtedness.

Due, in part, to the effects of power rationing, the sharp decline of the value of the Brazilian Real in dollar terms and the lack of access to the international capital markets, Eletropaulo is facing significant near-term debt payment obligations that must be extended, restructured, refinanced or repaid. AES Elpa failed to make a payment of $85 million due to BNDES on January 30, 2003, and AES Transgas failed to make a payment of $330 million due to BNDESPAR on February 28, 2003 in connection with the purchase of the preferred shares of Eletropaulo. All other participating holders of preferred shares of Eletropaulo accepted an offer from AES Transgas to defer payment until April 15, 2003, of approximately $6.5 million due by AES Transgas in connection with the deferred purchase by AES Transgas of Eletropaulo preferred stock from such former holders. As a result of such failure to pay the amounts due under the financing arrangements, BNDES has the right to call due the approximately $542 million of AES Elpa’s outstanding debt with BNDES and BNDESPAR has the right to call due approximately $621 million of AES Transgas’s outstanding debt with BNDESPAR. As a result of a cross default provision, BNDES also has the right to call due approximately $231 million loaned to Eletropaulo under the program in Brazil established to alleviate the effects of rationing on electricity companies. Due to BNDES’ right of acceleration and existing financial covenant and other defaults under Eletropaulo loan agreements, Eletropaulo’s commercial lenders have the right to call due approximately $836 million of indebtedness. In addition, Eletropaulo has indebtedness of approximately $514 million scheduled to mature in 2003. At December 31, 2002, Eletropaulo, AES Elpa and AES Transgas have a combined $1.9 billion of debt classified as current on the accompanying consolidated balance sheet.

Neither Eletropaulo, AES Elpa nor AES Transgas currently constitute “material subsidiaries” for purposes of the cross-default, cross acceleration and bankruptcy related events of default contained in AES’s parent company indebtedness. Furthermore, the Company believes that a bankruptcy proceeding would generally be an unattractive remedy for Eletropaulo’s lenders, as it could result in an intervention by ANEEL or a termination of Eletropaulo’s concession, and given that Eletropaulo is currently in negotiations to restructure such indebtedness, the Company believes such an outcome is unlikely. The Company cannot assure you, however, that such negotiations will be successful. As a result, AES may have to write-off some or all of the assets of Eletropaulo, AES Elpa or AES Transgas.

Under the industry-wide agreement reached in December 2001, Eletropaulo can receive Brazilian Real denominated loans from BNDES for revenues to be received through future tariff increases (see Note 1). Approximately $231 million was outstanding at December 31, 2002. The loans bear interest at the Selic (Brazilian interbank interest rate), 24.90% at December 31, 2002, plus 1%. Repayment will be made in 12 consecutive monthly installments beginning March 15, 2002. Eletropaulo is required to deposit a portion of its revenues in a restricted bank account as collateral for the loan. Future BNDES disbursements under the rationing agreement will have a repayment term of approximately 5 years.

On March 21, 2002, Fifoots was placed in administrative receivership by its lenders. Fifoots defaulted on its debt after electricity prices in the United Kingdom fell below its marginal costs. AES wrote off its investment of approximately $53 million in Fifoots during the first quarter of 2002.

RECOURSE DEBT—Recourse debt obligations are direct borrowings of the AES parent corporation and at December 31, 2002 and 2001, consisted of the following (in millions):

	Interest Rate (1)		Final Maturity	First Call Date (2)	2002			2001

Corporate revolving bank loan	—		2002	2000	$	—		$	70
Corporate revolving bank loan	8.10	%	2005	—	228			—
Term loan	—		2002	—	—			425
Term loan	—		2002	—	—			188
Term loan	8.12	%	2005	—	500			—
Term loan	7.99	%	2005	—	427			—
Term loan	7.94	%	2005	—	260			—
Senior notes	—		2002	—	—			300
Senior notes	8.00	%	2008	2000	199			200
Senior notes	9.50	%	2009	—	750			750
Senior notes	9.38	%	2010	—	850			850
Senior notes	8.88	%	2011	—	537			600
Senior notes	8.38	%	2011	—	217			196
Senior notes	8.75	%	2008	—	400			400
Senior notes	10.00	%	2005	—	258			—
Remarketable or Redeemable Securities	7.38	%	2013	2003	26			200
Senior subordinated notes	10.25	%	2006	2001	231			250
Senior subordinated notes	8.38	%	2007	2002	316			325
Senior subordinated notes	8.50	%	2007	2002	349			375
Senior subordinated debentures	8.88	%	2027	2004	125			125
Convertible junior subordinated debentures	4.50	%	2005	2001	150			150
Unamortized discounts					(19		)	(3		)
SUBTOTAL					5,804			5,401
Less: Current maturities					(26		)	(488		)
Total					$	5,778		$	4,913

(1) Interest rate at December 31, 2002.

(2) Except for the Remarketable or Redeemable Securities, which are discussed below, the first call date represents the date that the Company, at its option, can call the related debt.

In December 2002, the Company entered into secured credit facilities provided by a syndicate of financial institutions. The senior secured credit facilities include a $350 million senior secured revolving credit facility (all of which may be used for the issuance of standby and commercial letters of credit), a £52.25 million additional letter of credit, a $500 million tranche A term loan facility, a $427.25 million tranche B term loan facility and a $260.25 million tranche C term loan facility. The senior secured credit facilities refinanced in full: (i) an $850 million revolving credit facility due March 2003, (ii) a $425 million Term Loan Facility due August 2003, (iii) a £52.25 million letter of credit, and (iv) the $262.5 million EDC SELLS loans due 2003. The senior secured credit facilities will mature on December 12, 2005 provided that, on or prior to July 15, 2005, the Company’s 4.5% junior subordinated convertible debentures due August 15, 2005 have been refinanced to mature after December 12, 2005. If the Company’s 4.5% junior subordinated convertible debentures have not been refinanced in such a manner, then the senior secured credit facilities will mature on July 15, 2005.

In December 2002, concurrent with entering into the senior secured credit facilities, the Company issued $258 million of 10% Senior Secured Notes due December 12, 2005. The senior secured notes were issued in

exchange for: (i) $84 million of the $300 million 8.75% Senior Notes due December 2002, and (ii) $174 million of the $200 million Remarketable or Redeemable Securities (“ROARS”) due June 2003. The remaining $216 million of the $300 million 8.75% Senior Notes due December 2002 were redeemed in cash at or prior to maturity on December 15, 2002. The remaining $26 million of the ROARS remain outstanding and are scheduled to mature on June 15, 2003.

The Company has accounted for the debt refinancing in accordance with the requirements of Emerging Issues Task Force Issue No. 96-19 (EITF 96-19) “Debtors Accounting for a Modification of Debt Instruments.” Under EITF 96-19, the previously existing credit facility and notes which were exchanged are treated as extinguished. Accordingly, unamortized bond premiums and deferred financing costs related to the old notes, and early tender and other cash payments to the lenders were expensed resulting in a loss on extinguishment of $8 million which is included in other expense in the consolidated statement of operations. Payments of $42 million to third parties including legal, arrangement, and other fees associated with the newly issued debt instruments have been deferred and will be amortized over 3 years.

As part of the exchange offer, the Company entered into a written Treasury rate option that expires in June 2003. As of December 31, 2002, the value of this option was a liability of approximately $25 million.

Loans under the revolving credit facility and the term loan facilities bear interest, at the Company’s option, at the base rate or the Adjusted London Interbank Offered Rate (LIBOR) plus, in each case, applicable margins of 6.5% for LIBOR loans and 5.5% for base rate loans. Upon the occurrence of and during the continuance of any event of default, the applicable margin on both the LIBOR loans and the base rate loans will increase by 2.0%.

The Company will pay commitment fees (at a rate of 0.50% per annum) on the unused portion of the revolving credit facility. Such fees are payable quarterly in arrears. The Company will pay an additional fee (at a rate of 1.0%) of each lender’s commitment (in the case of the lenders under the senior secured revolving credit facility) or outstandings (in the case of the lenders under the tranche A, B and C term loan facilities) (in each case, after giving effect to any prepayment) under the senior secured facilities on January 31, 2004 and on January 31, 2005. The Company will also pay a letter of credit fee on the outstanding and undrawn amount of letters of credit issued under the senior secured credit facilities (at a rate of 6.5%) which shall be shared ratably by all lenders participating in the relevant letters of credit.

The senior secured credit facilities and senior secured notes are to be amortized as follows: on November 25, 2004, the Company is obligated to ratably repay each term loan facility (calculated, in the case of the tranche A term loan facility, on the sum of the original aggregate amount of the tranche A term loan facility plus the original aggregate commitments under the revolving credit facility) and cash collateralize the additional Drax letter of credit facility, and repay the notes in an amount such that, after giving effect to such repayment (and after giving effect to the mandatory prepayments made on or before such repayment), (i) the aggregate amount of such term loan facility is no greater than 50% of the original aggregate principal amount of such term loan facility, (ii) 50% of the maximum amount available under the letter of credit issued in respect thereof is cash collateralized or prepaid and (iii) the aggregate amount of such notes are no greater than 60% of the original principal amount of such notes.

The senior secured credit facilities are subject to mandatory prepayment on a ratable basis with the Company’s 10% senior secured exchange notes due 2005:

• with 50% of the first $600 million, 80% of between $600 million and $1 billion and 60% of in excess of $1 billion of the net cash proceeds received by the Company from certain sales or other dispositions of the property or assets by the Company or certain subsidiaries (including the issuance of equity securities by its subsidiaries), subject to certain exceptions and provided that the Senior Secured Notes will not share in the 50% of the first $600 million of such net asset sale proceeds; and

• with up to 75% of the Company’s adjusted free cash flow calculated at the end of the fiscal years 2003 and 2004.

As of March 21, 2003, approximately $276 million of proceeds from sales had been presented as mandatory prepayment in accordance with this agreement.

The senior secured credit facilities are also subject to mandatory prepayment:

• with the net cash proceeds received by the Company from the issuance of debt securities by the Company, subject to certain exceptions, including permitted financing and the issuance of up to $225 million of new debt;

• with 50% of the net cash proceeds received from the issuance of equity securities by the Company, subject to certain exceptions and provided that $87.5 million of the first $162.5 million of net cash proceeds from the sale of equity shall be applied to repay the tranche C loans and the balance of the first such $162.5 million to repay the loans to AES NY Funding LLC; and

• with all of the net cash proceeds received by the Company from the issuance of debt securities, subject to certain exceptions, by its subsidiary, IPALCO Enterprises, Inc., and by certain other of its domestic subsidiaries that guarantee its obligations under the senior secured credit facilities and with 75% of the net cash proceeds received by the Company from the issuance of debt securities by its other subsidiaries, other than the net cash proceeds received by the Company from the first $100 million of additional debt securities issued by such other subsidiaries. Refinancings of certain types are excluded from the requirement to prepay.

Certain of the Company’s obligations under the senior secured credit facilities are guaranteed by its direct subsidiaries through which the Company owns its interests in the Shady Point, Hawaii, Southland, Warrior Run and EDC businesses. The Company’s obligations under the senior secured credit facilities are, subject to certain exceptions, substantially secured, equally and ratably with its 10.0% senior secured notes due 2005, by: (i) all of the capital stock of domestic subsidiaries owned directly by the Company and 65% of the capital stock of certain foreign subsidiaries owned directly or indirectly by the Company and (ii) certain intercompany receivables, certain intercompany notes and certain intercompany tax sharing agreements. The Company’s obligations under the senior secured credit facilities are secured equally and ratably with the Company’s obligations under the senior secured notes.

The Junior Subordinated Debentures are convertible into common stock of the Company at the option of the holder at any time at or before maturity, unless previously redeemed, at a conversion price of $27.00 per share.

FUTURE MATURITIES OF DEBT—Scheduled maturities of total debt for continuing operations at December 31, 2002 are (in millions):

2003	$	3,317

2004	2,070

2005	2,634

2006	1,597

2007	1,334

Thereafter	8,771

Total	$	19,723

Scheduled maturities of total debt for discontinued operations at December 31, 2002 are (in millions):

2003	$	228
2004	217
2005	123
2006	116
2007	171
Thereafter	2,884

Total	$	3,739

COVENANTS—The terms of the Company’s senior and subordinated notes contain certain restrictive financial and non-financial covenants. The financial covenants provide for, among other items, maintenance of a minimum consolidated net worth, minimum consolidated cash flow coverage ratio and minimum ratio of recourse debt to recourse capital. The non-financial covenants include limitations on the Company’s ability to incur additional debt, pay dividends to stockholders, provide guarantees and enter into sale and leaseback transactions.

The senior secured credit facilities contain customary covenants and restrictions on the Company’s ability to engage in certain activities, including, but not limited to:

• limitations on other indebtedness, liens, investments and guarantees;

• restrictions on dividends and redemptions and payments of unsecured and subordinated debt and the use of proceeds; and

• restrictions on mergers and acquisitions, sales of assets, leases, transactions with affiliates and off balance sheet and derivative arrangements.

The senior secured credit facilities also contain financial covenants requiring the Company to maintain certain financial ratios including:

• collateral coverage ratio, calculated quarterly, which provides that a minimum ratio of the book value of pledged assets to secured debt must be maintained at all times;

• cash flow to interest coverage ratio, calculated quarterly, which provides that a minimum ratio of the Company’s adjusted operating cash flow to the Company’s interest charges must be maintained at all times;

• recourse debt to cash flow ratio, calculated quarterly, which provides that the ratio of the Company’s total recourse debt to the Company’s adjusted operating cash flow must not exceed a maximum at any time of calculation; and

• future borrowings and letter of credit issuances under the senior secured credit facilities will be subject to customary borrowing conditions, including the absence of an event of default and the absence of any material adverse change.

The terms of the Company’s non-recourse debt, which is debt held at subsidiaries, include certain financial and non-financial covenants. These covenants are limited to subsidiary activity and vary among the subsidiaries. These covenants may include but are not limited to maintenance of certain reserves, minimum levels of working capital and limitations on incurring additional indebtedness.

As of December 31, 2002, approximately $483 million of restricted cash was maintained in accordance with certain covenants of the debt agreements, and these amounts were included within debt service reserves and other deposits in the consolidated balance sheets.

Various lender and governmental provisions restrict the ability of the Company’s subsidiaries to transfer their net assets to the parent company. Such restricted net assets of subsidiaries amounted to approximately $6 billion at December 31, 2002.

10. DERIVATIVE INSTRUMENTS

Effective January 1, 2001, AES adopted SFAS No. 133, “Accounting For Derivative Instruments And Hedging Activities,” which, as amended, establishes accounting and reporting standards for derivative instruments and hedging activities. The adoption of SFAS No. 133 on January 1, 2001, resulted in a cumulative reduction to income of less than $1 million, net of deferred income tax effects, and a cumulative reduction of accumulated other comprehensive income in stockholders’ equity of $93 million, net of deferred income tax effects.

For the years ended December 31, 2002 and 2001, the impacts of changes in derivative fair value, net of income taxes, primarily related to derivatives that do not qualify for hedge accounting treatment, were a charge of $12 million and a charge of $36 million, respectively. These amounts include a charge of $12 million and a charge of $6 million, after income taxes, related to the ineffective portion of derivatives qualifying as cash flow and fair value hedges for the years ended December 31, 2002 and 2001, respectively which is primarily recorded in other expense. There was no net effect on results of operations for the years ended December 31, 2002 and 2001, of derivative and non-derivative instruments that have been designated and qualified as hedging net investments in foreign operations.

Approximately $112 million of other comprehensive loss related to derivative instruments as of December 31, 2002 is expected to be recognized as a reduction to income from continuing operations over the next twelve months. A portion of this amount is expected to be offset by the effects of hedge accounting. The balance in accumulated other comprehensive loss related to derivative transactions will be reclassified into earnings as interest expense is recognized for hedges of interest rate risk, as depreciation is recorded for hedges of capitalized interest, as foreign currency transaction and translation gains and losses are recognized for hedges of foreign currency exposure, and as electric and gas sales and purchases are recognized for hedges of forecasted electric and gas transactions. Amounts recorded in accumulated other comprehensive income (loss), after income taxes, during the years ended December 31, 2002 and 2001, were as follows (in millions):

	Years Ended December 31,
	2002			2001
Balance, beginning of year	$	(121	)	$	—
Transition adjustment on January 1, 2001	—			(93		)
Reclassification to earnings	106			32

Change in fair value	(383		)	(60		)

Balance, December 31	$	(398	)	$	(121	)

AES utilizes derivative financial instruments to hedge interest rate risk, foreign exchange risk and commodity price risk. The Company utilizes interest rate swap, cap and floor agreements to hedge interest rate risk on floating rate debt. The majority of AES’s interest rate derivatives are designated and qualify as cash flow hedges. Certain derivatives are not designated as hedging instruments, primarily because they do not qualify for hedge accounting treatment as defined by SFAS No. 133. The purpose of these instruments is to economically hedge interest rate risk, foreign exchange risk or commodity price risk. However, certain features of these contracts, primarily the inclusion of written options, cause them to not qualify for hedge accounting.

Currency forward and swap agreements are utilized by the Company to hedge foreign exchange risk which is a result of AES or one of its subsidiaries entering into monetary obligations in currencies other than its own functional currency. A portion of these contracts are designated and qualify as either fair value or cash flow hedges. Certain derivative instruments and other non-derivative instruments are designated and qualify as hedges of the foreign currency exposure of a net investment in a foreign operation. Approximately $13 million and $1 million of transaction losses, after income taxes, related to derivative and non-derivative instruments that have been designated as hedges of the foreign currency exposure of net investments in foreign operations are included in the foreign currency cumulative translation adjustment for the years ended December 31, 2002 and 2001, respectively.

The Company utilizes electric and gas derivative instruments, including swaps, options, forwards and futures, to hedge the risk related to electricity and gas sales and purchases. The majority of AES’s electric and gas derivatives are designated and qualify as cash flow hedges.

The maximum length of time over which AES is hedging its exposure to variability in future cash flows for forecasted transactions, excluding forecasted transactions related to the payment of variable interest, is twenty-eight years. For the years ended December 31, 2002 and 2001, charges of $1 million and $4 million, after income taxes, were recorded for cash flow hedges that were discontinued because it became probable that the hedged forecasted transactions will not occur. A portion of the 2001 charge has been classified as discontinued operations. For the year ended December 31, 2002, two fair value hedges were discontinued because they failed to meet the hedge effectiveness criteria of SFAS No. 133. The discontinuance of hedge accounting for these contracts did not have an impact on earnings. For the year ended December 31, 2001, no fair value hedges were de-recognized or discontinued.

On April 1, 2002, Derivative Implementation Group (“DIG”) Issue C-15, “Normal Purchases and Normal Sales Exception for Option Type Contracts and Forward Contracts in Electricity” became effective. DIG Issue C-15 is an interpretation of SFAS, No. 133, “Accounting for Derivative Instruments and Hedging Activities”, recognized by the FASB with respect to the application of SFAS No. 133. DIG Issue C-15 allows certain contracts for the purchase or sale of electricity, both forward contracts and option contracts, to qualify for the normal purchases and normal sales exemption and does not require these contracts to be accounted for as derivatives under SFAS No. 133. In order for contracts to qualify for this exemption, they must meet certain criteria, which include the requirement for physical delivery of the electricity to be purchased or sold under the contract only in the normal course of business. Additionally, contracts that have a price based on an underlying index that is not clearly and closely related to the electricity being sold or purchased or that are denominated in a currency that is foreign to the buyer or seller are not considered normal purchases and normal sales and are required to be accounted for as derivatives under SFAS No. 133.

The Company has two contracts that previously qualified for the normal purchases and normal sales exemption of SFAS No. 133, but no longer qualify for this exemption due to the effectiveness of DIG Issue C-15 on April 1, 2002. Accordingly, these contracts are required to be accounted for as derivatives at fair value. The two contracts are a 30-year power sales contract at the Warrior Run plant in Maryland and a 3-year power sales contract at the Deepwater plant in Texas. Approximately 28 years remain on the Warrior Run contract and approximately two years remain on the Deepwater contract.

The contracts were valued as of April 1, 2002, and an asset and a corresponding gain of $127 million, net of income taxes, was recorded as a cumulative effect of a change in accounting principle in the second quarter of 2002. The majority of the gain recorded relates to the Warrior Run contract, as the asset value of the Deepwater contract on April 1, 2002, was less than $1 million. The Warrior Run contract qualifies and was designated as a cash flow hedge as defined by SFAS No. 133 and hedge accounting is applied for this contract subsequent to April 1, 2002.

The contract valuations were performed using current forward electricity and gas price quotes and current market data for other contract variables. The forward curves used to value the contracts include certain assumptions, including projections of future electricity and gas prices in periods where future prices are not quoted. Fluctuations in market prices and their impact on the assumptions will cause the value of these contracts to change. Such fluctuations will increase the volatility of the Company’s reported results of operations.

11. COMMITMENTS, CONTINGENCIES AND RISKS

OPERATING LEASES—As of December 31, 2002, the Company was obligated under long-term non-cancelable operating leases, primarily for office rental and site leases. Rental expense for operating leases, excluding amounts related to the sale/leaseback discussed below, was $31 million $32 million and $13 million in the years ended December 31, 2002, 2001 and 2000, respectively, including commitments of businesses classified as discontinued amounting to $6 million in 2002, $18 million in 2001 and $6 million in 2000.

The future minimum lease commitments under these leases are as follows (in millions):

	Total		Discontinued Operations

2003	$	30	$	6
2004	20		5
2005	15		4
2006	11		2
2007	9		2
Thereafter	84		2

Total	$	169	$	21

SALE/LEASEBACK—In May 1999, a subsidiary of the Company acquired six electric generating stations from New York State Electric and Gas (“NYSEG”). Concurrently, the subsidiary sold two of the plants to an unrelated third party for $666 million and simultaneously entered into a leasing arrangement with the unrelated party. This transaction has been accounted for as a sale/leaseback with operating lease treatment. Rental expense was $54 million, $58 million and $54 million in 2002, 2001 and 2000, respectively.

Future minimum lease commitments are as follows (in millions): In connection with the lease of the two power plants, the subsidiary is required to maintain a rent reserve account equal to the maximum semi-annual payment with respect to the sum of the basic rent (other then deferrable basic rent) and fixed charges expected to become due in the immediately succeeding three-year period. At December 31, 2002, 2001 and 2000, the amount deposited in the rent reserve account approximated

$32 million, $32 million and $31 million, respectively. This amount is included in restricted cash and can only be utilized to satisfy lease obligations.

2003	$	58
2004	63
2005	59
2006	62
2007	63
Thereafter	1,252

Total	$	1,557

In connection with the lease agreements, the Subsidiary is required to maintain an additional liquidity account. The required balance in the additional liquidity account was initially equal to the greater of $65 million less the balance in the rent reserve account or $29 million. As of December 31, 2002, the Subsidiary had fulfilled its obligation to fund the additional liquidity account by establishing a letter of credit, issued by Fleet Bank in the stated amount of approximately $36 million (the Additional Liquidity Letter of Credit). This letter of credit was established by AES for the benefit of the Subsidiary. However, the Subsidiary is obligated to replenish or replace this letter of credit in the event it is drawn upon or needs to be replaced.

CONTRACTS—Operating subsidiaries of the Company have entered into “take-or-pay” contracts for the purchase of electricity from third parties. Purchases in 2002 were approximately $1,263 million, including purchases of businesses classified as discontinued of $44 million.

The future commitments under these contracts are as follows (in millions):

	Total		Discontinued Operations

2003	$	983	$	46
2004	831		15
2005	658		8
2006	477		—
2007	474		—
Thereafter	6,663		—

Total	$	10,086	$	69

Operating subsidiaries of the Company have entered into various long-term contracts for the purchase of fuel subject to termination only in certain limited circumstances. Purchases in 2002 were approximately $642 million, including commitments of businesses classified as discontinued of $403 million.

The future commitments under contracts are as follows (in millions):

	Total		Discontinued Operations

2003	$	671	$	457
2004	583		358
2005	440		202
2006	255		58
2007	227		1
Thereafter	2,729		—

Total	$	4,905	$	1,076

In connection with an electricity sales agreement, a subsidiary of the Company assumed contingent liabilities related to plant performance. If plant availability and contract performance specifications are not met, then a subsidiary of the Company may be required to make payments of up to $137 million to a third party under the terms of a power sales agreement.

Several of the Company’s power plants rely on power sales contracts with one or a limited number of entities for the majority of, and in some case all of, the relevant plant’s output over the term of the power sales contract. The remaining term of power sales contracts related to the Company’s power plants range from 5 to 28 years. However, the operations of such plants are dependent on the continued performance by customers and suppliers of their obligations under the relevant power sales contract, and, in particular, on the credit quality of the purchasers. If a substantial portion of the Company’s long-term power sales contracts were modified or terminated, the Company would be adversely affected to the extent that it was unable to find other customers at the same level of contract profitability. Some of the Company’s long-term power sales agreements are for prices above current spot market prices. The loss of one or more significant power sales contracts or the failure by any of the parties to a power sales contract to fulfill its obligations thereunder could have a material adverse impact on the Company’s business, results of operations and financial condition.

Two of these types of contracts, at the Company’s Warrior Run and Beaver Valley plants, are with customers owned by Allegheny Energy, Inc., which has encountered financial difficulty due to its energy trading business. The Company does not believe the financial difficulties of Allegheny Energy, Inc. will have a material adverse effect on the performance of those customers; however, there can be no assurance that a further deterioration in Allegheny Energy, Inc.’s financial condition will not have a material adverse effect on the ability of those customers to perform their operations. Other customers are commercial entities that have no such restrictions, and therefore, may be of lesser credit quality, which increases the risk of payment default to AES. One commercial customer at three of the Company’s subsidiaries, Williams Energy, has recently encountered financial difficulties related to its electricity trading operations and has been downgraded below investment grade by a number of ratings agencies. There can be no assurance that Williams Energy will continue to meet its contractual commitments. The Company’s investment in these subsidiaries was approximately $184 million at December 31, 2002. For the year ended December 31, 2002, the Company recorded $5.9 million of net income from the three subsidiaries.

Additionally, two AES competitive supply businesses, AES Wolf Hollow, L.P. and Granite Ridge have fuel supply agreements with El Paso Merchant Energy L.P. an affiliate of El Paso Corp., which has encountered financial difficulties. The Company does not believe the financial difficulties of El Paso Corp. will have a material adverse effect on El Paso Merchant Energy L.P.’s performance under the supply agreement; however, there can be no assurance that a further deterioration in El Paso Corp’s financial condition will not have a material adverse effect on the ability of El Paso Merchant Energy L.P. to perform its obligations. While El Paso Corp’s financial condition may not have a material adverse effect on El Paso Merchant Energy, L.P. at this time, it could lead to a default under the AES Wolf Hollow fuel supply agreement, in which case AES Wolf Hollow, L.P.’s lenders may seek to declare a default under its credit agreements. AES Wolf Hollow, L.P. is working in concert with its lenders to explore options to avoid such a default.

During 2000, the wholesale electricity market in California experienced a significant imbalance in the supply of, and demand for electricity, which resulted in significant electricity price increases and volatility. California’s two largest utilities were required to purchase wholesale power at higher market prices and to sell it at fixed prices to retail end users. Because the cost of wholesale power exceeded the price the utilities charged their retail customers, these utilities are facing severe financial difficulties. There can be no assurances that such utilities can, or will choose to, honor their financial commitments. In the event that such utilities become insolvent or otherwise choose not to honor their commitments, creditors (including certain of the Company’s subsidiaries) may seek to exercise whatever

remedies may be available, including, among other things, placing the utilities into involuntary bankruptcy. There can be no assurances that amounts owing directly or indirectly from such utilities will be recovered. In addition, the California Independent System Operator has sought a Temporary Restraining Order over some of the generators, including AES subsidiaries, arguing that, in times of declared emergencies, generators are required to continue to provide electricity to the market even if there is no credit-worthy purchaser for the electricity. The bulk of the Company’s revenues in California are not subject to this credit risk, because they are generated under a tolling agreement entered into by AES Southland. But the Company’s other subsidiaries have some exposure to this risk. At December 31, 2002, 2001 and 2000, the Company had receivables of approximately $4 million, $13 million and $27 million, respectively, that are subject to this credit risk. In addition, because these utilities have defaulted on amounts due in the state sanctioned markets, the markets have sought to recover those amounts pro rata from other market participants, including certain of the Company’s subsidiaries. Enron Corporation and several of its affiliates filed Chapter 11 bankruptcy petitions on December 2, 2001, in the U.S. Bankruptcy Court for the Southern District of New York. At that time, several of the Company’s subsidiaries had outstanding long-term contracts for gas and electricity purchases and sales with Enron and its subsidiaries. The Company does not believe its exposure under these contracts is material and has not recorded any liability associated with these contracts. Other Enron subsidiaries were also under contract to provide engineering, procurement and construction (“EPC”) services on three of the Company’s greenfield construction projects, including AES Wolf Hollow in Texas, AES Lake Worth Generation in Florida, and the AES Ebute Barge project in Nigeria. To avoid delay, each respective AES subsidiary has put into place transition arrangements that allow the subcontractors to continue working on the project, while alternative arrangements for completing the projects are investigated. Such alternative arrangements could include, but are not limited to, procuring a partner for the current EPC contractor, replacing the current EPC contractor entirely or assigning the contract to the largest subcontractor. Although disruption or delay in the progress of construction has not occurred to date, there can be no assurance that such disruption or delay will not occur in the future. The Company does not believe any such disruption or delay will have a material adverse effect on the results of operations or financial position of the Company.

ENVIRONMENTAL—As of December 31, 2002, the Company has recorded cumulative liabilities associated with acquired generation plants of approximately $31 million for projected environmental remediation costs. During 2000, the Company incurred a $17 million environmental fine and was required to incur capital expenditures related to excess nitrogen oxide air emissions at certain of its generating facilities in California.

The EPA has commenced an industry-wide investigation of coal-fired electric power generators to determine compliance with environmental requirements under the Federal Clean Air Act associated with repairs, maintenance, modifications and operational changes made to the facilities over the years. The EPA’s focus is on whether the changes were subject to new source review or new performance standards, and whether best available control technology was or should have been used. On August 4, 1999, the EPA issued a Notice of Violation (“NOV”) to the Company’s Beaver Valley plant, generally alleging that the facility failed to obtain the necessary permits in connection with certain changes made to the facility in the mid-to-late 1980s. The Company believes it has meritorious defenses to any actions asserted against it and expects to vigorously defend itself against the allegations.

In May 2000, the New York State Department of Environmental Conservation (“DEC”) issued a NOV to NYSEG for violations of the Federal Clean Air Act and the New York Environmental Conservation Law at the Greenidge and Westover plants related to NYSEG’s alleged failure to undergo an air permitting review prior to making repairs and improvements during the 1980s and 1990s. Pursuant to the agreement relating to the acquisition of the plants from NYSEG, AES Eastern Energy agreed with NYSEG that AES Eastern Energy will assume responsibility for the NOV, subject to a reservation of AES Eastern Energy’s right to assert any applicable exception to its contractual undertaking to assume pre-existing environmental liabilities. The Company believes it has meritorious defenses to any actions

asserted against it and expects to vigorously defend itself against the allegations; however, the NOV issued by the DEC, and any additional enforcement actions that might be brought by the New York State Attorney General, the DEC or the U.S. Environmental Protection Agency (“EPA”), against the Somerset, Cayuga, Greenidge or Westover plants, might result in the imposition of penalties and might require further emission reductions at those plants. In addition to the NOV, the DEC alleged, after our acquisition of the Cayuga, Westover, Greenidge, Hickling and Jennison plants from NYSEG in May 1999, air permit violations at each of those plants. Specifically, DEC has alleged exceedences of the opacity emissions limitations at these plants. With respect to pre-May 1999 and post-May 1999 violations, respectively, DEC has notified NYSEG, on the one hand, and AES, on the other, of their respective liability for such alleged violations. To remediate these alleged violations, DEC has proposed that each of AES and NYSEG pay fines and penalties in excess of $100,000. Resolution of this matter could also require AES to install additional pollution control technology at these plants. NYSEG has asserted a claim against AES for indemnification against all penalties and other related costs arising out of DEC’s allegations. However, no formal consent order has been issued by the DEC.

The Company’s generating plants are subject to emission regulations. The regulations may result in increased operating costs or the purchase of additional pollution control equipment if emission levels are exceeded.

The Company reviews its obligations as it relates to compliance with environmental laws, including site restoration and remediation. Because of the uncertainties associated with environmental assessment and remediation activities, future costs of compliance or remediation could be higher or lower than the amount currently accrued. Based on currently available information, the Company does not believe that any costs incurred in excess of those currently accrued will have a material effect on the financial condition and results of operations of the Company.

DERIVATIVES—Certain subsidiaries and an affiliate of the Company entered into interest rate, foreign currency, electricity and gas derivative contracts with various counterparties, and as a result, the Company is exposed to the risk of nonperformance by its counterparties. The Company does not anticipate nonperformance by the counter parties.

The Company is exposed to market risks on derivative contracts and on other unmatched commitments to purchase and sell energy on a price and quantity basis. Such market risks are monitored to limit the Company’s exposure.

GUARANTEES—In connection with certain of its project financing, acquisition, and power purchase agreements, AES has expressly undertaken limited obligations and commitments, most of which will only be effective or will be terminated upon the occurrence of future events. These obligations and commitments, excluding those collateralized by letter-of-credit and other obligations discussed below, were limited as of December 31, 2002, by the terms of the agreements, to an aggregate of approximately $627 million representing 51 agreements with individual exposures ranging from less than $1 million up to $100 million. Of this amount, $219 million represents credit enhancements for non-recourse debt that is recorded in the accompanying consolidated balance sheets. The Company is also obligated under other commitments, which are limited to amounts, or percentages of amounts, received by AES as distributions from its subsidiaries. This amounted to $25 million as of December 31, 2002. In addition, the Company has commitments to fund its equity in projects currently under development or in construction. At December 31, 2002, such commitments to invest amounted to approximately $65 million.

In the normal course of business, AES and certain of its subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries. Such agreements include guarantees, letters of credit and surety bonds. These agreements are entered into primarily to support or enhance the creditworthiness otherwise achieved by a subsidiary on a stand-

alone basis, thereby facilitating the availability of sufficient credit to accomplish the subsidiaries’ intended business purposes.

As prescribed in Financial Accounting Standards Board Interpretation No. 45 (“FIN 45”), “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” the Company will begin recording a liability for the fair value of obligations it undertakes for guarantees issued after December 31, 2002. The disclosure provisions of FIN 45 are effective for financial statements of interim or annual periods ending after December 15, 2002. The following information represents the disclosures required by FIN 45. The interpretation does not encompass guarantees of the Company’s own future performance; however, these guarantees are included in the presentation below. The Company does not expect adoption of the liability recognition provisions of FIN 45 to have a material impact on our financial position or results of operations.

Contingent contractual obligations	Amount		Number of Agreements	Term Range (years)	Maximum Exposure Range for Each Agreement	Credit Enhancements for Non-Recourse Debt		Performance Related Obligations
	(amounts in $millions, except agreements and years)

Guarantees	$	652	52	<1 - 20+	<$1 - $100	$	273	$	379
Letters of credit — under the Revolver.	104		14	<1 - 2	<$1 - $36	51		53
Letters of credit — outside the Revolver	109		5	<1 - 2	<$1 - $84	84		25
Surety bonds	6		6	<1	<$1 - $3	—		6

Total	$	871	77			$	408	$	463

Amounts identified as credit enhancements for non-recourse debt represent credit enhancements made by the parent company and other subsidiaries for the benefit of the lenders associated with the non-recourse debt recorded as liabilities in the accompanying consolidated balance sheets. These obligations are designed to cover potential risks and only require payment if certain targets are not met or certain contingencies occur. Amounts identified as performance related obligations primarily represent future performance commitments which the Company expects to fulfill within the normal course of business. Amounts presented in the above table represent the Company’s current undiscounted exposure to guarantees, and the range of maximum undiscounted potential exposure to the Company as of December 31, 2002. Guarantee termination provisions vary from less than 1 year to greater than 20 years. Some result from the repayment of the underlying debt or obligations, the end of a contract period, assignment, asset sale, change in credit rating, or elapsed time.

The risks associated with these obligations include change of control, construction cost overruns, political risk, tax indemnities, spot market power prices, supplier support and liquidated damages under power purchase agreements for projects in development, under construction and operating. While the Company does not expect to be required to fund any material amounts under these contingent contractual obligations during 2003 or beyond that are not recorded on the balance sheet, many of the events which would give rise to such an obligation are beyond the Company’s control. There can be no assurance that the Company would have adequate sources of liquidity to fund its obligations under these contingent contractual obligations if it were required to make substantial payments thereunder.

LETTERS OF CREDIT—At December 31, 2002, the Company had $213 million in letters of credit outstanding representing 19 agreements with individual exposures ranging from less than $1 million up to $84 million, which operate to guarantee performance relating to certain project development and construction activities and subsidiary operations. Of this amount, $135 million represent credit enhancements for non-recourse debt that is recorded in the accompanying consolidated balance sheets.

The Company pays a letter-of-credit fee ranging from 1.35% to 7.00% per annum on the outstanding amounts. In addition, the Company had $6 million in surety bonds outstanding at December 31, 2002.

LITIGATION— In September 1999, a judge in the Brazilian appellate state court of Minas Gerais granted a temporary injunction suspending the effectiveness of a shareholders’ agreement between Southern Electric do Brasil Participacoes Ltda. (“SEB”) and the state of Minas Gerais concerning CEMIG. This shareholders’ agreement granted SEB certain rights and powers in respect of CEMIG (the “Special Rights”). The temporary injunction was granted pending determination by the lower state court of whether the shareholders’ agreement could grant SEB the Special Rights. In October 1999, the full state appellate court upheld the temporary injunction. In March 2000, the lower state court in Minas Gerais ruled on the merits of the case, holding that the shareholders’ agreement was invalid where it purported to grant SEB the Special Rights. In August 2001, the state appellate court denied an appeal of the merits decision, and extended the injunction. In October 2001, SEB filed two appeals against the decision on the merits of the state appellate court, one to the Federal Superior Court and the other to the Supreme Court of Justice. The state appellate court denied access of these two appeals to the higher courts, and in August 2002, SEB filed two interlocutory appeals against such decision, one directed to the Federal Superior Court and the other to the Supreme Court of Justice. These appeals continue to be pending. SEB intends to vigorously pursue by all legal means a restoration of the value of its investment in CEMIG. However, there can be no assurances that it will be successful in its efforts. Failure to prevail in this matter may limit the SEB’s influence on the daily operation of CEMIG.

In November 2000, the Company was named in a purported class action suit along with six other defendants alleging unlawful manipulation of the California wholesale electricity market, resulting in inflated wholesale electricity prices throughout California. Alleged causes of action include violation of the Cartwright Act, the California Unfair Trade Practices Act and the California Consumers Legal Remedies Act. The case was consolidated with five other lawsuits alleging similar claims against other defendants. In March 2002, the plaintiffs filed a new master complaint in the consolidated action, which asserted the claims asserted in the earlier action and names the Company, AES Redondo Beach, L.L.C., AES Alamitos, L.L.C., and AES Huntington Beach, L.L.C. as defendants. In May 2002, the case was removed by certain cross-defendants from San Diego County Superior Court to the United States District Court for the Southern District of California. Defendants there filed a motion to dismiss the action in its entirety. The District Court subsequently ordered the case remanded back to the state court which order is currently on appeal to the United States Court of Appeals for the Ninth Circuit. The Company believes it has meritorious defenses to any actions asserted against it and expects that it will defend itself vigorously against the allegations.

In addition, the crisis in the California wholesale power markets has directly or indirectly resulted in several administrative and legal actions involving the Company’s businesses in California. Each of the Company’s businesses in California (AES Placerita and AES Southland, which is comprised of AES Redondo Beach, AES Alamitos, and AES Huntington Beach) is subject to overlapping state investigations by the California Attorney General’s Office and the California Public Utility Commission. The businesses have cooperated with the investigation and responded to multiple requests for the production of documents and data surrounding the operation and bidding behavior of the plants.

In August 2000, the Federal Energy Regulatory Commission (“FERC”) announced an investigation into California wholesale power through the ISO and PX spot markets, in order to determine whether prices were unjust and unreasonable. The Administrative Law Judge issued proposed findings of fact and the FERC affirmed those findings in large part. The FERC order would not cause AES Southland to pay refunds. The FERC has ordered the ISO and PX to calculate refunds that would be owed by AES Placerita and others. The order is being appealed.

In a separate investigation that spun out of the initial California investigation, FERC Staff is investigating physical withholding by generators. AES Southland and AES Placerita have received data requests from FERC Staff, have responded to those data requests, and have cooperated fully with the investigation. The physical withholding investigation is ongoing.

FERC also initiated an investigation in to economic withholding. AES Placerita has received data requests from FERC Staff, has responded to those data requests, and has cooperated fully with the investigation. The economic withholding investigation is ongoing.

In July 2001, a petition was filed against CESCO, an affiliate of the Company by the Grid Corporation of Orissa, India (“Gridco”), with the Orissa Electricity Regulatory Commission (“OERC”), alleging that CESCO has defaulted on its obligations as a government licensed distribution company; that CESCO management abandoned the management of CESCO; and asking for interim measures of protection, including the appointment of a government regulator to manage CESCO. Gridco, a state owned entity, is the sole energy wholesaler to CESCO. In August 2001, the management of CESCO was handed over by the OERC to a government administrator that was appointed by the OERC. By its Order of August 2001, the OERC held that the Company and other CESCO shareholders were not proper parties to the OERC proceeding and terminated the proceedings against the Company and other CESCO shareholders. Subsequently, OERC issued notices regarding the OERC proceedings to the Company and the other CESCO shareholders. The Company has advised OERC that the Company was not a party. In October 2003, OERC again forwarded a notice to the Company advising of a hearing in the OERC matter scheduled for November 2003. The Company, in November 2003, again advised the OERC that the Company is not subject to the OERC proceedings. Gridco also has asserted that a Letter of Comfort issued by the Company in connection with the Company’s investment in CESCO obligates the Company to provide additional financial support to cover CESCO’s financial obligations. In December 2001, a notice to arbitrate pursuant to the Indian Arbitration and Conciliation Act of 1996 was served on the Company by Gridco pursuant to the terms of the CESCO Shareholder’s Agreement (“SHA”), between Gridco, the Company, AES ODPL, and Jyoti Structures. The notice to arbitrate failed to detail the disputes under the SHA for which the Arbitration had been initiated. After both parties had appointed arbitrators, and those two arbitrators appointed the third neutral arbitrator, Gridco filed a motion with the India Supreme Court seeking the removal of AES’ arbitrator and the neutral chairman arbitrator. In the fall of 2002, the Supreme Court rejected Gridco’s motion to remove the arbitrators. Gridco has dropped the challenge of the appointment of neutral chairman arbitrator; however, it retained the challenge of removal of AES’ arbitrator. Although that motion remains pending, the parties have filed their respective statement of claims, counter claims and defenses. On or about July 26, 2003, Gridco filed a motion in the District Court of Bhubaneshwar, India, seeking a stay of the arbitration and requesting that the District Court terminate the mandate of the neutral chairman arbitrator. The District Court gave a stay order, and the case was scheduled to be heard in mid November 2003. Thereafter, pursuant to a separate motion filed with the Court in India, a further temporary stay of the arbitration proceedings was granted until the India Court issued a decision on whether or not to grant a permanent stay of the arbitration. In the interim, and pending a decision by the Court as to whether to grant a permanent stay, no new

proceedings have been scheduled for the arbitration. The Company believes that it has meritorious defenses to any actions asserted against it and expects that it will defend itself vigorously against the allegations.

In November 2002, the Company was served with a grand jury subpoena issued on application of the United States Attorney for the Northern District of California. The subpoena sought, inter alia, certain categories of documents related to the generation and sale of electricity in California from January 1998 to the present. The Company complied fully with its legal obligations in responding to the subpoena.

In April 2002, IPALCO and certain former officers and directors of IPALCO were named as defendants in a purported class action lawsuit filed in the United States District Court for the Southern District of Indiana. On May 28, 2002, an amended complaint was filed in the lawsuit. The amended complaint asserts that former members of the pension committee for the thrift plan breached their fiduciary duties to the plaintiffs under the Employees Retirement Income Security Act by investing assets of the thrift plan in the common stock of IPALCO prior to the acquisition of IPALCO by the Company. In February 2003, the Court denied the defendants motion to dismiss the lawsuit. On September 30, 2003, the Court granted plaintiffs’ motion for class certification. On October 31, 2003, the parties filed competing motions for summary judgment. IPALCO believes it has meritorious defenses to the claims asserted against it and intends to defend this lawsuit vigorously.

In July 2002, the Company, Dennis W. Bakke, Roger W. Sant, and Barry J. Sharp were named as defendants in a purported class action filed in the United States District Court for the Southern District of Indiana. In September 2002, two virtually identical complaints were filed against the same defendants in the same court. All three lawsuits purport to be filed on behalf of a class of all persons who exchanged their shares of IPALCO common stock for shares of AES common stock pursuant to the Registration Statement dated and filed with the SEC on August 16, 2000. The complaint purports to allege violations of Sections 11, 12(a)(2) and 15 of the Securities Act of 1933 based on statements in or omissions from the Registration Statement covering certain secured equity-linked loans by AES subsidiaries, the supposedly volatile nature of the price of AES stock, as well as AES’s allegedly unhedged operations in the United Kingdom. In October 2002, the defendants moved to consolidate these three actions with the IPALCO securities lawsuit referred to immediately below. On November 5, 2002, the Court appointed lead plaintiffs and lead and local counsel. On March 19, 2003, the Court entered an order on defendants’ motion to consolidate, in which the Court deferred its ruling on defendants’ motion and referred the actions to a magistrate judge for pretrial supervision. On April 14, 2003, lead plaintiffs filed an amended complaint, which adds John R. Hodowal, Ramon L. Humke and John R. Brehm as defendants and, in addition to the purported claims in the original complaint, purports to allege against the newly added defendants violations of Sections 10(b) and 14(a) of the Securities Exchange Act of 1934 and Rules 10b-5 and 14a-9 promulgated thereunder. The amended complaint also purports to add a claim based on alleged misstatements or omissions concerning AES’ alleged obligations to Williams Energy Services Co. in connection with the California energy market. By Order dated August 25, 2003, the court consolidated these three actions with an action captioned Cole et al. v. IPALCO Enterprises, Inc. et al., 1:02-cv-01470-DFH-TAB (the “Cole Action”), which is discussed immediately below. On September 26, 2003, defendants filed a motion to dismiss the amended complaint. The Company and the individual defendants believe that they have meritorious defenses to the claims asserted against them and intend to defend these lawsuits vigorously.

In September 2002, IPALCO and certain of its former officers and directors were named as defendants in a purported class action filed in the United States District Court for the Southern District of Indiana (the “Cole Action”). The lawsuit purports to be filed on behalf of the class of all persons who exchanged shares of IPALCO common stock for shares of AES common stock pursuant to the Registration Statement dated and filed with the SEC on August 16, 2000. The complaint purports to allege violations of Sections 11 of the Securities Act of 1933 and Sections 10(a), 14(a) and 20(a) of the Securities Exchange Act of 1934, and Rules 10b-5 and 14a-9 promulgated there under based on statements in or omissions from the Registration Statement covering certain secured equity-linked loans by AES subsidiaries, the supposedly volatile nature of the price of AES stock, and AES’s allegedly unhedged operations in the United Kingdom. By Order dated August 25, 2003, the court consolidated this action with three previously filed actions, discussed immediately above. The Company and the individual defendants believe that they have meritorious defenses to the claims asserted against them and intend to defend the lawsuit vigorously.

In October 2002, the Company, Dennis W. Bakke, Roger W. Sant and Barry J. Sharp were named as defendants in purported class actions filed in the United States District Court for the Eastern District of Virginia. Between October 29, 2002 and December 11, 2002, seven virtually identical lawsuits were filed against the same defendants in the same court. The lawsuits purport to be filed on behalf of a class of all persons who purchased the Company’s securities between April 26, 2001and February 14, 2002. The complaints purport to allege that certain statements concerning the Company’s operations in the United Kingdom violated Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, and Rule 10b-5 promulgated thereunder. On December 4, 2002 defendants moved to transfer the actions to the United States District Court for the Southern District of Indiana. By stipulation dated December 9, 2002, the parties agreed to consolidate these actions into one action. On December 12, 2002 the Court entered an order consolidating the cases under the caption In re AES Corporation Securities Litigation, Master File No. 02-CV-1485. On January 16, 2003, the Court granted defendants’ motion to transfer the consolidated action to the United States District Court for the Southern District of Indiana. By Order dated August 25, 2003, the Southern District of Indiana recognized the previous consolidation order. On September 26, 2003, plaintiffs filed a consolidated amended class action complaint. The consolidated amended class action complaint, in addition to asserting the same claims asserted in the original complaints, also purports to allege that AES and the individual defendants failed to disclose information concerning purported manipulation of the California electricity market, the effect thereof on AES’s reported revenues, and AES’s purported contingent legal liabilities as a result thereof, in violation of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder. Defendants’ motion to dismiss is currently due to be filed on November 11, 2003. The Company and the individuals believe that they have meritorious defenses to the claims asserted against them and intend to defend the lawsuit vigorously.

On December 11, 2002, the Company, Dennis W. Bakke, Roger W. Sant, and Barry J. Sharp were named as defendants in a purported class action lawsuit filed in the United States District Court for the Eastern District of Virginia captioned AFI LP and Naomi Tessler v. The AES Corporation, Dennis W. Bakke, Roger W. Sant and Barry J. Sharp, 02-CV-1811 (the “AFI Action”). The lawsuit purports to be filed on behalf of a class of all persons who purchased AES securities between July 27, 2000 and September 17, 2002. The complaint alleges that AES and the individual defendants failed to disclose information concerning purported manipulation of the California electricity market, the effect thereof on AES’s reported revenues, and AES’s purported contingent legal liabilities as a result thereof, in violation of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder. On May 14, 2003, the Court ordered that the action be transferred to the United States District Court for the Southern District of Indiana.

By Order dated August 25, 2003, the Southern District of Indiana consolidated this action with another action captioned Stanley L. Moskal and Barbara A. Moskal v. The AES Corporation, Dennis W. Bakke, Roger W. Sant and Barry J. Sharp, 1:03-CV-0284 (the “Moskal Action”), discussed immediately below. On September 26, 2003, plaintiffs filed an amended class action complaint. Defendants’ motion to dismiss is currently due to be filed on November 11, 2003. The Company and the individual defendants believe that they have meritorious defenses to the claims asserted against them and intend to defend the lawsuit vigorously.

Beginning in September 2002, El Salvador tax and commercial authorities initiated investigations involving four of the Company’s subsidiaries in El Salvador, Compañia de Luz Electrica de Santa Ana S.A. de C.V. (“CLESA”), Compañía de Alumbrado Electrico de San Salvador, S.A. de C.V. (“CAESS”), Empresa Electrica del Oriente, S.A. de C.V. (“EEO”), and Distribuidora Electrica de Usultan S.A. de C.V. (“DEUSEM”), in relation to two financial transactions closed in June 2000 and December 2001, respectively. The authorities have issued document requests and the Company and its subsidiaries are cooperating fully in the investigations. As of March 18, 2003, certain of these investigations have been successfully concluded, with no fines or penalties imposed on the Company’s subsidiaries. The tax authorities’ and attorney general’s investigations are pending conclusion.

In March 2002, the general contractor responsible for the refurbishment of two previously idle units at AES’s Huntington Beach plant filed for bankruptcy in the United States bankruptcy court for the Central District of California. A number of the subcontractors hired by the general contractor, due to alleged non-payment by the general contractor, have asserted claims for non-payment against AES Huntington Beach. The general contractor has also filed claims seeking up to $57 million from AES Huntington Beach for additional costs it allegedly incurred as a result of changed conditions, delays, and work performed outside the scope of the original contract. The general contractor’s claim includes its subcontractors’ claims. All of these claims are adversary proceedings in the general contractor’s bankruptcy case. In the event AES Huntington Beach were required to satisfy any of the subcontractor claims for payment, AES Huntington Beach may be unsuccessful in recovering such amounts from, or offsetting such amounts against claims by, the general contractor. The Company does not believe that any additional amounts are owed by its subsidiary and such subsidiary intends to defend vigorously against such claims.

The U.S. Department of Justice is conducting an investigation into allegations that persons and/or entities involved with the Bujagali hydroelectric power project which the Company was constructing and developing in Uganda, have made or have agreed to make certain improper payments in violation of the Foreign Corrupt Practices Act. The Company has been conducting its own internal investigation and has been cooperating with the Department of Justice in this investigation.

In November 2002, a lawsuit was filed against AES Wolf Hollow L.P. and AES Frontier L.P., two subsidiaries of the Company, in Texas State Court by Stone and Webster, Inc. The complaint in the action alleges claims for declaratory judgment and breach of contract allegedly arising out of the denial of certain force majeure claims purportedly asserted by the plaintiff in connection with its construction of the Wolf Hollow project, a gas-fired combined cycle power plant being constructed in Hood County, Texas. Stone and Webster is the general contractor for the Wolf Hollow project. On May 2, 2003 plaintiff amended its complaint to assert additional claims based on purported acts of fraud, negligent misrepresentation and breach of warranty. On July 3, 2003, Stone and Webster filed a third amended complaint, which complaint asserted claims against the Company. The alleged claims against the Company are for purported breach of warranty, wrongful liquidated damages, fraud and negligent misrepresentation. The claims asserted against the Company seek an unspecified damage amount. Discovery is ongoing in the lawsuit. The subsidiary and the Company believe that they have meritorious defenses to the claims asserted against them and intend to defend the lawsuit vigorously.

In March 2003, the office of the Federal Public Prosecutor for the State of Sao Paulo, Brazil notified Eletropaulo that it had commenced an inquiry related to the BNDES financings provided to AES Elpa and AES Transgas and the rationing loan provided to Eletropaulo, changes in the control of Eletropaulo, sales of assets by Eletropaulo and the quality of service provided by Eletropaulo to its customers and requested various documents from Eletropaulo relating to these matters. The Company is still in the process of collecting some of the requested documents concerning the real estate sales to provide to the Public Prosecutor. Also in March 2003, the Commission for Public Works and Services of the Sao Paulo Congress requested Eletropaulo to appear at a hearing concerning the default by AES Elpa and AES Transgas on the BNDES financings and the quality of service rendered by Eletropaulo. This hearing was postponed indefinitely.

In April 2003, the office of the Federal Public Prosecutor for the State of Sao Paulo, Brazil notified Eletropaulo that it is conducting an inquiry into possible errors related to the collection by Eletropaulo of customers’ unpaid past-due debt and requesting the company to justify its procedures.

In May 2003, there were press reports of allegations that in April 1998 Light Serviços de Eletricidade S.A. (“Light”) colluded with Enron in connection with the auction of the Brazilian group Eletropaulo Electricidade de Sao Paulo S.A. Enron and Light, of which AES was a shareholder, were among three potential bidders for Eletropaulo. At the time of the transaction in 1998, AES owned less than 15% of the stock of Light and shared representation in Light’s management and Board with three other shareholders. In June 2003, the Secretariat of Economic Law for the Brazilian Department of Economic Protection and Defense (“SDE”) issued a notice of preliminary investigation seeking information from a number of entities, including AES Brasil Energia, with respect to certain allegations arising out of the privatization of Eletropaulo. On August 1, 2003, AES Elpa S.A. responded on behalf of AES-affiliated companies and denied knowledge of these allegations. The SDE has begun a follow-up administrative proceeding as reported in a notice published on October 31, 2003.

In December 2002, Enron filed a lawsuit in the Bankruptcy Court for the Southern District Court of New York against the Company, NewEnergy, and CILCO. Pursuant to the complaint, Enron seeks to recover approximately $13 million (plus interest) from NewEnergy (and the Company as guarantor of the obligations of NewEnergy). Enron contends that NewEnergy and the Company are liable to Enron based upon certain accounts receivables purportedly owing from NewEnergy and an alleged payment arising from the purported termination by NewEnergy of a “Master Energy Purchase and Sale Agreement.” In the complaint, Enron seeks to recover from CILCO the approximate amount of $31.5 million (plus interest) arising from the termination by CILCO of a “Master Energy Purchase and Sale Agreement” and certain accounts receivables that Enron claims are due and owing from CILCO to Enron. On February 13, 2003 the Company, NewEnergy and CILCO filed a motion to dismiss certain portions of the action and compel arbitration of the disputes with Enron. Also in February 2003, the Bankruptcy Court ordered the parties to mediate the disputes. The mediation process is currently continuing. The Company believes it has meritorious defenses to the claims asserted against it and intends to defend the lawsuits vigorously.

In December 2002, plaintiff David Schoellermann filed a purported derivative lawsuit in Virginia State Court on behalf of the Company against the members of the Board of Directors and numerous officers of the Company (the “Schoellermann Lawsuit”). The lawsuit alleges that defendants breached their fiduciary duties to the Company by participating in or approving the Company’s alleged manipulation of electricity prices in California. Certain of the defendants are also alleged to have engaged in improper sales of stock based on purported inside information that the Company was manipulating the California electricity prices. The complaint seeks unspecified damages and a constructive trust on the profits made from the alleged insider sales. On February 21, 2003, a second derivative lawsuit was filed by plaintiff Joe Pearce in Virginia State Court on behalf of the Company against the members of the Board of Directors and numerous officers of the Company (the “Pearce Lawsuit”). In June 2003, a motion to stay the Schoellermann Lawsuit pending a review of the allegations asserted in the Schoellermann Lawsuit by a special committee of the Company comprised of two independent directors was granted by the Court. In July 2003, the Court issued a consent order further extending the stay of the proceedings until October 8, 2003. The parties recently informed the Court that they have reached a settlement of the case and are preparing appropriate documentation.

On February 26, 2003, the Company, Dennis W. Bakke, Roger W. Sant, and Barry J. Sharp were named as defendants in a purported class action lawsuit filed in the United States District Court for the Southern District of Indiana captioned Stanley L. Moskal and Barbara A. Moskal v. The AES Corporation, Dennis W. Bakke, Roger W. Sant and Barry J. Sharp, 1:03-CV-0284 (Southern District of Indiana). The lawsuit purports to be filed on behalf of a class of all persons who engaged in “option transactions” concerning AES securities between July 27, 2000 and November 8, 2002. The complaint alleges that AES and the individual defendants failed to disclose information concerning purported manipulation of the California electricity market, the effect thereof on AES’s reported revenues, and AES’s purported contingent legal liabilities as a result thereof, in violation of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder. By Order dated August 25, 2003, the Southern District of Indiana consolidated this action with the AFI Action, discussed immediately above. The Company and the individual defendants believe that they have meritorious defenses to the claims asserted against them and intend to defend the lawsuit vigorously.

On April 16, 2003, Lake Worth Generation, LLC (“Lake Worth”) commenced a voluntary proceeding under Chapter 11 of the United States Bankruptcy Court for the Southern District of Florida (the “Bankruptcy Court”). As a debtor in possession, Lake Worth continues to manage its affairs and operate its business. No trustee or examiner has been appointed for Lake Worth. Lake Worth has been constructing a combined cycle power generation facility in the City of Lake Worth (the “Project”). Lake Worth intended to install a single combustion turbine and heat recovery steam generator, along with a new 47 MW steam turbine, to produce approximately 205 MW of electricity for the residents of Lake Worth. Construction began in June 2001 under an EPC agreement with NEPCO, a subsidiary of Enron, who provided the financial guaranty in support of the EPC performance obligations. AES holds secured claims against Lake Worth of approximately $2.8 million. Lake Worth contemplates that it will sell the Project pursuant to procedures approved by the Bankruptcy Court. There are parties undertaking due diligence on the Project.

On May 2, 2003, the Indiana Securities Commissioner of Indiana’s Office of the Secretary of State, Securities Division, pursuant to Indiana Code 23-2-1, served subpoenas on 30 former officers and directors of IPALCO Enterprises, Inc. (“IPALCO”) requesting the production of documents in connection with the March 27, 2001 share exchange between the Company and IPALCO pursuant to which stockholders exchanged shares of IPALCO common stock for shares of the Company’s common stock and IPALCO became a wholly-owned subsidiary of the Company. A subsequent subpoena was issued to IPALCO. IPALCO has produced documents pursuant to the subpoena. On September 4, 2003, the Indiana Securities Commissioner served a subpoena on the Company requesting the production of documents. The Company is in the process of producing documents responsive to the subpoena. On September 30, 2003, the Indiana Securities Commissioner served a supplemental subpoena on IPALCO, and IPALCO is in the process of producing documents responsive to the supplemental subpoena.

The Company is also involved in certain claims, suits and legal proceedings in the normal course of business.

RISKS RELATED TO REGULATED AND FOREIGN OPERATIONS—AES operates businesses in many regulated and foreign environments. There are certain economic, political, technological and regulatory risks associated with operating in these environments. Investments in foreign countries may be impacted by significant fluctuations in foreign currency exchange rates. During 2002 and 2001, the Company’s financial position and results of operations were adversely affected by a significant devaluation of the Argentine peso, Brazilian Real and Venezuelan Bolivar relative to the U.S. dollar.

The distribution businesses, which the Company owns or has investments in, are subject to regulatory review or approval which could limit electricity tariff rates charged to customers or require the return of amounts previously collected. These regulatory environments are also subject to change, which could impact the results of operations.

In certain locations, particularly developing countries or countries that are in a transition from centrally planned to market-oriented economies, the electricity purchasers, both wholesale and retail, may be unable or unwilling to honor their payment obligations. Collection of receivables may be hindered in these countries due to ineffective systems for adjudicating contract disputes.

Argentina

In 2002, Argentina continued to experience a political, social and economic crisis that has resulted in significant changes in general economic policies and regulations as well as specific changes in the energy sector. In January and February 2002, many new economic measures were adopted by the Argentine government, including abandonment of the country’s fixed dollar-to-peso exchange rate, converting U.S. dollar denominated loans into pesos and placing restrictions on the convertibility of the Argentine peso. The government also adopted new regulations in the energy sector that have the effect of repealing U.S. dollar denominated pricing under electricity tariffs as prescribed in existing electricity distribution concessions in Argentina by fixing all prices to consumers in pesos. Presidential elections are scheduled to occur in Argentina in 2003, and the new government may enact changes to the regulations governing the electricity industry. In combination, these circumstances create significant uncertainty surrounding the performance, cash flow and potential for profitability of the electricity industry in Argentina, including the Argentine subsidiaries of AES. Due to the changes, the Company changed the functional currency for its businesses in Argentina to the peso. If the commercial arrangements or regulatory framework within which any of the businesses operate become indexed to a currency other than the peso, the functional currency of the respective business may change. The Argentine peso has experienced a significant devaluation relative to the U.S. dollar during 2002. The Company recorded foreign currency transaction losses on its U.S. dollar denominated net liabilities during 2002 of approximately $143 million before income taxes representing a decline in the Argentine peso to the U.S. dollar from 1.65 used at December 31, 2001 to 3.32 at December 31, 2002.

AES has several subsidiaries in Argentina operating in both the competitive supply and growth distribution segments of the electricity business. Eden, Edes and Edelap are distribution companies that operate in the province of Buenos Aires. Generating businesses include Alicura, Parana, CTSN, Rio Juramento and several other smaller hydro facilities. These businesses are experiencing cash flow shortfalls arising from the economic and regulatory changes described earlier, and some of the businesses are in default on their project financing arrangements. AES is not generally required to support the potential cash flow or debt service obligations of these businesses.

The effects of the crisis are not expected to have a significant negative impact on AES’s parent cash flow, due primarily to the non-recourse financing structure in place at most of AES’s Argentine businesses. The effects of the current circumstances on future earnings are much more uncertain and difficult to predict. At December 31, 2002, AES’s total investment in the competitive supply business in Argentina was approximately $141 million and the total investment in the growth distribution business is approximately negative $61 million. These investment amounts are net of foreign currency translation losses. Depending on the ultimate resolution of these uncertainties, AES may be required in 2003 to record a material impairment loss or write off associated with the recorded carrying values of its investments.

During the first quarter of 2002, the Company recorded an after-tax impairment charge of $190 million which represented the write off of goodwill related to certain of our businesses in Argentina. This charge resulted from the adoption of SFAS No. 142 and is recorded as a cumulative effect of a change in accounting principle on the consolidated statement of operations.

Brazil

Eletropaulo. AES has owned an interest in Eletropaulo since April 1998. The Company began consolidating Eletropaulo in February 2002 when AES Elpa acquired a controlling interest in the business. AES financed a significant portion of the acquisition of Eletropaulo, including both common

and preferred shares, through loans and deferred purchase price financing arrangements provided by BNDES, the National Development Bank of Brazil and its wholly owned subsidiary BNDES Participacoes Ltda. (“BNDESPAR”), to AES Elpa and AES Transgas, respectively. As of December 31, 2002, AES Elpa and AES Transgas had approximately $542 million and $621 million of outstanding BNDES and BNDESPAR indebtedness, respectively. All of the common shares of Eletropaulo owned by AES Elpa are pledged to BNDES to secure the AES Elpa debt and all of the preferred shares of Eletropaulo owned by AES Transgas and AES Cemig Empreendimentos II, Ltd. (which owns approximately 7.4% of Eletropaulo’s preferred shares, representing 4.4% economic ownership of Eletropaulo) are pledged to BNDESPAR to secure AES Transgas debt. AES has pledged its share of the proceeds in the event of the sale of certain of its businesses in Brazil, including Sul, Uruguaiana, Eletronet and AES Communications Rio, to secure the indebtedness of AES Elpa to BNDES for the repayment of the debt of AES Elpa. The interests underlying the Company’s investments in Uruguaiana, AES Communications Rio and Eletronet have also been pledged as collateral to BNDES under the AES Elpa loan. As of December 31, 2002, Eletropaulo had $1.4 billion of outstanding indebtedness. The Company’s total investment associated with Eletropaulo as of December 31, 2002, was approximately negative $1.0 billion, which is net of foreign currency translation losses and other comprehensive losses arising from minimum pension obligations.

During the fourth quarter of 2002, the Company recorded an after-tax impairment charge of approximately $706 million at Eletropaulo. This charge was taken to reflect the reduced carrying value of certain assets, including goodwill, primarily resulting from slower than anticipated recovery to pre-rationing electricity consumption levels and lower electricity prices due to devaluation of foreign exchange rates.

Eletropaulo, AES Elpa and AES Transgas are in negotiations with debt holders, BNDES and BNDESPAR to seek resolution of these issues; however, there can be no assurance that these negotiations will be successful. If the negotiations are not successful, Eletropaulo would face an increased risk of loss of its concession and of bankruptcy, resulting in an increased risk of loss of AES’s investment in Eletropaulo. Dividend restrictions applicable to Eletropaulo are expected to reduce substantially the ability of Eletropaulo to pay dividends. In addition, the refinancing agreement entered into with BNDES in June 2002 provides for Eletropaulo to pay directly to BNDES any dividends in respect of the shares held by AES Elpa, AES Transgas and Cemig Empreendimentos II Ltd. In light of the failure of AES Elpa and AES Transgas to make the BNDES and BNDESPAR payments when due,

BNDES and BNDESPAR may choose to foreclose on the collateral, and this may result in a loss and a corresponding write-off of a portion or all of the Company’s investment in Eletropaulo. In addition, the default on the BNDES loan could also result in a cross-default to a BNDES loan in connection with our investment in CEMIG.

Although neither AES Elpa nor AES Transgas currently constitute “material subsidiaries” for purposes of the cross-default, cross acceleration and bankruptcy related events of default contained in AES’s parent company indebtedness, Eletropaulo does constitute a “material subsidiary” for purposes of certain of such bankruptcy-related events of default. However, given that a bankruptcy proceeding would generally be an unattractive remedy for Eletropaulo’s lenders, as it could result in an intervention by ANEEL or a termination of Eletropaulo’s concession, and given that Eletropaulo is currently in negotiations to restructure such indebtedness, the Company believes such an outcome is unlikely. The Company cannot assure you, however, that such negotiations will be successful. As a result, AES may have to write-off some or all of the assets of Eletropaulo, AES Elpa or AES Transgas.

Sul. Sul and AES Cayman Guaiba, a subsidiary of the Company that owns the Company’s interest in Sul, are facing near-term debt payment obligations that must be extended, restructured, refinanced or paid. Sul had outstanding debentures of $53 million, at the December 31, 2002 exchange rate, that were restructured on December 1, 2002. The restructured debentures have partial interest payments due in June 2003 and December 2003 and principal payments due in 12 equal monthly installments commencing on December 1, 2002. The banks under the $300 million AES Cayman Guaiba syndicated loan have granted a waiver in respect of $30 million of principal payments due under such loan until the earlier of April 24, 2003 and the execution of satisfactory final documentation in respect of the restructuring of such loan. The Company cannot assure you, however, that the restructuring will be completed.

In addition, during the second quarter of 2002, ANEEL promulgated an order (“Order 288”) whose practical effect was to purport to invalidate gains recorded by Sul from inter-submarket trading of energy purchased from the Itaipu power station. The Company, in total, recorded a pre-tax provision as a reduction of revenues of approximately $160 million during the second quarter of 2002. Sul filed a motion for an administrative appeal with ANEEL challenging the legality of Order 288 and requested a preliminary injunction in the Brazilian federal courts to suspend the effect of Order 288 pending the determination of the administrative appeal. Both were denied. In August 2002, Sul appealed and in October 2002 the court confirmed the preliminary injunction’s validity. Its effect, however, was subsequently suspended pending an appeal by ANEEL and an appeal by Sul.

In December 2002, prior to any settlement of the Brazilian Wholesale Electricity Market (“MAE”), Sul filed an incidental claim requesting, by way of a preliminary injunction, the suspension of the Company’s debts registered in the MAE. A Brazilian federal judge granted the injunction and ordered that an amount equal to one-half of the amount claimed by Sul from inter-market trading of energy purchased from Itaipu in 2001 be set aside by the MAE in an escrow account. The injunction was subsequently overturned. Sul has appealed that decision and requested the judge to reinstate the injunction and the escrow account. A decision is expected shortly.

The MAE partially settled its registered transactions between late December 2002 and early 2003. If the final settlement occurs with the effect of Order 288 in place, Sul will owe approximately $21 million, based upon the December 31, 2002 exchange rate. Sul does not believe it will have sufficient funds to make this payment. However, if the MAE settlement occurs absent the effect of Order 288, Sul will receive approximately $106 million, based upon the December 31, 2002 exchange rate. If Sul is unable to pay any amount that may be due to MAE, penalties and fines could be imposed up to and including the termination of the concession contract by ANEEL.

Sul continues legal action against ANEEL to seek resolution of these issues. Sul and AES Cayman Guaiba will continue to face shorter-term debt maturities in 2004 but, given that a bankruptcy proceeding would generally be an unattractive remedy for each of its lenders, as it would result in an

intervention by ANEEL or a termination of Sul’s concession, and because Sul has completed negotiations for debt restructuring through 2003, we think such an outcome is unlikely. We cannot assure you, however, that future negotiations will be successful and AES may have to write off some or all of the assets of Sul or AES Cayman Guaiba. The Company’s total investment associated with Sul as of December 31, 2002 was approximately $146 million, which is net of foreign currency translation losses.

During the first quarter of 2002, the Company recorded an after-tax impairment charge of $231 million related to the write off of goodwill at Sul. This charge resulted from the adoption of SFAS No. 142 and is recorded as a cumulative effect of a change in accounting principle on the consolidated statements of operations.

CEMIG. An equity method affiliate of AES received a loan from BNDES to finance its investment in CEMIG, and the balance, including accrued interest, outstanding on this loan is approximately $700 million as of December 31, 2002. Approximately $57 million of principal and interest, which represents AES’s share, is scheduled to be repaid in May 2003. If the equity method affiliate of the Company is not able to repay the amounts when due or is not able to refinance or extend the maturities of any or all of the payment amounts, BNDES may choose to seize the shares held as collateral. Additionally, the existing default on the debt used to finance the acquisition of Eletropaulo could result in a cross default on the debt used to finance the acquisition of CEMIG. In December 2002, AES recorded a charge related to the other than temporary impairment of the investment in CEMIG, as the shares in CEMIG were written-down to fair market value. Additionally, AES recorded a valuation allowance against a deferred tax asset related to the CEMIG investment. The total amount of these charges, net of tax, was $587 million, of which $264 million relates to the other than temporary impairment of the investment and $323 million relates to the valuation allowance against the deferred tax asset. At December 31, 2002, the Company’s total investment associated with CEMIG was negative.

Tiete. The MAE settlement for the period from September 2000 to September 2002 for Tiete totals an obligation of approximately $64 million, at the December 31, 2002 exchange rate. Fifty percent of the amount was due on December 26, 2002, and the rest is due after MAE’s numbers are audited. According to the industry-wide agreement reached in December 2001, BNDES was supposed to provide Tiete with a credit facility in the amount of approximately $43 million at the December 31, 2002 exchange rate to pay off a part of the liability. This credit facility has not yet been provided. In the meantime, the Federal Court has granted Tiete an injunction suspending the payment of the obligation until BNDES makes this credit facility available. However, if the MAE settles absent the effect of ANEEL Order 288, which is currently being appealed by market participants, including Sul, Tiete’s obligation to the MAE would be increased by $17 million at the December 31, 2002 exchange rate. The appealing market participants have received a favorable injunction against ANEEL’s Order 288. However, this injunction was overturned in February 2003. The Company’s total investment associated with Tiete as of December 31, 2002 was approximately $26 million, which is net of foreign currency translation losses.

Under Brazilian corporate law, Tiete may only pay to shareholders dividends or interest on net worth from net income less allocations to statutory reserves. In 2002, Tiete’s dividends and interest on net worth paid to shareholders were insufficient to enable payment to be made of amounts due on debt obligations of AES IHB Cayman, Ltd., an affiliate of Tiete, guaranteed by Tiete’s parent company, AES Tiete Holdings, Ltd., and direct shareholders, AES Tiete Empreendimentos Ltda (“TE”) and Tiete Participações Ltda. As a result, those payments were principally funded through Tiete capital reductions and intercompany loans from Tiete to TE. These debt obligations are also supported by a foreign exchange guaranty facility and related political risk insurance provided by the Overseas Private Investment Corporation (“OPIC”), an agency of the United States government. A payment of principal and interest on the debt obligations in the amount of approximately $21.5 million is due on June 15, 2003. Because Tiete recorded a net loss for 2002, no dividends or interest on net worth will be

available to enable that payment to be made. As a result, Tiete Holdings intends to seek certain amendments to the debt obligations and the OPIC documentation designed to reduce the risk of defaults due to the limitation on dividend and interest on net worth payments, including amendments to allow debt payments to be made with the proceeds of loans from Tiete. Any loan by Tiete to its affiliates is subject to ANEEL approval. No assurance can be given, however, that these amendments will be adopted or that ANEEL will grant such approval.

Uruguaiana. The MAE settlement for the period from September 2000 to September 2002 for Uruguaiana totals an obligation of approximately $13 million at the December 31, 2002, exchange rate. Fifty percent of the outstanding liability was due on December 26, 2002. Uruguaiana disagreed with the liability for the period from December 2000 to March 2002, which represents approximately $11 million at the December 31, 2002, exchange rate, and on December 18, 2002, Uruguaiana obtained an injunction from the Federal Court suspending the payment of the liability under dispute. On February 25, 2003, ANEEL and MAE filed an appeal against the injunction. On March 12, 2003, the judge responsible for the case did not accept the appeal and maintained the injunction for Uruguaiana. Uruguaiana believes that under the terms of its ANEEL Independent Power Producer Operational Permit, power purchase and regulatory contracts, it is not liable for replacement power costs arising directly out of the electric system’s instability. Furthermore, the civil action also discusses the power prices changed by ANEEL in August 2002 related to energy sold at the spot market in June 2001. Uruguaiana does not expect to have sufficient resources to pay the MAE settlement, and if the legal challenge of this obligation is not successful, penalties and fines could be imposed, up to and including the termination of the ANEEL Independent Power Producer Operational Permit. The Company’s total investment associated with Uruguaiana as of December 31, 2002 was approximately $272 million, which is net of foreign currency translation losses.

Other Regulatory Matters. The electricity industry in Brazil reached a critical point in 2001 as a result of a series of regulatory, meteorological and market driven problems. The Brazilian government implemented a program for the rationing of electricity consumption effective as of June 2001. In December 2001, an industry-wide agreement was reached with the Brazilian government that applies to Eletropaulo, Tiete, CEMIG, and Sul. There were three parts of the agreement that specifically affected AES. The terms of the agreement were implemented during 2002.

the Company wrote-off approximately $160 million ($101 million representing the Company’s portion from equity affiliates), of Parcel A costs incurred prior to 2001 that will not be recovered.

Under the third part of the agreement, Sul was permitted to record additional revenue and a corresponding receivable from the spot market in 2001 and through May 2002. However, the electricity regulator, ANEEL promulgated Order 288 which retroactively changed certain previously communicated methodologies during May 2002, and resulted in a change in the calculation methods for electricity pricing in the Wholesale Energy Market. The Company recorded a pretax provision of approximately $160 million, including the amounts for Sul, against revenues during May 2002 to reflect the negative impacts of this retroactive regulatory decision. Sul filed a motion for an administrative appeal with ANEEL challenging the legality of Order 288 and requested a preliminary injunction in the Brazilian federal courts to suspend the effect of Order 288 pending the determination of the administrative appeal. Both were denied. In August 2002, Sul appealed and in October 2002 the court confirmed the preliminary injunction’s validity. Its effect, however, was subsequently suspended pending an appeal by ANEEL and an appeal by Sul.

On September 3, 2002, ANEEL issued an order providing that the formula for adjusting the tariffs applicable to distribution companies, which are scheduled to be reset in 2003, should be based on a replacement cost method. The Company, together with other electric distribution companies, disagrees with the proposed method and filed a lawsuit advocating that a minimum bid price methodology be used to set the rate base. The companies have not obtained an injunction to date, but the lawsuit is ongoing. Taken alone, the method proposed in the ANEEL order would lead to a significantly lower adjustment in the tariff than would methodologies proposed by the distribution companies. Because a number of other factors that affect the formula have yet to be determined, we are unable to predict the ultimate impact, if any, of this order. These other factors include an “X” factor. The X factor is intended to permit the regulator to adjust tariffs so that consumers may share in the distribution company’s realization of increased operating efficiencies. The revision, however, is entirely within the regulator’s discretion.

Venezuela

The politics and economy in Venezuela have been experiencing significant systemic crisis. The economy has suffered from falling oil revenues, capital flight and a decline in foreign reserves. The country is

experiencing a negative growth of GDP, high unemployment, significant foreign currency fluctuations and political instability. Beginning December 2, 2002 Venezuela experienced a forty-five day nationwide general strike that affected a significant portion of the Venezuelan economy, including the city of Caracas and the oil industry. This general strike has affected the normal conduct of the business of EDC. In combination, these circumstances create significant uncertainty surrounding the performance, cash flow and potential for profitability of EDC. However, AES is not required to support the potential cash flow or debt service obligations of EDC. AES’s total investment in EDC at December 31, 2002 was approximately $1.8 billion, which is net of foreign currency translation losses.

In February 2002, the Venezuelan Government decided not to continue support of the Venezuelan currency, which has caused significant devaluation. As a result of the change, the U.S. dollar to Venezuelan exchange rate had floated as high as 1,497 before declining to 1,403 at December 31, 2002 as compared to 758 at December 31, 2001. EDC uses the U.S. dollar as its functional currency. A portion of its debt is denominated in the Venezuelan Bolivar, and as of December 31, 2002, EDC has net Venezuelan Bolivar monetary liabilities thereby creating foreign currency gains when the Venezuelan Bolivar devalues. During 2002, the Company recorded pre-tax foreign currency transaction gains of approximately $39 million, as well as $40 million of pre-tax mark to market gains on a foreign currency forward contract due to a decline in the Venezuelan Bolivar to the U.S. dollar exchange rate. The tariffs at EDC are adjusted semi-annually to reflect fluctuations in inflation and the currency exchange rate. However, a failure to receive such adjustment to reflect changes in the exchange rate and inflation could adversely affect the Company’s results of operations.

Effective January 21, 2003, the Venezuelan Government and the Central Bank of Venezuela (Central Bank) agreed to suspend the trading of foreign currencies in the country for five business days and to establish new standards for the foreign currency exchange regime. Then, effective February 5, 2003, the Venezuelan Government and the Central Bank entered into an exchange agreement that will govern the Foreign Currency Management Regime, and establish the applicable exchange rate. The exchange agreement established certain conditions including the centralization of the purchase and sale of currencies within the country by the Central Bank, and the incorporation of the Foreign Currency Management Commission (CADIVI) to administer the execution of the exchange agreement and establish certain procedures and restrictions. The acquisition of foreign currencies will be subject to the prior registration of the interested party and the issuance of an authorization to participate in the exchange regime. Furthermore, CADIVI will govern the provisions of the exchange agreement, define the procedures and requirements for the administration of foreign currencies for imports and exports, and authorize purchases of currencies in the country. The exchange rates set by such agreements are 1,596 Bolivars per U.S. dollar for purchases and 1,600 Bolivars per U.S. dollar for sales. These actions may impact the ability of EDC to distribute cash to the parent.

In January 1999, a joint resolution of the Ministry of Energy and Mines and the Ministry of Industry and Commerce established the basic tariff rates applicable during the Four Year Tariff Regime from 1999 through 2002. The tariffs were established by the Ministry of Energy and Mines using a combination of cost-plus and return on investment methodologies. The regulation that establishes basic tariff rates is expected to change for 2003, and this change may have an impact on the amount and timing of the cash flows and earnings reported by EDC.

LEVERAGED LEASE INVESTMENTS—CILCORP, which is classified as a discontinued operation in the consolidated financial statements, has investments in leveraged leases totaling $135 million. Related deferred tax liabilities total $108 million. The investment includes estimated residual values totaling $86 million. Leveraged lease residual value assumptions are adjusted on a periodic basis, based on independent appraisals. CILCORP was sold to Ameren Corporation in a transaction that closed on January 31, 2003.

SALE OF ACCOUNTS RECEIVABLE—IPL, a subsidiary of the Company, formed IPL Funding Corporation (“IPL Funding”) in 1996 to purchase, on a revolving basis, up to $50 million of the retail accounts receivable and related collections of IPL in exchange for a note payable. IPL Funding is not

consolidated by IPL or IPALCO since it meets requirements set forth in SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities” to be considered a qualified special-purpose entity. IPL Funding has entered into a purchase facility with unrelated parties (“the Purchasers”) pursuant to which the Purchasers agree to purchase from IPL Funding, on a revolving basis, up to $50 million of the receivables purchased from IPL. As of December 31, 2002, the aggregate amount of receivables purchased pursuant to this facility was $50.0 million. The net cash flows between IPL and IPL Funding are limited to cash payments made by IPL to IPL Funding for interest charges and processing fees. These payments totaled approximately $1.1 million, $2.3 million and $3.5 million for the years ended December 31, 2002, 2001 and 2000, respectively. IPL retains servicing responsibilities through its role as a collection agent for the amounts due on the purchased receivables. IPL and IPL Funding provide certain indemnities to the Purchasers, including indemnification in the event that there is a breach of representations and warranties made with respect to the purchased receivables. IPL Funding and IPL each have agreed to indemnify the Purchasers on an after-tax basis for any and all damages, losses, claims, liabilities, penalties, taxes, costs and expenses at any time imposed on or incurred by the indemnified parties arising out of or otherwise relating to the sale agreement, subject to certain limitations as defined in the agreements. The transfers of such accounts receivable from IPL to IPL Funding are recorded as sales; however, no gain or loss is recorded on the sale.

Under the receivables sale agreement, if IPL fails to maintain certain financial covenants regarding interest coverage and debt to capital, it would constitute a “termination event.” As of December 31, 2002, IPL was in compliance with such covenants.

As a result of IPL’s current credit rating, the facility agent has the ability to (i) replace IPL as the collection agent; and (ii) declare a “lock-box” event. Under a lock-box event or a termination event, the facility agent has the ability to require all proceeds of purchased receivables of IPL to be directed to lock-box accounts within 45 days of notifying IPL. In the facility agent’s discretion, the lock-box account may be under the control of IPL (as collection agent) or under the control of the facility agent. A termination event would also give the Purchasers the option to discontinue the purchase of new receivables and cause all proceeds of the purchased receivables to be used to reduce the Purchaser’s investment and to pay other amounts owed to the Purchasers and the facility agent. This would have the effect of reducing the operating capital available to IPL by the aggregate amount of such purchased receivables, currently $50 million.

OTHER—IPL has an agreement with a regulatory body that establishes certain performance measures for their system reliability and call center performance. If these measures are not maintained, penalties of up to $7 million per year can be assessed. During 2002, IPL was assessed penalties of $1.25 million.

LIQUIDITY—AES believes that its sources of liquidity will be adequate to meet its needs through the end of 2003. This belief is based on a number of assumptions, including, without limitation, the non-recourse nature of subsidiary debt, assumptions about exchange rates, pool prices, the ability of its subsidiaries to pay dividends and the timing and amount of asset sale proceeds. As discussed in Note 9, AES (as parent) completed an exchange offer which extended the maturities of the parent debt. In addition, as discussed in this Note 11, AES has numerous material contingent commitments. While AES does not expect to be required to fund any material amounts under these contingent contractual obligations during 2003, many of the events which would give rise to such an obligation are beyond AES’s control.

12. COMPANY-OBLIGATED CONVERTIBLE MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUSTS

During 1997, two wholly owned special purpose business trusts (AES Trust I and AES Trust II) issued Term Convertible Preferred Securities (“Tecons”). On March 31, 1997, AES Trust I issued 5 million of $2.6875 Tecons (liquidation value $50) for total proceeds of $250 million and concurrently purchased $250 million of 5.375% junior subordinated convertible debentures due 2027 of AES (individually the

5.375% Debentures). On October 29, 1997, AES Trust II issued 6 million of $2.75 Tecons (liquidation value $50) for total proceeds of $300 million and concurrently purchased $300 million of 5.5% junior subordinated convertible debentures due 2012 of AES (individually the 5.5% Debentures). During 2000, the Company called for redemption of AES Trust I and AES Trust II. Substantially all of AES Trust I Tecons were converted into approximately 14 million shares of AES common stock and substantially all of AES Trust II Tecons were converted into approximately 11 million shares of AES common stock.

During 1999, AES Trust III, a wholly owned special purpose business trust, issued 9 million of $3.375 Tecons (liquidation value $50) for total proceeds of approximately $518 million and concurrently purchased approximately $518 million of 6.75% junior subordinated convertible debentures due 2029 (individually, the 6.75% Debentures).

During 2000, AES Trust VII, a wholly owned special purpose business trust, issued 9.2 million of $3.00 Tecons (liquidation value $50) for total proceeds of approximately $460 million and concurrently purchased approximately $460 million of 6% junior subordinated convertible debentures due 2008 (individually, the 6% Debentures and collectively with the 6.75% Debentures, the Junior Subordinated Debentures). The sole assets of AES Trust III and VII (collectively, the Tecon Trusts) are the Junior Subordinated Debentures.

AES, at its option, can redeem the 6.75% Debentures after October 17, 2002, which would result in the required redemption of the Tecons issued by AES Trust III, for $52.10 per Tecon, reduced annually by $0.422 to a minimum of $50 per Tecon, and can redeem the 6% Debentures after May 18, 2003, which would result in the required redemption of the Tecons issued by AES Trust VII, for $51.88 per Tecons, reduced annually by $0.375 to a minimum of $50 per Tecon. The Tecons must be redeemed upon maturity of the Junior Subordinated Debentures.

The Tecons are convertible into the common stock of AES at each holder’s option prior to October 15, 2029 for AES Trust III and May 14, 2008 for AES Trust VII at the rate of 1.4216 and 1.0811, respectively, representing a conversion price of $35.171 and $46.25 per share, respectively.

Dividends on the Tecons are payable quarterly at an annual rate of 6.75% by AES Trust III and 6% by AES Trust VII. The Trusts are each permitted to defer payment of dividends for up to 20 consecutive quarters, provided that the Company has exercised its right to defer interest payments under the corresponding debentures or notes. During such deferral periods, dividends on the Tecons would accumulate quarterly and accrue interest and the Company may not declare or pay dividends on its common stock.

On November 30, 1999, three wholly owned special purpose business trusts (individually, AES RHINOS Trust I, II, and III, collectively, the Rhinos Trusts and with the Tecon Trusts, collectively the Trusts) issued trust preferred securities (“Rhinos”). The aggregate amount of Rhinos issued was approximately $250 million. Concurrent with the issuance of the Rhinos, the Rhinos Trusts purchased approximately $258 million of junior subordinated convertible notes due 2007. In October 2001, the Rhino Trusts were converted to an amortizing loan. The amortizing loan balance was paid in full by August 2002.

Interest expense for each of the years ended December 31, 2002, 2001 and 2000, includes approximately $63 million, $63 million and $71 million, respectively, related to the Tecon Trusts and approximately, $0 million, $17 million and $21 million for 2002, 2001 and 2000, respectively, related to the Rhinos Trusts.

13. MINORITY INTEREST

Minority interest includes $100 million of cumulative preferred stock of subsidiaries at December 31, 2002 and 2001. In 2000, a subsidiary of the Company retired $25 million of its cumulative preferred stock at par value. The total annual dividend requirement was approximately $5 million at December 31, 2002. $22 million of the preferred stock is subject to mandatory redemption

requirements over the period 2003-2008. Except for the series of preferred stock subject to mandatory redemption discussed above, each series of preferred stock is redeemable solely at the option of the issuer at prices between $101 and $118 per share.

14. STOCKHOLDERS’ EQUITY

SALE OF STOCK—In May 2000, the Company sold 24.725 million shares of common stock at $37.00 per share. Net proceeds from the offering were $886 million. In November 2000, the Company sold 10 million shares of common stock at $52.50 per share. Net proceeds from the offering were $520 million.

STOCK SPLIT AND STOCK DIVIDEND—On April 17, 2000, the Board of Directors authorized a two-for-one stock split, effected in the form of a stock dividend, payable to stockholders of record on May 1, 2000. Accordingly, all outstanding shares, per share and stock option data in all periods presented have been restated to reflect the stock split.

SHARES ISSUED FOR ACQUISITIONS—In January 2001, the Company issued approximately 9.1 million shares valued at approximately $511 million to fund a portion of the acquisition of Gener. During March 2001, the Company issued approximately 41.5 million shares in the IPALCO pooling-of-interests transaction. During December 2000, the Company issued approximately 699,000 shares, valued at $51 million to fund the acquisition of KMR. Also, during 2000, the Company issued approximately 343,000 shares, valued at $16 million in various other acquisitions.

SHARES ISSUED FOR DEBT—During 2002, the Company swapped 21.6 million shares of Common stock at an average value of $3.39 per share, for approximately $117.2 million in senior subordinated notes. This resulted in a gain on retirement of approximately $44 million for the year ended December 31, 2002.

RESTRICTED STOCK—The Company issued restricted stock under various incentive stock option plans. Generally, under each plan, shares of restricted common stock with value equal to a stated percentage of participants’ base salary are initially awarded at the beginning of a three-year performance period, subject to adjustment to reflect the participants’ actual base salary. The shares remain restricted and nontransferable throughout each three-year performance period, vesting in one-third increments in each of the three years following the end of the performance period. At the end of a performance period, awards are subject to adjustment to reflect the Company’s performance compared to peer companies. Final awards under the plans can range from zero up to 400% of the initial awards. Vested shares are no longer restricted and may be held or sold by the participant. Compensation expense of $0 million, $0 million and $8 million for 2002, 2001 and 2000, respectively, as measured by the market value of the common stock at the balance sheet date, has been recognized. In January 2001, the final performance evaluation was completed for one of the restricted stocks plans resulting in final awards of an additional 199,000 shares with approximately 101,000 shares becoming fully vested. All shares of restricted stock became fully vested on the date of merger with IPALCO. Under the terms of the restricted stock plan, no additional shares will be awarded.

STOCK OPTIONS—The Company has granted options to purchase shares of common stock under its two stock option plans- The AES Corporation 2001 Stock Option Plan and The AES Corporation 2001 Non-Officer Stock Option Plan. Under the terms of the plans, the Company may issue options to purchase shares of the Company’s common stock at a price equal to 100% of the market price at the date the option is granted. The options become eligible for exercise under various schedules.

The AES Corporation 2001 Stock Option Plan—The 2001 plan was issued effective January 1, 2001 due to the expiration of the 1991 stock option plan previously used. The standard is that outstanding stock options become exercisable on a cumulative basis at fifty percent for each of two years from the date of grant and expire ten years from date of grant. Additionally, some options become exercisable in as little as one year (100% in one year), or as many as four years (25% each year). At December 31, 2002,

7.7 million shares were remaining for award under the plan. The maximum term of options granted is 10 years.

The AES Corporation 2001 Non-Officer Stock Option Plan—The 2001 plan was issued without shareholder approval and therefore, all AES officers are excluded from receiving grants under the plan. The standard is that outstanding stock options become exercisable on a cumulative basis at fifty percent for each of two years from the date of grant and expire ten years from date of grant. Additionally, some options become exercisable in as little as one year (100% in one year) or as many as four years (25% each year). At December 31, 2002, 118,707 shares were remaining for award under the plan. The maximum term of options granted is 10 years.

A summary of the option activity follows (in thousands of shares):

	Years Ended December 31,
	2002				2001				2000
	Shares		Weighted- Average Exercise Price		Shares		Weighted- Average Exercise Price		Shares		Weighted- Average Exercise Price
Outstanding — beginning of year	33,142		$	16.58	13,789		$	14.11	15,500		$	9.19
Exercised during the year	(228	)	5.10		(1,508	)	8.95		(3,612	)	6.01
Forfeited during the year	(813	)	8.90		(216	)	32.92		(175	)	27.71
Granted during the year	1,143		2.66		21,077		17.82		2,076		37.86

Outstanding — end of year	33,244		16.37		33,142		16.58		13,789		14.11

Eligible for exercise — end of year	31,057		$	15.75	11,732		$	13.44	10,751		$	9.31

The following table summarizes information about stock options outstanding at December 31, 2002 (in thousands of shares):

	Options Outstanding				Options Exercisable
Range of Exercise Prices	Total Outstanding	Weighted- Average Remaining Life (In Years)	Weighted- Average Exercise Price		Total Exercisable	Weighted- Average Exercise Price
$0.78 - $3.24	1,048	9.6	$	2.15	—	$	—
$3.25 - $9.88	4,787	2.5	5.39		4,707	5.34
$9.89 - $14.40	19,828	8.4	13.03		19,775	13.04
$14.41 - $22.85	2,924	5.7	17.85		2,884	17.89
$22.86 - $58.00	4,648	7.4	44.11		3,683	41.85
$58.01 - $80.00	9	7.7	61.42		8	61.19

Total	33,244	7.2	$	16.37	31,057	$	15.75

COMMON STOCK HELD BY SUBSIDIARIES—The Company has a secured equity-linked loan (“SELLS Loan”) of $225 million due in 2004 issued by AES New York Funding, LLC (the “NY SELLS Loan”). The NY SELLS loan was issued by a consolidated subsidiary and has been classified as non-recourse debt in the accompanying consolidated balance sheets.

NY SELLS Loan.

The NY SELLS Loan is secured by (i) a pledge by AES New York Funding LLC (the “NY SELLS Borrower”) of all of the limited liability company’s membership interests and partnership interests in the subsidiaries of the NY SELLS Borrower that own or operate the Somerset, Cayuga, Westover, Greenidge, Hickling and Jennison coal-fired electric generating plants (the “NY Generating Assets”) and (ii) approximately 218 million shares of common stock of the Company held in the name of the NY SELLS Borrower as of December 31, 2002.

The Company has no obligation to deliver any additional shares of the Company’s common stock as collateral to secure the SELLS Loan.

The events of default with respect to the SELLS Loan includes (a) typical events of default related to the NY SELLS Borrower, and (b) the occurrence and continuance of an “Event of Default” under the Company’s revolving credit agreement.

Upon the occurrence and during the continuance of an event of default, the lenders are entitled to accelerate the maturity of the NY SELLS Loan and to foreclose upon and sell the collateral. The lenders are not entitled to demand that the Company, nor is the Company obligated to, make any payment with respect to the SELLS Loan, repurchase any of the collateral or provide additional Company shares or other collateral.

The shares of Company stock that constitute collateral have not been registered under the Securities Act of 1933 and may not be sold in a foreclosure sale until so registered except in a manner exempt from the registration requirements of the Securities Act. The Company has agreed to cause the pledged Company shares to be registered by no later than November 28, 2004, or sooner if there has been a material adverse change in the business condition (financial or otherwise), operations, performance, properties or prospects of the NY SELLS Borrower or the NY Generating Assets, as the case may be.

The Company shares held in the name of the NY SELLS Borrower are not considered outstanding and therefore have been excluded from the calculation of earnings per share.

15. EARNINGS PER SHARE

The following table presents a reconciliation of the numerators and denominators of the basic and diluted earnings per share computations for (loss) income from continuing operations. In the table below, (loss) income represents the numerator (in millions) and shares represent the denominator (in millions):

	December 31, 2002									December 31, 2001									December 31, 2000
	Income			Shares		$ per Share				Income			Shares		$ per Share				Income			Shares		$ per Share

BASIC (LOSS) EARNINGS PER SHARE:
(Loss) income from continuing operations	$	(1,635)			538.9		$	(3.03)			$	413		532.2		$	0.78			$	691		482.1		$	1.43
EFFECT OF DILUTIVE SECURITIES:
Stock options and warrants	—				—		—				—			5.3		(0.01		)		—			9.5		(0.02		)
Stock units allocated to deferred compensation plans	—				—		—				—			0.4		—				—			0.5		—

Tecons and other convertible debt, net of tax	—				—		—				—			—		—				19			21.1		(0.02		)

DILUTED (LOSS) EARNINGS PER SHARE	$	(1,635	)		538.9		$	(3.03	)		$	413		537.9		$	0.77			$	710		513.2		$	1.39

There were approximately 28,207,330 and 4,048,700 and 173,000 options outstanding in 2002, 2001 and 2000 that were omitted from the earnings per share calculation because they were antidilutive. In 2002 and 2001, all Tecons and convertible debt were omitted from the earnings per share calculation because they were antidilutive. In 2000, a portion of the Tecons were omitted from the earnings per share calculation because they were antidilutive.

16. OTHER INCOME (EXPENSE)

The components of other income are summarized as follows (in millions):

	For the years ended December 31,
	2002		2001		2000

Gain on sale of assets	$	12	$	21	$	24
Gain on extinguishment of liabilities	62		9		3
Marked-to-market gain on commodity derivatives	23		9		—
Marked-to-market gain on investment	—		19		—
Legal/dispute settlement	12		—		16
Dividends	—		41		6
Rent	—		7		—
Other income	24		4		2

Total other income	$	133	$	110	$	51

The components of other expense are summarized as follows (in millions):

	For the years ended December 31,
	2002			2001			2000

Marked-to-market loss on commodity derivatives	$	—		$	(30	)	$	—
Loss on sale and disposal of assets	(33		)	(10		)	(14		)
Loss on extinguishment of liabilities	—			—			(16		)
Legal/dispute settlement	(10		)	(3		)	—
Environmental fine	—			—			(17		)
Other expenses	(34		)	(16		)	(5		)

Total other expense	$	(77	)	$	(59	)	$	(52	)

On April 1, 2002, the Company adopted SFAS No. 145, “Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” Among other items, this Statement rescinds FASB Statement No. 4, “Reporting Gains and Losses from Extinguishments of Debt.” As a result, gains and losses from early extinguishments of debt in 2002, 2001 and 2000 are no longer reported as extraordinary items but have been reclassified to income from continuing operations.

17. INCOME TAXES

INCOME TAX PROVISION—The (benefit) expense for income taxes on continuing operations consists of the following (in millions):

	Years Ended December 31,
	2002			2001		2000

Federal:
Current	$	—		$	2	$	146
Deferred	60			42		0
State:
Current	6			—		20
Deferred	(17		)	7		(2		)
Foreign:
Current	118			179		180
Deferred	130			46		24

Total	$	297		$	276	$	368

The Company records its share of earnings of its equity investees on a pre-tax basis. The Company’s share of the investees’ income taxes is recorded in income tax expense.

EFFECTIVE AND STATUTORY RATE RECONCILIATION—A reconciliation of the U.S. statutory Federal income tax rate to the Company’s effective tax rate as a percentage of income before taxes (after minority interest) is as follows:

	Years Ended December 31,
	2002		2001		2000

Statutory Federal tax rate	35	%	35	%	35	%
State taxes, net of Federal tax benefit	1		1		1
Taxes on foreign earnings	4		4		1
Valuation allowance	(61	)	—		—
Other-net	(1	)	—		(2	)

Effective tax rate	(22)	%	40	%	35	%

DEFERRED INCOME TAXES—Deferred income taxes reflect the net tax effects of (a) temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes, and (b) operating loss and tax credit carry forwards. These items are stated at the enacted tax rates that are expected to be in effect when taxes are actually paid or recovered.

As of December 31, 2002, the Company had Federal net operating loss carry forwards for tax purposes of approximately $201 million expiring from 2019 through 2021, Federal general business tax credit carry forwards for tax purposes of approximately $51 million expiring in years 2005 through 2022, and Federal alternative minimum tax credits of approximately $8 million that carry forward without expiration. As of December 31, 2002, the Company had foreign net operating loss carry forwards of approximately $2.5 billion that expire at various times beginning in 2003, and some of which carry forward without expiration, and foreign investment and assets tax credits of approximately $36 million that expire at various times beginning in 2003 through 2007. The Company had state net operating loss carry forwards as of December 31, 2002, of approximately $495 million expiring in years 2003 through

2022, and state tax credit carry forwards of approximately $3 million expiring in years 2003 through 2010.

The valuation allowance increased by $755 million during 2002 to $862 million at December 31, 2002. This increase was primarily the result certain foreign net operating loss carry forwards, capital loss carry forwards and the cumulative effects of certain foreign currency translation losses. The ultimate realization of these deferred tax assets is not known at this time. The Company believes that it is more likely than not that the remaining deferred tax assets as shown below will be realized.

Deferred tax assets and liabilities are as follows (in millions):

	December 31,
	2002			2001

Differences between book and tax basis of property	$	1,205		$	1,261
Other taxable temporary differences	121			103

Total deferred tax liability	$	1,326		$	1,364

Operating loss carry forwards	(754		)	(443		)
Capital loss carry forwards	(348		)	—
Bad debt and other book provisions	(153		)	(109		)
Retirement costs	(389		)	(66		)
Tax credit carry forwards	(91		)	(135		)
Other deductible temporary differences	(541		)	(335		)

Total gross deferred tax asset	(2,276		)	(1,088		)
Less: valuation allowance	862			107

Total net deferred tax asset	(1,414		)	(981		)

Net deferred tax (asset)/liability	$	(88	)	$	383

Undistributed earnings of certain foreign subsidiaries and affiliates aggregated approximately $1.2 billion and $1.4 billion at December 31, 2002 and 2001, respectively. The Company considers these earnings to be indefinitely reinvested outside of the United States and, accordingly, no U.S. deferred taxes have been recorded with respect to such earnings. Should the earnings be remitted as dividends, the Company may be subject to additional U.S. taxes, net of allowable foreign tax credits. It is not practicable to estimate the amount of any additional taxes which may be payable on the undistributed earnings.

Income from operations in certain countries is subject to reduced tax rates as a result of satisfying specific commitments regarding employment and capital investment. The reduced tax rates for these operations will be in effect for the life of the related businesses, at the end of which ownership transfers back to the local government. The income tax benefits related to the tax status of these operations are estimated to be $41 million, $33 million and $29 million for the years ended December 31, 2002, 2001 and 2000, respectively.

(Loss) income from continuing operations before income taxes consisted of the following:

	Years Ended December 31,
	2002			2001		2000

U.S	$	(172	)	$	282	$	614
Non U.S	(1,166		)	407		445

Total	$	(1,338	)	$	689	$	1,059

18. BENEFIT PLANS

PROFIT SHARING AND STOCK OWNERSHIP PLANS—The Company sponsors one defined contribution plan, qualified under section 401 of the Internal Revenue Code, which is available to eligible AES people. The plan provides for Company matching contributions, other Company contributions at the discretion of the Compensation Committee of the Board of Directors, and discretionary tax deferred contributions from the participants. Participants are fully vested in their own contributions and the Company’s matching contributions. Participants vest in other Company contributions ratably over a five-year period ending on the 5th anniversary of their hire date. Company contributions to the plans were approximately $15 million, $13 million and $11 million for the years ended December 31, 2002, 2001 and 2000, respectively.

DEFERRED COMPENSATION PLANS—The Company sponsors a deferred compensation plan under which directors of the Company may elect to have a portion, or all, of their compensation deferred. The amounts allocated to each participant’s compensation account may be converted into common stock units. Upon termination or death of a participant, the Company is required to distribute, under various methods, cash or the number of shares of common stock accumulated within the participant’s deferred compensation account. Distribution of stock is to be made from common stock held in treasury or from authorized but previously unissued shares. The plan terminates and full distribution is required to be made to all participants upon any change of control of the Company (as defined in the plan document). No stock associated with distributions was issued during 2002, 2001, or 2000 under such plan.

Common stock units held under the AES deferred compensation plans do not represent issued shares of common stock. The deferred compensation liabilities related to such plans were approximately $1 million as of December 31, 2002 and 2001, and were convertible into approximately 857,000 and 795,000 shares at December 31, 2002 and 2001, respectively. For those electing to participate in the deferred compensation plans the amount of the stock unit award is based on the compensation and average stock price during the compensation period. The liabilities will only be settled in stock, except cash settlement is required in the event of certain recapitalization transactions, as defined in the plan documents.

In addition, the Company sponsors an executive officers’ deferred compensation plan. At the election of an executive officer, the Company will establish an unfunded, nonqualified compensation arrangement for each officer who chooses to terminate participation in the Company’s profit sharing and employee stock ownership plans. The participant may elect to forego payment of any portion of his or her compensation and have an equal amount allocated to a contribution account. In addition, the Company will credit the participant’s account with an amount equal to the Company’s contributions (both matching and profit sharing) that would have been made on such officer’s behalf if he or she had been a participant in the profit sharing plan. The participant may elect to have all or a portion of the Company’s contributions converted into stock units. Dividends paid on common stock are allocated to the participant’s account in the form of stock units. The participant’s account balances are distributable upon termination of employment or death.

The Company also sponsors a supplemental retirement plan covering certain highly compensated AES people. The plan provides incremental profit sharing and matching contributions to participants that would have been paid to their accounts in the Company’s profit sharing plan if it were not for limitations imposed by income tax regulations. All contributions to the plan are vested in the manner provided in the Company’s profit sharing plan, and once vested are nonforfeitable. The participant’s account balances are distributable upon termination of employment or death.

DEFINED BENEFIT PLANS—Certain of the Company’s subsidiaries have defined benefit pension plans covering substantially all of their respective employees. Pension benefits are based on years of credited service, age of the participant and average earnings. Of the thirteen defined benefit plans, three

are at U.S. subsidiaries and the remaining are at foreign subsidiaries. Prior to the consolidation of Eletropaulo in February 2002, the Company did not have significant benefit obligations from its foreign plans. Since the consolidation of Eletropaulo, the benefit obligation from foreign plans has become significant relative to the total; therefore, the 2002 amounts will distinguish between the U.S. and foreign plans.

Significant weighted average assumptions used in the calculation of pension benefits expense and obligation are as follows:

	Pension Benefits Years Ended December 31,
	2002				2001		2000
	U.S.		Foreign

Discount rates	6.7	%	8.8	%	7.0	%	6.2	%
Rates of compensation increase	0.30	%	5.7	%	0.8	%	2.3	%
Expected long-term rate of return on plan assets	8.96	%	14.1	%	9.1	%	9.5	%

A subsidiary of the Company has a defined benefit plan, which has a benefit obligation of $411 million and $383 million at December 31, 2002 and 2001, respectively, and uses salary bands to determine future benefit costs rather than rate of compensation increases. As such, rates of compensation increase in the table above do not include amounts relating to this specific defined benefit plan.

Total pension cost for the years ended December 31, 2002, 2001 and 2000 includes the following components (in millions):

	Pension Costs Years Ended December 31
	2002						2001			2000
	U.S.			Foreign

Service cost	$	3		$	7		$	6		$	11
Interest cost on projected benefit obligation	28			136			39			33
Expected return on plan assets	(23		)	(87		)	(27		)	(33		)
Amount of curtailment (gain) loss recognized	(1		)	3			6			6
VERP benefits	3			—			19			57
Amortization of unrecognized actuarial loss (gain)	—			16			1			(6		)

Total pension cost	$	10		$	75		$	44		$	68

The changes in the benefit obligation of the plans combined for the years ended December 31, 2002 and 2001 are as follows (in millions):

	2002						2001
	U.S.			Foreign
CHANGE IN BENEFIT OBLIGATION:
Benefit obligation at beginning of year	$	407		$	182		$	538
Effect of foreign currency exchange rate change on beginning balance	—			(64		)	(25		)
Service cost	3			7			6
Interest cost	28			136			39
Plan acquired	3			1,477			4
VERP benefits	—			—			19
Benefits paid	(30		)	(120		)	(37		)
Actuarial loss	18			222			56
Other	9			4			(11		)

Benefit obligation as of December 31	$	438		$	1,844		$	589

The changes in the plan assets of the plans combined for the years ended December 31, 2002 and 2001 are as follows (in millions):

	2002						2001
	U.S.			Foreign
CHANGE IN PLAN ASSETS:
Fair value of plan assets at beginning of year	$	264		$	55		$	368
Fair value of plan acquired	—			635			—
Effect of foreign currency exchange rate change on beginning balance	—			(9		)	(6		)
Actual return on plan assets	(20		)	66			(25		)
Benefits paid	(30		)	(120		)	(34		)
Employer Contributions	18			145			29
Other	—			1			(14		)

Fair value of plan assets as of December 31	$	232		$	773		$	(318	)

The funded status of the plans combined for the years ended as of December 31, 2002 and 2001 are as follows (in millions):

	2002						2001
	U.S.			Foreign
Funded status	$	(205	)	$	(1,072	)	$	(270	)
Unrecognized net actuarial loss	90			613			36
Other	—			(7		)	2

Accrued benefit cost as of December 31	$	(115	)	$	(466	)	$	(232	)

	2002						2001
	U.S.			Foreign
Accrued benefit liability	$	(191	)	$	(1,072	)	$	(243	)
Accumulated other comprehensive loss	76			606			11

Net amount recognized	$	(115	)	$	(466	)	$	(232	)

All of the Company’s plans at December 31, 2002 and 2001 had benefit obligations exceeding the fair value of the related plan’s assets. The tables above exclude approximately $2 million, $3 million and $2 million in total pension cost for the years ended December 31, 2002, 2001 and 2000, respectively, benefit obligations of $410 million and $320 million, and fair value of assets of $299 million and $286 million related to businesses that are discontinued as of December 31, 2002 and 2001, respectively.

From November 2000 through September 2001, a subsidiary of the Company implemented several Voluntary Early Retirement Programs (“VERP”). These programs offer enhanced retirement benefits upon early retirement to eligible employees. The VERP was available to all employees, except officers, whose combined age and years of service totaled at least 75 on June 30, 2001. Participation was limited to, and subsequently accepted by 550 qualified employees. Participants elected actual retirement dates in 2001. Additionally, the post-retirement benefits will be provided to VERP retirees until age 55 at which time they will be eligible to receive benefits from the independent Voluntary Employee Benefit Association trustee. The subsidiary recognized $0 million, $19 million and $57 million of pre-tax non-cash pension benefit costs for the VERP in 2002, 2001 and 2000, respectively.

In August 2002, a subsidiary of the Company implemented a VERP. The VERP was offered to 56 qualified plan participants. The 27 participants that accepted the offer retired effective September 1, 2002. The subsidiary recognized $3 million of pre-tax non-cash benefit costs for the VERP in 2002.

During 2000, a subsidiary of the Company curtailed one of its defined benefit plans. In connection with the curtailment, the subsidiary paid approximately $8 million and transferred approximately $145 million of plan assets to an independent trustee.

19. SEGMENTS

The Company operates in four business segments: contract generation, competitive supply, large utilities and growth distribution businesses. Contract generation businesses are businesses that supply wholesale electricity under long-term contracts for more than 75% of their output, and these businesses generally have little exposure to commodity price risk. Competitive supply businesses are businesses that supply wholesale electricity pursuant to short-term contracts or into spot electricity markets. Competitive supply businesses are generally exposed to commodity price risk. Large utility businesses are utilities of significant size that maintain a monopoly franchise within a defined service area, and these businesses are generally subjected to extensive regulation in their respective jurisdiction. Growth distribution businesses are distribution businesses that offer significant potential for growth because they face particular challenges related to operational difficulties such as outdated equipment, significant non-technical losses, cultural problems, emerging economies, less stable governments or regulatory regimes, or location in a developing nation that allow for operating improvements that would result in financial performance improvement that are typically greater that those seen in the large utility business. Although the nature of the product is the same, the segments are differentiated by the nature of the customers, operational differences and risk exposure. All balance sheet information for businesses that were discontinued during the year are broken out and shown separately in the chart below. All income statement related information is shown in the line “Discontinued operations” in the accompanying consolidated statements of operations.

The accounting policies of the four business segments are the same as those described in Note 1—General and Summary of Significant Accounting Policies. The Company uses gross margin to evaluate the performance of its business segments. Depreciation and amortization at the business segments are included in the calculation of gross margin. Corporate depreciation and amortization is reported within selling, general and administrative expenses in the consolidated statements of operations. Pre-tax equity in earnings is used to evaluate the performance of businesses that are significantly influenced by the

Company. Sales between the segments are accounted for at fair value as if the sales were to third parties. All intersegment activity has been eliminated with respect to revenue and gross margin.

Information about the Company’s operations and assets by segment is as follows (in millions):

	Revenues(1)		Depreciation and Amortization		Gross Margin(2)		Pre-Tax Equity in (Loss) Earnings(3)			Total Assets		Investment in and Advances to Affiliates			Property Additions
Year Ended December 31, 2002

Contract Generation	$	2,406	$	226	$	1,023	$	75		$	12,092	$	671		$	926
Competitive Supply	982		67		218		(7		)	3,727		7			452
Large Utilities	3,137		286		685		(275		)	8,451		0			300
Growth Distribution	1,117		90		19		—			2,817		(20		)	96
Discontinued Businesses	—		—		—		—			6,740		—			341
Corporate	—		2		—		—			403		20			1
Total	$	7,642	$	671	$	1,945	$	(207	)	$	34,230	$	678		$	2,116

	Revenues(1)		Depreciation and Amortization		Gross Margin(2)		Pre-Tax Equity in (Loss) Earnings(3)			Total Assets		Investment in and Advances to Affiliates			Property Additions
Year Ended December 31, 2001

Contract Generation	$	2,353	$	253	$	833	$	54		$	11,647	$	660		$	737
Competitive Supply	1,077		77		264		(9		)	4,567		46			1,308
Large Utilities	1,642		203		618		144			7,444		2,292			378
Growth Distribution	1,559		107		264		(13		)	4,077		12			63
Discontinued Businesses	—		—		—		—			8,801		—			684
Corporate	—		3		—		—			276		21			3
Total	$	6,631	$	643	$	1,979	$	176		$	36,812	$	3,031		$	3,173

	Revenues(1)		Depreciation and Amortization		Gross Margin(2)		Pre-Tax Equity in (Loss) Earnings(3)			Total Assets		Investment in and Advances to Affiliates			Property Additions
Year Ended December 31, 2000

Contract Generation	$	1,696	$	160	$	746	$	49		$	9,915	$	517		$	1,114
Competitive Supply	840		55		282		—			3,005		27			630
Large Utilities	1,385		191		437		426			7,807		2,485			76
Growth Distribution	1,236		81		145		—			3,647		23			106
Discontinued Businesses	—		—		—		—			8,524		—			300
Corporate	—		1		—		—			140		30			—
Total	$	5,157	$	488	$	1,610	$	475		$	33,038	$	3,082		$	2,226

(1) Intersegment revenues for the years ended December 31, 2002, 2001, and 2000 were $213 million, $113 million and $81 million, respectively.

(2) For consolidated subsidiaries, the measure of profit or loss used for our reportable segments is gross margin. Gross margin equals revenues less cost of sales on the consolidated statement of operations for each year presented.

(3) For equity method investments, the measure of profit or loss used for our reportable segments is pre-tax equity in earnings.

Revenues are recorded in the country in which they are earned and assets are recorded in the country in which they are located. Information about the Company’s consolidated operations and long-lived assets by country are as follows (in millions):

	Revenues						Property, Plant and Equipment, net
	2002		2001		2000		2002		2001		2000

United States	$	2,085	$	2,079	$	2,078	$	6,133	$	6,320	$	5,754
Non-U.S:


Brazil	2,193		844		695		2,797		1,744		2,034

Argentina	218		456		481		486		1,725		1,551
Chile	363		446		—		946		1,023		—
Venezuela	634		806		494		2,436		2,369		2,218
Dominican Republic	301		391		333		547		424		225
El Salvador	312		321		139		300		250		153
Pakistan	226		230		233		309		301		319
United Kingdom	207		204		113		406		417		392
Colombia	125		124		—		473		481		41
Hungary	197		175		177		125		97		91
Ukraine	152		85		—		94		120		—

Other Non-U.S.(1)	629		470		414		3,122		2,252		944

Total Non-U.S	5,557		4,552		3,079		12,041		11,203		7,968

Total	$	7,642	$	6,631	$	5,157	$	18,174	$	17,523	$	13,722

(1) AES has operations in 15 countries, which are included in this category.

20. FAIR VALUE OF FINANCIAL INSTRUMENTS

The fair value of current financial assets, current financial liabilities, and debt service reserves and other deposits, are estimated to be equal to their reported carrying amounts. The fair value of non-recourse debt, excluding capital leases, is estimated differently based upon the type of loan. For variable rate loans, carrying value approximates fair value. For fixed rate loans, other than securities registered and publicly traded, the fair value is estimated using discounted cash flow analyses based on the Company’s current incremental borrowing rates. The fair value of interest rate swap, cap and floor agreements, foreign currency forwards and swaps, and energy derivatives is the estimated net amount that the Company would receive or pay to terminate the agreements as of the balance sheet date. The estimated fair values for certain of the notes and bonds included in non-recourse debt, and certain of the recourse debt and Tecons, which are registered and publicly traded, are based on quoted market prices.

The estimated fair values of the Company’s assets and liabilities have been determined using available market information. The estimates are not necessarily indicative of the amounts the Company could realize in a current market exchange. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.

The estimated fair values of the Company’s debt and derivative financial instruments as of December 31, 2002 and 2001 are as follows (in millions):

	December 31, 2002				December 31, 2001
	Carrying Amount		Fair Value		Carrying Amount		Fair Value

Assets:
Foreign currency forwards and swaps, net	$	17	$	17	$	14	$	14
Energy derivatives, net	201		201		7		7
Liabilities:
Non-recourse debt	17,658		20,447		16,857		17,064
Recourse debt	5,804		3,895		5,401		4,730
Tecons	978		284		978		626
Interest rate swaps	557		557		166		166
Interest rate caps and floors, net	115		115		72		72

Amounts in the table above include the carrying amount and fair value of financial instruments of discontinued operations and assets held for sale, except for preferred stock with mandatory redemption of one of our discontinued operations that has a carrying amount of $22 million.

As of December 31, 2002, discontinued operations and assets held for sale had non-recourse debt with a carrying amount and fair value of $3,738 million and $5,481 million, respectively, foreign currency forwards and swaps, net (assets), with a carrying amount and fair value of $13 million, interest rate swaps (liabilities) with a carrying amount and fair value of $133 million and interest rate caps and floors, net (liabilities), with a carrying amount and fair value of $43 million.

The fair value estimates presented herein are based on pertinent information as of December 31, 2002 and 2001. The Company is not aware of any factors that would significantly affect the estimated fair value amounts since December 31, 2002.

21. NEW ACCOUNTING PRONOUNCEMENTS

Asset retirement obligations. In June 2001, the Financial Accounting Standards Board issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143, which is effective January 1, 2003, requires entities to record the fair value of a legal liability for an asset retirement obligation in the period in which it is incurred. When a new liability is recorded beginning in 2003, the entity will capitalize the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The Company will adopt SFAS No. 143 effective January 1, 2003.

The Company has completed a detailed assessment of the specific applicability and implications of SFAS No. 143. The scope of SFAS No. 143 includes primarily active ash landfills, water treatment basins and the removal or dismantlement of certain plant and equipment. As of December 31, 2002, the Company had a recorded liability of approximately $15 million related to asset retirement obligations. Upon adoption of SFAS No. 143, the Company will record an additional liability of approximately $13 million, a net asset of approximately $9 million, and a cumulative effect of a change in accounting principle of approximately $2 million, after income taxes. Proforma net (loss) income and (loss) earnings per share have not been presented for the years ended December 31, 2002, 2001 and 2000 because the proforma application of SFAS No. 143 to prior periods would result in proforma net (loss) income and (loss) earnings per share not materially different from the actual amounts reported for those periods in the accompanying consolidated statements of operations.

Early extinguishments of debt. During the second quarter of 2002, the Company adopted SFAS No. 145, “Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” Among other items, this Statement rescinds FASB Statement No. 4, “Reporting Gains and Losses from Extinguishments of Debt.” As a result, early extinguishments of debt are no longer reported as extraordinary items but are included in income from continuing operations. For the year ended December 31, 2002, the Company extinguished debt with a face value of approximately $117 million for approximately 21.6 million shares of the Company’s common stock. This resulted in a gain of approximately $44 million for the year ended December 31, 2002 which is recorded in other income in the accompanying consolidated statement of operations. There were no early extinguishments of debt during 2001. In 2000, the Company recognized losses of approximately $11 million related to the early extinguishment of debts.

Exit or disposal activities. In June 2002, the Financial Accounting Standards Board issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” which addresses financial accounting and reporting for costs associated with exit or disposal activities. This Statement requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred. Prior to issuance of SFAS No. 146, a liability for an exit cost was recognized at the date of an entity’s commitment to an exit plan. The provisions of this Statement are effective for exit or disposal activities that are initiated after December 31, 2002. We do not expect the adoption of this pronouncement to have a material impact on our financial statements.

Stock-based compensation. In December 2002, the Financial Accounting Standards Board issued SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure.” SFAS No. 148 amends SFAS No. 123, “Accounting for Stock-Based Compensation” to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of Statement 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The Company expects to use the prospective method to transition to the fair value based method of accounting for stock-based employee compensation. All employee awards granted, modified, or settled after January 1, 2003, will be recorded using the fair value based method of accounting. The expanded disclosures required by SFAS No. 148 will be included in our quarterly financial reports beginning in the first quarter of 2003.

Guarantor accounting. The Company adopted the disclosure provisions of FASB Interpretation No. (“FIN”) 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Direct Guarantees of Indebtedness of Others,” in the fourth quarter of 2002. We will apply the initial recognition and measurement provisions on a prospective basis for all guarantees issued after December 31, 2002. Under FIN 45, at the inception of guarantees issued after December 31, 2002, we will record the fair value of the guarantee as a liability, with the offsetting entry being recorded based on the circumstances in which the guarantee was issued. We will account for any fundings under the guarantee as a reduction of the liability. After funding has ceased, we will recognize the remaining liability in the income statement on a straight-line basis over the remaining term of the guarantee. In general, we enter into various agreements providing financial performance assurance to third parties on behalf of certain subsidiaries. Such agreements include guarantees, letters of credit and surety bonds. FIN 45 does not encompass guarantees issued either between parents and their subsidiaries or between corporations under common control, a parent’s guarantee of its subsidiary’s debt to a third party (whether the parent is a corporation or an individual), a subsidiary’s guarantee of the debt owed to a third party by either its parent or another subsidiary of that parent, nor guarantees of a Company’s own future performance. Adoption of FIN 45 will have no impact to our historical financial statements as existing guarantees are not subject to the measurement provisions of FIN 45. The Company does not

expect adoption of the liability recognition provisions of FIN 45 to have a material impact on our financial position or results of operations.

Variable interest entities. FIN 46, “Consolidation of Variable Interest Entities,” is effective immediately for all enterprises with variable interests in variable interest entities created after January 31, 2003. FIN 46 provisions must be applied to variable interests in variable interest entities created before February 1, 2003 from the beginning of the third quarter of 2003. If an entity is determined to be a variable interest entity, it must be consolidated by the enterprise that absorbs the majority of the entity’s expected losses if they occur and/or receives a majority of the entity’s expected residual returns if they occur. If significant variable interests are held in a variable interest entity, the company must disclose the nature, purpose, size and activity of the variable interest entity and the company’s maximum exposure to loss as a result of its involvement with the variable interest entity in all financial statements issued after January 31, 2003. We do not believe that the adoption of FIN 46 will result in our consolidation of any previously unconsolidated entities or material additional disclosure.

DIG Issue C11. In connection with the January 2003 FASB Emerging Issues Task Force (EITF) meeting, the FASB was requested to reconsider an interpretation of SFAS No. 133. The interpretation, which is contained in the Derivatives Implementation Group’s C11 guidance, relates to the pricing of contracts that include broad market indices. In particular, that guidance discusses whether the pricing in a contract that contains broad market indices (e.g. CPI) could qualify as a normal purchase or sale. The Company is currently reevaluating which contracts, if any, that have previously been designated as normal purchases or sales would now not qualify for this exception. The Company is currently evaluating the effects that this guidance will have on its results of operations and financial position.

SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

The following table summarizes the unaudited quarterly statements of operations for the Company for 2002 and 2001, giving effect to the acquisition of IPALCO as if it had occurred at the beginning of the earliest period presented (in millions, except per share amounts). Additionally, the amounts have been adjusted to report the impact of our classification of certain businesses during the three months ended March 31, 2003 as discontinued operations pursuant to SFAS No. 144.

	Quarter Ended 2002 (As restated (2))
	Mar 31			Jun 30			Sep 30			Dec 31

Revenues	$	1,965		$	1,846		$	1,895		$	1,936

Gross margin	613			386			539			407

Income (loss) from continuing operations	95			(99		)	(206		)	(1,425		)

Discontinued operations	64			(143		)	(108		)	(1,341		)
Cumulative effect of change in accounting principle	(473		)	127			—			—
Net loss	(314		)	(115		)	(314		)	(2,766		)
Basic loss per share: (1,2)
Income (loss) from continuing operations	$	0.18		$	(0.18	)	$	(0.39	)	$	(2.62	)
Discontinued operations	0.12			(0.27		)	(0.19		)	(2.46		)
Cumulative effect of accounting change	(0.88		)	0.23			—			—

Basic loss per share	$	(0.58	)	$	(0.22	)	$	(0.58	)	$	(5.08	)

Diluted loss per share: (1,2)
Income (loss) from continuing operations	$	0.18		$	(0.18	)	$	(0.39	)	$	(2.62	)
Discontinued operations	0.12			(0.27		)	(0.19		)	(2.46		)
Cumulative effect of accounting change	(0.88		)	0.23			—			—

Diluted loss per share	$	(0.58	)	$	(0.22	)	$	(0.58	)	$	(5.08	)

	Quarter Ended 2001 (As restated (2))
	Mar 31			Jun 30			Sep 30			Dec 31

Revenues	$	1,746		$	1,633		$	1,590		$	1,662

Gross margin	540			421			427			591

Income from continuing operations	116			140			11			146

Discontinued operations	(5		)	(25		)	(8		)	(102		)
Net income	111			115			3			44
Basic earnings per share:

Income from continuing operations	$	0.22		$	0.27		$	0.03		$	0.27

Discontinued operations	(0.01		)	(0.05		)	(0.02		)	(0.19		)

Basic earnings per share	$	0.21		$	0.22		$	0.01		$	0.08

Diluted earnings per share: (1)

Income from continuing operations	$	0.22		$	0.27		$	0.03		$	0.27
Discontinued operations	(0.01		)	(0.06		)	(0.02		)	(0.19		)

Diluted earnings per share	$	0.21		$	0.21		$	0.01		$	0.08

(1) The sum of these amounts does not equal the annual amount due to rounding or because the quarterly calculations are based on varying numbers of shares outstanding.

(2) The quarterly information has been presented based on discontinued operations classifications as of September 30, 2003. Results of operations for periods prior to the third quarter 2003 for components that were either disposed of or held for sale and treated as discontinued operations in the nine months ended September 30, 2003 have been reclassified into discontinued operations. Subsequent to the issuance of the Company’s results for the third quarter 2002, it came to the Company’s attention that the results of operations of AES Greystone, LLC should not be treated as a discontinued operation because it did not qualify as an operating business component of the Company. Accordingly, the quarterly information for the third quarter 2002 has been restated to reclassify the loss from operations of AES Greystone, LLC, which amounted to $109 million, net of income taxes, into income (loss) from continuing operations. No restatement of earlier quarters was necessary because Greystone had no income or loss prior to the third quarter 2002.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned here unto duly authorized.

	THE AES CORPORATION

Date: November 21, 2003	By	/S/ Barry J. Sharp
	Executive Vice President and Chief Financial Officer

EXHIBIT INDEX

Exhibit No.	Description	Method of Filing

22.1	Independent Auditors’ Consent	Filed herewith