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# UNITED	STATES

# SECURITIES	AND	EXCHANGE	COMMISSION

# ANNUAL	REPORT	PURSUANT	TO	SECTION	13	OR	15(d)	OF	THE SECURITIES	EXCHANGE	ACT	OF	1934

# FOR	THE	FISCAL	YEAR	ENDED	DECEMBER	31,	2002

COMMISSION	FILE	NUMBER	0-19281

# The	AES	Corporation

(Exact	name	of	registrant	as	specified	in	its	charter)

Delaware

(State	or	other	jurisdiction	of incorporation	or	organization)

Arlington,	Virginia

(Address	of	principal	executive	offices)

(I.R.S.	Employer	Identification	No.)

(Zip	Code)

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

Securities	registered	pursuant	to	Section	12(b)	of	the	Act:

# Title	of	Each	Class

# Name	of	Each	Exchange	on	Which	Registered

Securities	registered	pursuant	to	Section	12(g)	of	the	Act:

Indicate	by	check	mark	whether	the	registrant	(1)	has	filed	all	reports	required	to	be	filed	by	Section	13	or	15(d)	of	the	Securities	Exchange	Act	of	1934	during	the preceding	12	months	(or	for	such	shorter	period	that	the	registrant	was	required	to	file	such	reports),	and	(2)	has	been	subject	to	such	filing	requirements	for	the	past 90	days.	Yes	ý				No	o

Indicate	by	check	mark	if	disclosure	of	delinquent	filers	pursuant	to	Item	405	of	Regulation	S-K	is	not	contained	herein,	and	will	not	be	contained,	to	the	best	of registrant's	knowledge,	in	definitive	proxy	or	information	statements	incorporated	by	reference	in	Part	III	of	this	Form	10-K	or	any	amendment	to	this	Form	10-K.	o

Indicate	by	check	mark	whether	the	registrant	is	an	accelerated	filer	(as	defined	in	Rule	12b-2	of	the	Act).	Yes	ý				No	o

The	aggregate	market	value	of	Registrant's	voting	stock	held	by	non-affiliates	of	Registrant,	on	June	28,	2002	(based	on	the	closing	sale	price	of	$5.42	of	the	Registrant's Common	Stock,	as	reported	by	the	New	York	Stock	Exchange	on	such	date)	was	approximately	$2,421,114,000.	The	number	of	shares	outstanding	of	Registrant's Common	Stock,	par	value	$0.01	per	share,	on	March	3,	2003,	was	564,542,183.

# DOCUMENTS	INCORPORATED	BY	REFERENCE

The	Proxy	Statement	for	the	Annual	Meeting	of	Stockholders	of	the	Registrant	to	be	held	on	May	1,	2003	is	hereby	incorporated	by	reference.	Certain	information therein	is	incorporated	by	reference	into	Part	III	hereof.

# AES	CORPORATION

TABLE	OF	CONTENTS

| Part	I |  |
| :--- | :--- |
| Item\t1—Business | 1 |
| Item\t2—Properties | 28 |
| Item\t3—Legal\tProceedings | 29 |
| Item\t4—Submission\tof\tMatters\tto\ta\tVote\tof\tSecurity\tHolders | 33 |

| Part	II |  |
| :--- | :--- |
| Item\t5—Market\tfor\tRegistrant's\tCommon\tEquity\tand\tRelated\tStockholder\tMatters | 34 |
| Item\t6—Selected\tFinancial\tData | 35 |
| Item\t7—Discussion\tand\tAnalysis\tof\tFinancial\tCondition\tand\tResults\tof\tOperations | 36 |
| Item\t7a—Quantitative\tand\tQualitative\tDisclosures\tAbout\tMarket\tRisk | 78 |
| Item\t8—Financial\tStatements\tand\tSupplementary\tData | 80 |
| Item\t9—Changes\tin\tand\tDisagreements\twith\tAccountants\ton\tAccounting\tand |  |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\tFinancial\tDisclosure | 153 |
| Part\tIII |  |
| Item\t10—Directors\tand\tExecutive\tOfficers\tof\tthe\tRegistrant | 153 |
| Item\t11—Executive\tCompensation | 153 |
| Item\t12—Security\tOwnership\tof\tCertain\tBeneficial\tOwners\tand\tManagement | 153 |
| Item\t13—Certain\tRelationships\tand\tRelated\tTransactions | 153 |
| Item\t14—Disclosure\tControls\tand\tProcedures | 153 |
| Part\tIV |  |
| Item\t15—Exhibits,\tFinancial\tStatement\tSchedules\tand\tReports\ton\tForm\t8-K | 154 |
| Signatures | 158 |

# Part	I

# Overview

The	AES	Corporation	(including	all	its	subsidiaries	and	affiliates,	and	collectively	referred	to	herein	as	"AES"	or	the	"Company"	or	"we"),	founded	in	1981,	is	a	leading global	power	company.	The	Company's	goal	is	to	help	meet	the	world's	need	for	electric	power	in	ways	that	benefit	all	of	our	stakeholders.	AES	participates	primarily	in four	lines	of	business:	contract	generation,	competitive	supply,	large	utilities	and	growth	distribution.

# Mission	Statement

The	Company's	goal	is	to	help	meet	the	world's	need	for	electric	power	in	ways	that	benefit	all	of	our	stakeholders,	to	build	long-term	value	for	the	Company's shareholders,	and	to	assure	sustained	performance	and	viability	of	the	Company	for	its	owners,	employees	and	other	individuals	and	organizations	who	depend	on	the Company.	To	achieve	this	goal,	the	Company	has	taken	steps	to	improve	performance	and	achieve	excellence	in	the	operation	and	management	of	each	and	every	AES business,	including	the	implementation	of	a	compensation	system	which	is	dependent,	in	part,	on	each	individual	within	AES	meeting	performance	goals	and	targets. The	Company	shall	continue	to	be	guided	by	the	four	shared	values	that	helped	shape	the	Company's	culture:	Integrity,	Fairness,	Fun	and	Social	Responsibility.

# Contract	Generation

AES's	contract	generation	line	of	business	consists	of	multiple	power	generation	facilities	located	around	the	world.	Provided	that	the	counterparty's	credit	remains viable,	these	facilities	have	contractually	limited	their	exposure	to	commodity	price	risks	and	electricity	price	volatility	by	entering	into	long-term	(five	years	or	longer) power	purchase	agreements	for	75%	or	more	of	their	capacity.	Because	they	have	contracted	for	a	majority	of	their	anticipated	output,	they	are	able	to	project	their	fuel supply	requirements	and	also,	generally,	enter	into	long-term	agreements	for	most	of	their	fuel	(coal,	natural	gas	or	fuel	oil	or	other	similar	fuel)	supply	requirements, thereby	also	limiting	their	exposure	to	fuel	price	volatility.	Through	these	contractual	agreements,	the	businesses	generally	increase	the	predictability	of	their	cash	flows and	earnings.	In	order	to	meet	AES's	definition	of	its	contract	generation	segment,	long-term	power	purchase	agreements	must	have	minimum	initial	durations	of	five years	or	longer	and	are	typically	entered	into	with	one	major	customer,	but	may	also	be	with	a	series	of	unrelated	customers.	In	addition,	AES	may	enter	into	tolling	or "pass	through"	arrangements	whereby	the	counterparty	directly	provides	the	necessary	fuel	and	markets	the	resulting	power	output	generated.	However,	not	all businesses	within	AES's	contract	generation	line	of	business	have	the	same	degree	of	contractually	limited	exposure,	and	therefore,	the	degree	of	predictability	may	vary from	business	to	business.

# Competitive	Supply

AES's	competitive	supply	line	of	business	consists	of	generating	facilities	that	sell	electricity	directly	to	wholesale	customers	in	competitive	markets.	Additionally,	as compared	to	the	contract	generation	segment	discussed	above,	these	generating	facilities	generally	sell	less	than	75%	of	their	output	pursuant	to	long-term	contracts	with pre-determined	pricing	provisions	and/or	sell	into	power	pools,	under	shorter-term	contracts	or	into	daily	spot	markets.	The	prices	paid	for	electricity	under	short-term contracts	and	in	the	spot	markets	are	unpredictable	and	can	be,	and	from	time	to	time	have	been,	volatile.	The	results	of	operations	of	AES's	competitive	supply	business are	also	more	sensitive	to	the	impact	of	market	fluctuations	in	the	price	of	electricity,	natural	gas,	coal	and	other	raw	materials,	and	these	businesses	also	have	higher needs	for	credit	support	of	their	operations.

# Large	Utilities

AES's	large	utility	business	is	comprised	of	three	utilities	located	in	three	countries:	the	U.S.	(IPALCO	Enterprises,	Inc.	("IPALCO")),	Brazil	(Eletropaulo	Metropolitana Electricidade	de	Sao	Paulo	S.A.	("Eletropaulo"))	and	Venezuela	(C.A.	La	Electricidad	de	Caracas	("EDC")).	AES's	equity	interest	in	each	of	these	utilities	is	over	70%. All	of	these	utilities	are	significant	in	size,	and	all	maintain	a	monopoly	franchise	within	a	defined	service	area.	In	most	cases	large	utilities	combine	generation, transmission	and	distribution	capabilities.	Large	utilities	are	subject	to	extensive	local,	state	and	national	regulation	relating	to	ownership,	marketing,	delivery	and pricing	of	electricity	and	gas,	with	a	focus	on	protecting	customers.	Large	utility	revenues	result	primarily	from	electricity	sales	to	customers	under	regulated	tariff	or concession	agreements	and	to	a	lesser	extent	from	contractual	agreements	of	varying	lengths	and	provisions.	The	results	of	operations	of	AES's	large	utility	businesses are	sensitive	to	changes	in	economic	growth,	abnormal	weather	conditions	affecting	their	market	and	regulatory	changes.

# Growth	Distribution

AES's	growth	distribution	line	of	business	includes	distribution	facilities	located	in	developing	countries	or	regions	where	the	demand	for	electricity	is	expected	to	grow at	a	higher	rate	than	in	more	developed	parts	of	the	world.	However,	these	businesses	face	particular	challenges	associated	with	their	presence	in	developing	countries such	as	outdated	equipment,	significant	theft-related	losses,	cultural	problems	associated	with	safety	and	non-payment,	emerging	economies	and	potentially	less	stable governments	or	regulatory	regimes.	Often,	however,	the	conditions	of	the	business	environment	in	a	developing	nation	also	provide	for	significant	opportunities	to implement	operating	improvements	that	may	stimulate	growth	in	earnings	and	cash	flow	performance	at	rates	greater	than	those	typically	achievable	in	AES's	other business	segments.	Distribution	facilities	in	this	line	of	business	may	include	integrated	generation,	transmission,	distribution	or	related	services	companies.	The	results

of	operations	of	AES's	growth	distribution	business	are	sensitive	to	changes	in	economic	growth,	abnormal	weather	conditions	affecting	their	market	and	regulatory changes,	as	well	as	the	success	of	the	operational	changes	implemented.

# Strategic	Initiatives

In	2002,	the	company	changed	certain	senior	management	positions,	including	the	Chief	Executive	Officer	position.	These	changes	were	accompanied	by	a	shift	in management	philosophy	to	a	more	centralized	organizational	structure	in	certain	functional	areas.

# Refinancing

In	December	2002,	AES	completed	a	$2.1	billion	refinancing	of	certain	bank	loans	and	debt	securities	by	entering	into	new	$1.6	billion	senior	secured	credit	facilities and	completing	an	exchange	offer	relating	to	$500	million	of	outstanding	debt	securities.	The	refinancing	substantially	eliminates	all	scheduled	parent	debt	maturities until	November	2004.	The	$1.6	billion	senior	secured	credit	facilities	are	comprised	of	a	$350	million	senior	secured	revolving	credit	facility,	three	tranches	of	term	loan facilities	totaling	approximately	$1.2	billion	and	a	£52.25	million	letter	of	credit.	In	the	exchange	offer	the	Company	issued	approximately	$258	million	aggregate principal	amount	of	its	10%	senior	secured	notes	with	certain	mandatory	redemption	provisions.	The	senior	secured	credit	facilities	and	the	senior	secured	notes	are scheduled	to	mature	in	the	second	half	of	2005.	On	March	14,	2003,	the	Company	launched	a	consent	solicitation	seeking	to	change	the	definition	of	"Material Subsidiary"	and	amend	certain	other	provisions	of	its	outstanding	senior	and	senior	subordinated	notes	to	conform	those	provisions	to	the	provisions	in	its	10%	senior secured	notes.	We	cannot	assure	you	that	the	consent	solicitation	will	be	successful.

# Asset	Sales

AES	has	announced	a	number	of	strategic	initiatives	designed	to	decrease	its	dependence	on	access	to	the	capital	markets,	strengthen	its	balance	sheet,	reduce	the financial	leverage	at	the	parent	company	and	improve	short-term	liquidity.	One	of	these	initiatives	involves	the	sale	of	all	or	part	of	certain	of	the	Company's subsidiaries.	During	2002,	the	Company	announced	agreements	to	sell	AES	NewEnergy,	CILCORP,	Inc.	("CILCORP"),	AES	Mt.	Stuart,	and	AES	Ecogen	for	net equity	proceeds	of	approximately	$819	million.	The	NewEnergy	transaction	closed	in	September	2002,	CILCORP	and	AES	Mt.	Stuart	closed	in	January	2003	and	AES Ecogen	closed	in	February	2003.	Additionally,	the	Company	has	reached	agreements	to	sell	100%	of	Songas	Limited	and	AES	Kelvin	(Pty.)	Ltd,	two	generation businesses	in	Africa,	for	net	equity	proceeds	of	approximately	$116	million.	These	transactions	are	expected	to	close	in	early	to	mid-2003.	In	January	2003,	the	Company announced	the	sale	of	Mountainview	for	$30	million	with	another	$20	million	payment	contingent	on	the	achievement	of	project	specific	milestones.	This	transaction closed	in	March	2003.	Additionally,	the	Company	announced	in	March	2003,	agreements	to	sell	100%	of	its	ownership	interest	in	two	generation	businesses	in Bangladesh	(AES	Haripur	Private	Limited	("Haripur")	and	AES	Meghnaghat	Limited	("Meghnaghat"))	and	32%	of	its	ownership	interest	in	AES	Oasis	Limited	("AES Oasis"),	which	includes	two	electric	generation	development	projects	and	desalination	plants	in	Oman	and	Qatar	(AES	Barka	and	AES	Ras	Laffan,	respectively),	and	the oil-fired	generating	facilities,	AES	LalPir	and	AES	PakGen	in	Pakistan.	Proceeds	from	the	sales	of	Haripur	and	Meghnaghat	are	expected	to	be	approximately $127	million	in	cash	plus	assumption	of	debt,	subject	to	certain	closing	adjustments.	Cash	proceeds	from	the	sale	of	the	minority	interest	in	AES	Oasis	will	be approximately	$150	million.	Completion	of	this	sale	is	subject	to	certain	conditions,	including	government	and	lender	approvals.	The	Company	continues	to	evaluate which	additional	businesses	it	may	sell.	However,	there	can	be	no	guarantee	that	the	proceeds	from	such	sales	transactions	will	cover	the	entire	investment	in	such subsidiaries.	Additionally,	depending	on	which	businesses	are	eventually	sold,	the	entire	or	partial	sale	of	any	subsidiaries	may	change	the	current	financial characteristics	of	the	Company's	portfolio	and	results	of	operations,	and	in	the	future	may	impact	the	amount	of	recurring	earnings	and	cash	flows	the	Company	would expect	to	achieve.

# Cost	Cutting

In	early	2002,	the	Company	initiated	a	corporate-wide	effort	to	more	closely	focus	on	cost	reduction	and	revenue	enhancement	opportunities,	and	also	to	better	capture the	benefits	of	scale	in	the	procurement	of	services	and	supplies.	The	Company	expects	to	realize	cost	cutting	benefits	in	both	earnings	and	cash	flows;	however,	there can	be	no	assurance	that	the	Cost	Cutting	Office	will	be	successful	in	achieving	these	savings.	The	inability	of	the	Company	to	achieve	cost	reductions	and	revenue enhancements	may	result	in	less	than	expected	earnings	and	cash	flows	in	2003	and	beyond.	In	addition,	the	shift	to	a	more	centralized	organizational	structure	has	led, and	will	continue	to	lead,	to	an	expansion	in	the	number	of	people	performing	certain	financial	and	control	functions,	and	will	likely	result	in	an	increase	in	the Company's	selling,	general	and	administrative	expense.

# Restructuring

In	July	2002	the	Company	established	a	Restructuring	Office	formerly	referred	to	as	the	Turnaround	Office,	to	focus	on	improving	the	operating	and	financial performance	of,	selling	or	abandoning	certain	of	its	underperforming	businesses.	Businesses	are	considered	to	be	underperforming	if	they	do	not	meet	the	Company's internal	rate	of	return	criteria,	among	other	factors.	The	Restructuring	Office	is	actively	managing	AES	Drax	Power	Limited	("Drax"),	AES	Barry	Limited	("Barry"), AES	Gener	S.A.	("Gener"),	the	Company's	businesses	within	the	Dominican	Republic	and	the	Company's	Argentine	businesses,	as	well	as	evaluating	AES	Sul Distribuidora	Gaucha	de	Energia	S.A.l	("Sul"),	AES	Uruguaiana	Empreedimentos	Ltda.	("Uruguaiana"),	JSC	AES	Telasi	("Telasi"),	Eletropaulo,	Compagnia	Energetica de	Minas	Gerais	("CEMIG")	and	certain	development	projects.	The	Company	is	evaluating	whether	the	profitability	and	cash	flows	of	such	businesses	can	be

sufficiently	improved	to	achieve	acceptable	returns	on	the	Company's	investment,	or	whether	such	businesses	should	be	disposed	of	or	sold.	If	the	Company	determines that	certain	businesses	are	to	be	sold	or	otherwise	disposed	of,	there	can	be	no	guarantee	that	the	proceeds	from	such	transactions	would	cover	the	Company's	entire investment	in	such	subsidiaries	or	that	such	proceeds	will	be	available	to	the	Company.	It	is	possible	that	the	restructuring	efforts	will	change	the	ownership	structure	or the	manner	in	which	a	business	operates,	and	these	efforts	may	result	in	an	impairment	charge	if	the	Company	is	not	able	to	recover	its	investment	in	such	business.	In 2002	the	Company	took	after-tax	charges	of	approximately	$465	million	on	investments	in	certain	development	projects,	$301	million	on	businesses	classified	as discontinued	operations,	and	$2.3	billion	of	asset	impairment	charges	at	Drax,	Barry,	Eletropaulo	and	CEMIG.	The	inability	of	the	Company	to	successfully	restructure the	underperforming	businesses	may	result	in	less	earnings	and	cash	flows	in	2003	and	beyond.

# Charges	related	to	dispositions

Most	of	the	strategic	initiatives	described	above	involve	potential	sales	or	other	dispositions	of	businesses	by	AES.	Some	of	these	sales	or	dispositions	may	result	in	AES recognizing	losses	related	to	asset	write-downs	and	impairments,	and	severance	and	employee	benefits.	Additionally,	depending	on	which	businesses	are	eventually	sold, the	entire	or	partial	sale	of	any	subsidiary	may	change	the	current	financial	characteristics	of	the	Company's	portfolio	and	results	of	operations,	and	may	impact	the future	amount	of	recurring	earnings	and	cash	flows	the	Company	would	expect	to	achieve.

# Cautionary	Statements	and	Risk	Factors

The	Company	wishes	to	caution	readers	that	the	following	important	factors,	among	others,	indicate	areas	affecting	the	Company,	which	involve	risk	and	uncertainty. These	factors	should	be	considered	when	reviewing	the	Company's	business,	and	are	relied	upon	by	AES	in	issuing	any	forward-looking	statements.	Such	factors	could affect	AES's	actual	results	and	cause	such	results	to	differ	materially	from	those	expressed	in	any	forward-looking	statements	made	by,	or	on	behalf	of,	AES.	Some	or	all of	these	factors	may	apply	to	the	Company's	businesses	as	currently	maintained	or	to	be	maintained.

•The	inability	to	raise	capital	on	favorable	terms,	to	refinance	existing	corporate	or	subsidiary	indebtedness	or	to	fund	operations,	future	acquisitions, construction	of	new	plants	(known	as	"greenfield	development")	and	other	capital	commitments,	particularly	during	times	of	uncertainty	in	the	capital markets	and	in	those	areas	of	the	world	where	the	capital	and	bank	markets	are	underdeveloped.

•Successful	and	timely	completion	of	pending	and	future	asset	sales.

•Changes	in	operation	and	availability	of	the	Company's	generating	plants	(including	wholly	and	partially	owned	facilities)	compared	to	the	Company's historical	performance;	changes	in	the	Company's	historical	operating	cost	structure,	including	but	not	limited	to	those	costs	associated	with	fuel, operations,	supplies,	raw	materials,	maintenance	and	repair,	people,	environmental	compliance,	including	the	costs	of	required	emission	offsets,	purchase and	transmission	of	electricity	and	insurance;	changes	in	the	availability	of	fuel,	supplies,	raw	materials,	emission	offsets,	transmission	access	and insurance;	changes	or	increases	in	planned	or	unplanned	capital	expenditures	or	other	maintenance	activities,	including	but	not	limited	to	expenditures relating	to	environmental	emission	equipment,	changes	in	law	or	regulation,	sudden	mechanical	failure,	or	acts	of	God.

•Failure	by	the	Company	to	achieve	significant	operating	improvements	and	cost	reductions	in	its	distribution	businesses;	changes	in	cost	structure	of	its distribution	businesses,	including	unexpected	increases	in	planned	or	unplanned	capital	expenditures	or	other	maintenance	activities;	inability	to	predict, influence	or	respond	appropriately	to	changes	in	law	or	regulatory	schemes.

•Inability	to	obtain	expected	or	contracted	changes	in	electricity	tariff	rates	or	tariff	adjustments	for	increased	expenses,	changes	in	the	underlying	foreign currency	exchange	rates	or	unexpected	changes	in	those	rates	or	adjustments;	the	ability	or	inability	of	AES	to	obtain,	or	hedge	against	movements	in	an economical	manner	of	foreign	currency;	foreign	currency	exchange	rates	and	fluctuations	in	those	rates;	local	inflation	and	monetary	fluctuations;	import and	other	charges	or	taxes;	conditions	or	restrictions	impairing	repatriation	of	earnings	or	other	cash	flow;	the	economic,	political	and	military	conditions affecting	property	damage,	interruption	of	business	and	expropriation	risks;	changes	in	trade,	monetary	and	fiscal	policies,	laws	and	regulations; unwillingness	of	governments	to	honor	contracts	or	other	activities	of	governments,	agencies,	government-owned	entities	and	similar	organizations; development	progress	and	other	social	and	economic	conditions;	inability	to	obtain	access	to	fair	and	equitable	political,	regulatory,	administrative	and legal	systems,	enforcement	of	judgments	or	a	just	result;	nationalizations	and	unstable	governments	and	legal	systems,	and	intergovernmental	disputes; inability	to	protect	the	Company's	rights	and	assets	due	to	dysfunctional,	corrupt	or	ineffective	administrative	or	legal	systems.

•In	certain	jurisdictions	where	the	Company's	electricity	tariffs	are	subject	to	regulatory	review	or	approval,	changes	in	the	application	or	interpretation	of regulatory	provisions	including,	but	not	limited	to,	changes	in	the	determination,	definition	or	classification	of	costs	to	be	included	as	reimbursable	or pass-through	costs,	changes	in	the	definition	or	determination	of	controllable	or	non-controllable	costs,	changes	in	the	definition	of	events	which	may	or may	not	qualify	as	changes	in	economic	equilibrium,	changes	in	the	timing	of	tariff	increases	or	other	changes	in	the	regulatory	determinations	under	the relevant	concessions;	changes	in	state	or	federal	regulatory	provisions;	inability	to	obtain	redress	from	regulatory	authorities;	unwillingness	of	regulatory bodies	to	take	required	actions,	retrenchment	or	delay	in	taking	action.

•Changes	in	the	amount	of,	and	rate	of	growth	in,	AES's	selling,	general	and	administrative	expenses;	the	impact	of	AES's	ongoing	evaluation	of	its development	costs,	business	strategies

and	asset	valuations,	including,	but	not	limited	to,	the	effect	of	a	failure	to	successfully	complete	certain	acquisition,	construction	or	development projects.

•Legislation	intended	to	promote	competition	in	U.S.	and	non-U.S.	electricity	markets,	including	the	effects	of	such	legislation	upon	existing	contracts, such	as:	(i)	The	NewEnergy	Trading	Arrangements	("NETA")	in	England	and	Wales	(see	also	the	description	under	Foreign	Regulatory	Environment	for related	matters);	(ii)	legislation	currently	receiving	serious	consideration	in	the	United	States	Congress	to	repeal	(a)	the	Public	Utility	Regulatory	Policies Act	of	1978,	as	amended,	or	at	least	to	repeal	the	obligation	of	utilities	to	purchase	electricity	from	qualifying	facilities,	and	(b)	the	Public	Utility	Holding Company	Act	of	1935,	as	amended;	(iii)	changes	in	regulatory	rule-making	by	the	U.S.	Securities	and	Exchange	Commission,	the	U.S.	Federal	Energy Regulatory	Commission	or	other	regulatory	bodies;	(iv)	changes	in	energy	taxes;	(v)	new	legislative	or	regulatory	initiatives	in	U.S.	and	non-U.S. countries;	and	(vi)	changes	in	national,	state	or	local	energy,	environmental,	safety,	tax	and	other	laws	and	regulations	applicable	to	the	Company	or	its operations.

•A	reversal	or	continued	slowdown	of	the	trend	toward	electricity	industry	deregulation	in	the	various	markets	in	which	the	Company	is	conducting	or	is seeking	to	conduct	business.

•The	failure	by	any	significant	customer	of	the	Company	or	any	of	its	subsidiaries	to	fulfill	its	contractual	payment	obligations	presently	or	in	the	future, either	because	such	customer	is	financially	unable	to	fulfill	such	contractual	obligation	or	otherwise	refuses	to	do	so.

•Successful	and	timely	completion	of	(i)	the	respective	construction	of	each	of	the	Company's	electric	generating	projects	now	under	construction	and those	projects	yet	to	begin	construction,	(ii)	capital	improvements	to	existing	facilities,	and	(iii)	the	favorable	resolution	of	pending	or	potential	disputes regarding	the	construction	of	the	Company's	projects.

•Successful	and	timely	completion	of	pending	and	future	acquisitions;	conducting	appropriate	due	diligence;	and	accurate	assumptions	regarding	the performance	of	countries,	markets,	and	models.

•The	effects	of	a	fluctuating	dollar	against	foreign	currencies;	the	lack	of	portability	of	products	and	services	produced	by	the	company's	power	plants	and distribution	companies	beyond	the	local	markets	where	such	products	or	services	are	produced;	failure	by	the	Company	to	include	dollar	indexation	and other	protective	provisions	in	contracts	or	through	third	party	hedging	mechanisms,	or	the	refusal	of	contracting	parties	to	abide	by	such	provisions	when included.

•The	effects	of	a	worldwide	depression,	recession	or	economic	downturn;	prolonged	economic	crisis	in	countries,	states	or	regions	where	the	Company conducts,	or	is	seeking	to	conduct,	its	business;	political,	economic	and	market	instability	related	to	or	resulting	from	economic	crisis	and	the	related collateral	effects,	including,	but	not	limited	to,	riots,	looting,	destruction	of	property,	terrorism	and	civil	war.

•Changes	and	volatility	in	inflation,	fuel,	electricity	and	other	commodity	prices	in	U.S.	and	non-U.S.	markets;	conditions	in	financial	markets,	including fluctuations	in	interest	rates	and	the	availability	of	capital;	temporary	or	prolonged	over/under	supply	in	key	markets	and	changes	in	the	economic	and electricity	consumption	growth	rates	in	the	United	States	and	non-U.S.	countries.

•Adverse	weather	conditions	and	the	specific	needs	of	each	plant	to	perform	unanticipated	facility	maintenance	or	repairs	or	outages	(including	annual	or multi-year),	or	to	install	pollution	control	equipment	or	other	environmental	emission	equipment.

•The	costs	and	other	effects	of	legal	and	administrative	cases,	arbitrations	or	proceedings,	settlements	and	investigations,	claims	(including	insurance claims	for	losses	suffered),

environmental	remediations	and	changes	in	those	items,	developments	or	assertions	by	or	against	AES;	the	effect	of	new,	or	changes	in,	accounting policies	and	practices	and	the	application	of	such	policies	and	practices.

•Changes	or	increases	in	taxes	on	property,	plant,	equipment,	emissions,	gross	receipts,	income	or	other	aspects	of	the	Company's	business	or	operations; investigation	or	reversal	of	the	Company's	tax	positions	by	the	IRS.

•The	failure	of	any	significant	manufacturer	of	parts	for	facilities	of	the	Company's	subsidiaries	or	any	significant	provider	of	construction	services	to	the Company's	subsidiaries	to	fulfill	its	contractual	obligations	presently	or	in	the	future,	either	because	such	manufacturer	or	service	provider	is	financially unable	to	fulfill	such	obligations	or	otherwise	refuses	to	do	so.

# Description	of	Business	Segments

The	Company	operates	in	four	business	segments:	contract	generation,	competitive	supply,	large	utilities	and	growth	distribution.	See	Note	19	to	the	Consolidated Financial	Statements	included	in	Item	8	herein	for	financial	information	about	those	segments	as	well	as	information	about	foreign	and	domestic	operations.

AES's	contract	generation	line	of	business	consists	of	multiple	power	generation	facilities	located	around	the	world.	Provided	that	the	counterparty's	credit	remains viable,	these	facilities	have	contractually	limited	their	exposure	to	commodity	price	risks,	primarily	electricity	prices.	These	facilities	generally	limit	their	exposure	to electricity	price	volatility	by	entering	into	long-term	(five	years	or	longer)	power	purchase	agreements	for	75%	or	more	of	their	output	capacity.	Because	they	have contracted	for	a	majority	of	their	anticipated	output,	they	are	able	to	project	their	fuel	supply	requirements	and	also,	generally,	enter	into	long-term	agreements	for	most of	their	fuel	(coal,	natural	gas	or	fuel	oil	or	other	similar	fuel)	supply	requirements,	thereby	also	limiting	their	exposure	to	fuel	price	volatility.	Through	these	contractual agreements,	the	businesses	generally	increase	the	predictability	of	their	cash	flows	and	earnings.	In	order	to	meet	AES's	definition	of	its	contract	generation	segment, long-term	power	purchase	agreements	must	have	minimum	initial	durations	of	five	years	or	longer	and	are	typically	entered	into	with	one	major	customer,	but	may	also be	with	a	series	of	unrelated	customers.	In	addition,	AES	may	enter	into	tolling	or	"pass	through"	arrangements	whereby	the	counterparty	directly	assumes	the	risks associated	with	providing	the	necessary	fuel	and	markets	the	resulting	power	output	generated.	However,	not	all	businesses	within	AES's	contract	generation	line	of business	have	the	same	degree	of	contractually	limited	exposure,	and	therefore,	the	degree	of	predictability	may	vary	from	business	to	business.

A	significant	portion	of	AES's	contract	generating	business	is	comprised	of	agreements	whereby	a	single	customer	contracts	for	the	majority,	if	not	all,	of	the	power generated	by	a	particular	facility.	The	prolonged	failure	of	any	significant	customer	to	fulfill	its	contractual	payment	obligations	in	the	future	could	have	a	substantial negative	impact	on	AES's	results	of	operations	and	financial	condition.	AES	has	sought	to	reduce	this	risk,	where	possible,	by	contracting	with	customers	who	have	their debt	or	preferred	securities	rated	"investment	grade,"	or	by	obtaining	sovereign	government	guarantees	of	the	customer's	obligations.	However,	AES	does	not	limit	its business	solely	to	developed	countries	or	economies,	nor	even	to	those	countries	with	investment	grade	sovereign	credit	ratings.	In	certain	locations,	particularly	in 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	all	of	their	contractual	payment	obligations.	Moreover,	collection	of	receivables	may	be	hindered	in	some	countries	due	to	ineffective systems	for	adjudicating	contract	disputes.	In	order	to	minimize	the	risk	of	contract	abrogation,	AES	takes	steps	to	maintain	flexibility

with	its	customers.	In	many	instances,	AES	is	able	to	avoid	contract	abrogation	by	creatively	restructuring	contracts	without	disadvantaging	itself.	In	situations	in	which this	is	not	possible,	AES	diligently	pursues	resolution	through	litigation	or	contractually	prescribed	arbitration.	AES	believes	that	locating	its	plants	in	different geographic	areas	helps	to	mitigate	the	effects	of	regional	economic	downturns,	thereby	mitigating	a	portion	of	the	risks	imposed	by	operating	in	less	developed countries.

Certain	of	the	Company's	contract	generation	customers	are	regulated	utilities	that	are	regulated	by	state	or	local	public	utility	commissions	("PUCs").	PUCs	often restrict	the	amount	of	debt	certain	utilities	are	permitted	to	incur,	as	well	as	the	types	of	business	activities	in	which	they	participate.	Two	of	these	types	of	customers,	at the	Company's	Warrior	Run	and	Beaver	Valley	plants,	are	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.

Certain	subsidiaries	and	affiliates	of	the	Company	(domestic	and	non-U.S.)	are	in	various	stages	of	developing	and	constructing	greenfield	power	plants,	some	but	not all	of	which	have	signed	long-term	contracts	or	made	similar	arrangements	for	the	sale	of	electricity.	Successful	completion	depends	upon	overcoming	substantial	risks, including,	but	not	limited	to,	risks	relating	to	failures	of	siting,	financing,	construction,	permitting,	governmental	approvals	or	the	potential	for	termination	of	the	power sales	contract	as	a	result	of	a	failure	to	meet	certain	milestones.	As	of	December	31,	2002,	capitalized	costs	for	projects	under	development	and	in	early	stage construction	were	approximately	$15	million	and	capitalized	costs	for	projects	under	construction	were	approximately	$3.2	billion.	The	Company	believes	that	these costs	are	recoverable;	however,	no	assurance	can	be	given	that	individual	projects	will	be	completed	and	reach	commercial	operation.

AES's	competitive	supply	line	of	business	consists	of	generating	facilities	that	sell	electricity	directly	to	wholesale	customers	in	competitive	markets.	Additionally,	as compared	to	the	contract	generation	segment	discussed	above,	these	generating	facilities	generally	sell	less	than	75%	of	their	output	pursuant	to	long-term	contracts	with pre-determined	pricing	provisions	and/or	sell	into	power	pools,	under	shorter-term	contracts	or	into	daily	spot	markets.

In	managing	supply	and	price	risk,	all	options	for	supply	are	actively	considered,	including	(i)	utilizing	the	output	from	AES-owned	generating	assets,	(ii)	building	or acquiring	additional	generating	assets	and	(iii)	buying	electricity	from	other	generators	or	marketers.	AES	permits	its	wholesale	and	retail	businesses	to	operate independently	but	may	choose	to	integrate	businesses	in	certain	instances	where	it	is	economically	advantageous	to	AES	to	do	so.	The	prices	paid	for	electricity	under short-term	contracts	and	in	the	spot	markets	are	unpredictable	and	can	be,	and	from	time	to	time	have	been,	volatile.	This	volatility	is	influenced	by	peak	demand requirements,	weather	conditions,	competition,	market	regulation,	interest	rate	and	foreign	exchange	rate	fluctuations,	electricity	transmission	and	environmental emission	constraints,	the	availability	or	prices	of	emission	credits	and	fuel	prices,	as	well	as	plant	availability	and	other	relevant	factors.	In	addition	to	exposure	to	the risks	associated	with	market	movement,	the	competitive	supply	business	is	also	exposed	to	credit	risk	either	because	such	business	may	be	required	to	establish sufficient	credit	to	support	its	operations,	or	because	of	the	potential	nonperformance	of	contractual	obligations	by	a	counterparty.	AES	maintains	credit	policies

with	regard	to	its	counterparties;	however,	there	can	be	no	assurance	that	these	parties	will	ultimately	be	able	to	pay	when	called	to	do	so.	The	absence	of	long-term contracts	can	also	result	in	uncertainty	relating	to	future	production	volumes,	which	in	turn	causes	uncertainty	with	respect	to	the	volume	of	fuel	to	be	consumed	to support	such	production.	As	a	result,	the	competitive	supply	business	may	also	be	exposed	to	volume	risk	in	connection	with	its	purchase	of	natural	gas,	coal	and	other raw	materials.	In	the	U.S.,	AES	hedges	certain	aspects	of	its	"net	open"	positions.	AES	has	used	a	hedging	strategy,	where	appropriate,	to	hedge	its	financial performance	against	the	effects	of	fluctuations	in	energy	commodity	prices.	The	implementation	of	this	strategy	involves	the	use	of	commodity	forward	contracts, futures,	swaps	and	options.

During	the	third	quarter	of	2002,	AES	completed	the	sale	of	100%	of	its	ownership	interest	in	AES	NewEnergy	to	Constellation	Energy	Group.	AES	NewEnergy	was previously	reported	in	the	competitive	supply	segment.

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	AES	Wolf	Hollow,	L.P.'s	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.

AES's	large	utility	business	is	comprised	of	three	utilities	located	in	the	U.S.	(IPALCO),	Brazil	(Eletropaulo)	and	Venezuela	(EDC).	AES's	equity	interest	in	each	of these	utilities	is	over	70%.	In	January	2003,	AES	sold	100%	of	its	ownership	interest	in	a	fourth	utility,	CILCORP,	a	utility	holding	company	whose	largest	subsidiary	is Central	Illinois	Light	Company	("CILCO"),	to	Ameren	Corporation.	The	sale	of	CILCORP	by	AES	was	required	under	the	U.S.	Public	Utility	Holding	Company	Act (PUHCA)	when	AES	purchased	IPALCO,	a	regulated	utility	in	Indianapolis,	Indiana	in	March	2001.	CILCORP	was	previously	reported	in	the	large	utilities	segment.	In February	2002,	AES	also	exchanged	a	minority	interest	in	a	fifth	utility,	Light	Servicos	de	Eletricidade	S.A.	("Light"),	for	an	additional	ownership	interest	in Eletropaulo.	All	of	these	utilities	are	of	significant	size	and	all	maintain	a	monopoly	franchise	within	a	defined	service	area.	In	most	cases	large	utilities	combine generation,	transmission	and	distribution	capabilities.	Large	utilities	are	subject	to	extensive	local,	state	and	national	regulation	relating	to	ownership,	marketing, delivery	and	pricing	of	electricity	and	gas	with	a	focus	on	protecting	customers.	AES's	large	utilities,	including	IPALCO	(3,431	MW)	and	EDC	(2,616	MW),	aggregate 6,047	gross	MW	of	generation	capacity	and	serve	over	1.6	million	customers	with	annual	sales	of	nearly	27,000	gigawatt	hours.	Large	utility	revenues	result	primarily from	electricity	sales	to	customers	under	regulated	tariff	or	concession	agreements	and	to	a	lesser	extent	from	contractual	agreements	of	varying	lengths	and	provisions.

IPALCO	is	a	holding	company	and	its	principal	subsidiary	is	Indianapolis	Power	&	Light	Company	("IPL").	IPL	is	engaged	in	generating,	transmitting,	distributing	and selling	electric	energy	in	the	City	of	Indianapolis	and	neighboring	cities,	towns	and	communities,	and	adjacent	rural	areas,	all	within	the	state	of	Indiana.	IPL	owns	and operates	two	primarily	coal-fired	generating	plants	and	a	separately-sited	combustion	turbine	that	are	used	for	electric	generation.	IPL	also	operates	one	coal	and	gas- fired	plant.	For	electric	generation,	the	total	demonstrated	net	winter	capability	is	3,342	MW	and	net	summer	capability	is	3,224	MW.

Eletropaulo	has	served	the	São	Paulo	area	for	over	100	years	and	is	the	largest	electricity	distribution	company	in	Latin	America	in	terms	of	revenues.	Eletropaulo's concession	contract	with	the	Brazilian	National	Electric	Energy	Agency	("ANEEL"),	the	government	agency	responsible	for	regulating	the	Brazilian	electric	industry, entitles	Eletropaulo	to	distribute	electricity	in	its	service	area	for	30	years.	Eletropaulo's	service	territory	consists	of	24	municipalities	in	the	greater	São	Paulo metropolitan	area	and	adjacent	regions	and	accounts	for	about	15%	of	Brazil's	GDP,	covering	5.0	million	customers	or	about	44%	of	the	population	in	the	State	of	São Paulo,	Brazil.	On	February	6,	2002,	AES	exchanged	its	interest	in	Light	for	an	additional	31%	equity	interest	in	Eletropaulo.

EDC	was	founded	in	1895	and	is	the	largest	private-sector	electric	utility	in	Venezuela	serving	approximately	1.2	million	customers	(approximately	20%	of	the Venezuelan	population).	EDC	generates,	transmits	and	distributes	electricity	primarily	to	metropolitan	Caracas	and	its	surrounding	area.	EDC's	distribution	area	covers 5,176	square	kilometers.	EDC	has	an	installed	generating	capacity	of	2,616	MW.

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	(which	was approximately	$900	million	at	December	31,	2002).	The	sale	of	CILCORP	closed	on	January	31,	2003.	The	transaction	also	included	an	agreement	to	sell	AES	Medina Valley	Cogen	("Medina	Valley"),	a	gas-fired	cogeneration	facility	located	in	CILCO's	service	territory,	which	closed	on	February	4,	2003.	The	sales	of	CILCORP	and Medina	Valley	generated	net	proceeds	(after	expenses)	of	approximately	$500	million,	which	are	subject	to	certain	adjustments.	The	sale	of	CILCORP	by	AES	was required	under	PUHCA	when	AES	purchased	IPALCO	in	March	2001.	CILCORP	was	previously	reported	in	the	large	utilities	segment.

AES	believes	it	is	important	to	manage	the	regulatory	frameworks	of	its	large	utilities,	which	are	becoming	increasingly	competitive.	As	regulated	entities,	each	large

utility	is	subject	to	extensive	local,	state	and	national	regulation	relating	to	ownership,	marketing,	delivery	and	pricing	of	electricity	and	gas	with	a	focus	on	protecting customers.	Regulatory	approval	must	generally	be	sought	for	the	purchase,	acquisition,	sale	or	disposal	of	these	businesses.	In	some	instances,	the	approval	process	can broadly	affect	all	of	AES's	public	utility	holdings.	For	example,	as	mentioned	above,	the	provisions	of	the	regulatory	approval	for	AES's	acquisition	of	IPALCO	required AES	to	relinquish	control	or	dispose	of	a	portion	of	its	regulated	assets	or	businesses	in	the	United	States,	in	particular	certain	transmission	and	distribution	assets owned	by	CILCO,	a	subsidiary	of	CILCORP,	within	two	years.

AES's	growth	distribution	line	of	business	includes	distribution	facilities	located	in	developing	countries	where	the	demand	for	electricity	is	expected	to	grow	at	a	higher rate	than	in	more	developed	parts	of	the	world.	However,	these	businesses	face	particular	challenges	associated	with	their	presence	in	developing	countries	such	as outdated	equipment,	significant	theft-related	losses,	cultural	problems	associated	with	safety	and	non-payment,	emerging	economies,	and	potentially	less	stable governments	or	regulatory	regimes.	Often,	however,	the	conditions	of	the	business	environment	in	a	developing	nation	also	provide	for	significant	opportunities	to implement	operating	improvements	that	may	stimulate	growth	in	earnings	and	cash	flow	performance	at	rates	greater	than	those	typically	achievable	in	AES's	other business	segments.	Distribution	facilities	included	in	this	line	of	business	may	include	generation,	transmission,	distribution	or	related	services	companies.	The	results	of operations	of	AES's	growth	distribution	business	are	sensitive	to	changes	in	economic	growth,	abnormal	weather	conditions	affecting	their	market	and	regulatory changes,	as	well	as	the	success	of	the	operational	changes	implemented.

Growth	distribution	revenues	are	derived	from	the	distribution	and	sale	of	electricity	made	pursuant	to	the	provisions	of	long-term	electricity	sale	concessions	granted	by the	appropriate	governmental	authorities,	or	in	some	locations,	under	existing	regulatory	laws	and	provisions.	One	of	our	distribution	facilities	("SONEL")	is "integrated,"	in	that	it	also	owns	electric	power	plants	for	the	purpose	of	generating	a	portion	of	the	electricity	it	sells.	The	facilities	currently	in	this	line	of	business represent	approximately	850	Gross	MW	of	generation	and	serve	over	4.8	million	customers	with	sales	exceeding	28,000	gigawatt	hours	in	Argentina,	Brazil,	Cameroon, Dominican	Republic,	El	Salvador,	Georgia	and	Ukraine.

# AES	Facilities

The	following	tables	set	forth	information	regarding	the	Company's	facilities	that	are	in	operation	or	under	construction	at	December	31,	2002.	For	a	description	of	risk factors	and	additional	factors	that	may	apply	to	the	Company's	facilities,	see	also	the	information	contained	under	the	caption	"Cautionary	Statements	and	Risk	Factors" in	Item	1	above,	and	Item	7,	"Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations"	herein.

| Generation	Facilities | Dominant	Fuel | Year	of	Acquisition<br>or	Commencement<br>of	Commercial<br>Operations | Geographic<br>Location | Gross	MW | AES	Equity<br>Interest<br>(percent) |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Contract\tGeneration |  |  |  |  |  |  |
| North\tAmerica |  |  |  |  |  |  |
| Kingston | Gas | 1997 | Canada | 110 |  | 50 |
| Beaver\tValley | Coal | 1987 | USA | 125 |  | 100 |
| Thames | Coal | 1990 | USA | 181 |  | 100 |
| Shady\tPoint | Coal | 1991 | USA | 320 |  | 100 |
| Hawaii | Coal | 1992 | USA | 180 |  | 100 |
| Southland-Alamitos | Gas | 1998 | USA | 2,123 |  | 100 |
| Southland-Huntington\tBeach | Gas | 1998 | USA | 430 |  | 100 |
| Southland-Redondo\tBeach | Gas | 1998 | USA | 1,330 |  | 100 |
| Warrior\tRun | Coal | 2000 | USA | 180 |  | 100 |
| Hemphill | Biomass | 2001 | USA | 14 |  | 100 |
| Mendota | Biomass | 2001 | USA | 25 |  | 100 |
| Medina\tValley\t(1) | Gas | 2001 | USA | 47 |  | 100 |
| Ironwood | Gas | 2001 | USA | 705 |  | 100 |
| Red\tOak | Gas | 2002 | USA | 832 |  | 100 |
| South\tAmerica |  |  |  |  |  |  |
| Gener-Termoandes | Gas | 2000 | Argentina | 643 |  | 99 |
| Uruguaiana | Gas | 2000 | Brazil | 600 |  | 100 |
| Tiete\t(10\tplants) | Hydro | 1999 | Brazil | 2,650 |  | 53 |
| GENER-Norgener | Oil | 2000 | Chile | 277 |  | 99 |
| GENER-Centrogener\t(9\tplants) | Hydro | 2000 | Chile | 756 |  | 99 |
| GENER-Electrica\tde\tSantiago | Gas | 2000 | Chile | 379 |  | 89 |
| GENER-Energia\tVerde | Biomass | 2000 | Chile | 39 |  | 99 |
| GENER-Guacolda | Coal | 2000 | Chile | 304 |  | 49 |
| Europe\tand\tAfrica |  |  |  |  |  |  |
| Bohemia | Coal | 2001 | Czech\tRepublic | 50 |  | 100 |
| Elsta | Gas | 1998 | Netherlands | 405 |  | 50 |
| Ebute | Gas | 2001 | Nigeria | 290 |  | 95 |
| Kelvin\t(2) | Coal | 2001 | South\tAfrica | 600 |  | 95 |
| Kilroot | Oil\t&amp;\tCoal | 1992 | UK | 520 |  | 97 |
| Medway | Gas | 1996 | UK | 688 |  | 25 |
| Tisza\tII | Gas | 1996 | Hungary | 860 |  | 100 |

# Contract	Generation	(continued)

| Bayano | Hydro | 1999 | Panama | 236 | 49 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Chiriqui-La\tEstrella | Hydro | 1999 | Panama | 42 | 49 |
| Chiriqui-Los\tValles | Hydro | 1999 | Panama | 48 | 49 |
| Panama | Oil | 1999 | Panama | 42 | 49 |
| Bayano | Hydro | 2003 | Panama | 24 | 49 |
| Esti | Hydro | 2003 | Panama | 120 | 49 |
| Chivor | Hydro | 2000 | Colombia | 1,000 | 99 |
| Colombia\tI | Gas | 2000 | Colombia | 90 | 69 |
| Large\tUtilities |  |  |  |  |  |
| North\tAmerica |  |  |  |  |  |
| CILCORP-Duck\tCreek\t(1) | Coal | 1999 | USA | 366 | 100 |
| CILCORP-Edwards\t(1) | Coal | 1999 | USA | 772 | 100 |
| CILCORP-Indian\tTrails\t(1) | Gas | 1999 | USA | 19 | 100 |
| IPALCO-Georgetown | Oil | 2001 | USA | 79 | 100 |
| IPALCO-Eagle\tValley | Coal | 2001 | USA | 364 | 100 |
| IPALCO-Petersburg | Coal | 2001 | USA | 1,842 | 100 |
| IPALCO-Harding\tStreet | Coal | 2001 | USA | 1,146 | 100 |
| Caribbean |  |  |  |  |  |
| EDC-generation\t(4\tplants) | Gas | 2000 | Venezuela | 2,616 | 87 |
| Growth\tDistribution |  |  |  |  |  |
| Europe/\tAfrica |  |  |  |  |  |
| SONEL | Hydro | 2001 | Cameroon | 850 | 56 |

| Eastern	Kazakhstan	REC | 1999 | Kazakhstan | 291,000 | 1,455 | 0 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Semipalatensk\tREC | 1999 | Kazakhstan | 178,513 | 1,117 | 0 |
| Large\tUtilities |  |  |  |  |  |
| North\tAmerica |  |  |  |  |  |
| IPALCO | 2001 | USA | 449,550 | 16,256 | 100 |
| CILCORP-Electricity\t(1) | 1999 | USA | 193,000 | 6,743 | 100 |
| South\tAmerica |  |  |  |  |  |
| Eletropaulo | 1998 | Brazil | 5,014,300 | 32,451 | 70 |
| Caribbean |  |  |  |  |  |
| EDC-distribution | 2000 | Venezuela | 1,199,805 | 10,726 | 87 |
| Growth\tDistribution |  |  |  |  |  |
| South\tAmerica |  |  |  |  |  |
| Sul | 1997 | Brazil | 975,000 | 7,300 | 98 |
| Eden | 1997 | Argentina | 272,122 | 1,708 | 60 |
| Edes | 1997 | Argentina | 140,823 | 573 | 60 |
| Edelap | 1998 | Argentina | 275,963 | 2,029 | 60 |
| Europe\tand\tAfrica |  |  |  |  |  |
| SONEL | 2001 | Cameroon | 452,000 | 3,020 | 56 |
| Asia |  |  |  |  |  |
| Telasi | 1998 | Georgia | 370,000 | 2,200 | 75 |
| Kievoblenergo | 2001 | Ukraine | 763,000 | 3,840 | 75 |
| Rivnooblenergo | 2001 | Ukraine | 383,000 | 1,700 | 75 |
| Caribbean |  |  |  |  |  |
| CLESA | 1998 | El\tSalvador | 239,449 | 567 | 64 |
| EDE\tEste | 1999 | Dominican\tRepublic | 300,000 | 2,996 | 50 |
| CAESS | 2000 | El\tSalvador | 451,772 | 1,697 | 75 |
| DEUSEM | 2000 | El\tSalvador | 47,108 | 75 | 74 |
| EEO | 2000 | El\tSalvador | 162,496 | 339 | 89 |

(1) At	December	31,	2002,	the	Company	had	entered	into	agreements	to	sell	these	businesses.	The	CILCORP	and	Mt.	Stuart	transactions	closed	in	January	2003. Ecogen	and	Medina	Valley	closed	in	February	2003.

(2) At	December	31,	2002,	the	Company	had	entered	into	agreements	to	sell	these	businesses.	These	transactions	are	expected	to	close	in	the	first	half	of	2003.

(3) In	March	2003,	the	Company	announced	that	it	had	entered	into	agreements	to	sell	all	or	a	portion	of	its	interest	in	these	businesses.

(4) In	January	2003,	the	Company	entered	into	an	agreement	to	sell	this	business.	This	transaction	closed	in	March	2003.

Note:	Some	of	the	Company's	generation	businesses	may	change	between	the	competitive	supply	and	contract	generation	segments	due	to	changes	in	the	amount of	output	contracted.

# United	States	Regulatory	Environment

# General

Over	the	past	decade	the	United	States	implemented	a	series	of	regulatory	policies	that	encourage	competition	in	wholesale	and	retail	electricity	markets.	Such	policies have	been	implemented	both	at	the	federal	level	and	in	many	states,	reflecting	the	federal	structure	of	the	U.S.	system.	Wholesale	power	markets	and	transmission facilities	are	regulated	by	the	federal	government	while	retail	electricity	markets	and	distribution	are	regulated	by	each	of	the	fifty	states.

Beginning	in	the	fall	of	2001	and	continuing	through	2002,	however,	primarily	as	a	result	of	events	in	California	(the	electricity	shortage	and	price	rise	during	the	period from	May	2000	through	June	2001)	and	the	bankruptcy	of	Enron,	previously	the	largest	U.S.	electricity	trading	company,	regulatory	officials	both	in	the	United	States and	abroad	have	begun	to	reexamine	the	nature	and	pace	of	deregulation	of	electricity	markets.	This	reexamination,	however,	just	as	the	movement	toward	deregulation before	it,	has	not	occurred	in	a	uniform	manner	but	rather	differs	from	state	to	state	and	between	the	federal	government	and	the	states	themselves.	Thus,	over	the	last several	years	the	state	of	California	abandoned	the	framework	for	deregulation	that	had	been	adopted	in	1996,	while	the	Federal	Energy	Regulatory	Commission ("FERC")	has	not	indicated	any	inclination	to	roll	back	its	efforts	to	enhance	"open	access"	electric	transmission	and	enhance	competition	in	bulk	power	markets.

Volatility	in	the	wholesale	power	markets	in	California	coupled	with	structural	flaws	inherent	in	the	state's	deregulation	law	that	shifted	the	risk	of	wholesale deregulation	to	the	states'	investor-owned	utilities	led	the	state	government	to	impose	emergency	measures	that	effectively	repealed	California	electric	market restructuring	legislation.	(See	below,	"California	Businesses,"	for	more	information).	While	the	confluence	of	events	that	occurred	in	California	may	not	be	repeated	in other	states	pursuing	restructuring	programs,	to	the	extent	these	other	states	adopt,	or	have	adopted,	policies	similar	to	California's,	particularly	the	use	of	"default"	or regulated	retail	prices	while	wholesale	prices	are	set	by	the	market,	the	problems	experienced	in	California	could	be	repeated	elsewhere.

The	events	in	California	generally	have	caused	state	lawmakers	and	politicians	to	postpone	restructuring	legislation	or	even	to	propose	a	return	to	more	traditional regulated	markets.	A	recent	survey	by	the	Energy	Information	Administration	shows	18	states	(including	the	District	of	Columbia)

are	actively	pursuing	restructuring,	6	states	have	delayed	or	suspended	such	restructuring,	and	27	states	have	no	active	restructuring	plans.	The	Company	believes	the most	likely	outlook	over	the	next	decade	is	for	the	United	States	to	continue	to	resemble	a	"patchwork	quilt"	of	differing	regulatory	policies	at	the	retail	level.	Because AES	has	sold	its	primary	retail	electric	business	in	the	United	States,	the	impact	of	these	differing	retail	policies	on	it	is	expected	to	be	small	in	the	near	term.

The	federal	government,	through	regulations	promulgated	by	the	FERC,	has	primary	jurisdiction	over	wholesale	electricity	markets.	Since	1990,	FERC	has	approved market-based	rates	for	many	providers	of	wholesale	generation,	and	the	mix	of	market	players	has	shifted	dramatically	toward	non-utility	entities,	referred	to	as independent	power	producers	or	wholesale	generators	whose	rates	are	based	on	competitive	conditions	rather	than	on	costs.	The	Electric	Power	Supply	Association reports	that	non-utility	generators	now	account	for	approximately	30	percent	of	U.S.	wholesale	generation.	FERC	has	proposed	new	regulations	to	implement	a "standard	market	design"	for	wholesale	electric	markets	and	may	publish	a	final	rule	in	2003.	This	rule	generally	is	intended	to	further	promote	non-discriminatory,	open access	wholesale	transmission	and	workably	competitive	wholesale	generation	markets.	Some	states	and	members	of	Congress	have	expressed	concerns,	however,	and	it is	uncertain	whether	and	in	what	form	FERC	will	issue	a	final	rule.	Congress	may	seek	to	pass	legislation	affecting	U.S.	electric	markets,	including	possible	repeal	of significant	portions	of	the	Public	Utility	Holding	Company	Act	of	1935	and	the	Public	Utility	Regulatory	Policies	Act	of	1978.

One	major	result	of	creating	competitive	wholesale	electricity	markets	has	been	the	advent	of	marketing	and	trading	companies.	These	entities	buy	and	sell	electricity, creating	an	interface	between	generators	and	retail	customers.	In	December	2001,	the	largest	of	such	marketers/traders,	Enron,	filed	for	bankruptcy.	Several	other companies	subsequently	have	reduced	or	eliminated	their	marketing	and	trading	activities.	These	activities	have	resulted	in	a	less	liquid	wholesale	market,	in	which	AES participates	primarily	as	a	generator.	Due	to	the	Enron	bankruptcy	and	difficulties	of	other	marketing/trading	companies,	stricter	trading	and	credit	requirements	have been	implemented,	which	has	made	wholesale	transactions	more	expensive	for	AES	and	its	competitors.

California	Businesses

During	the	first	half	of	2001,	the	wholesale	electricity	and	natural	gas	markets	in	California	continued	to	exhibit	the	high	price	volatility	that	began	in	May	2000.	The volatility	and	unpredictable	market	dynamics	were	the	result	of	a	confluence	of	factors,	including,	among	other	things,	growing	demand,	a	supply/demand	imbalance	on natural	gas	pipelines	importing	gas	to	California,	regional	electrical	supply	shortages	due	to	weather	conditions,	limited	additions	of	new	generating	capacity	over	the previous	decade,	and	the	cost	and	availability	of	NOx	emissions	credits.	The	situation	was	further	exacerbated	by	credit	concerns	among	market	participants	brought	on by	the	bankruptcies	and	near	bankruptcies	of	the	major	investor-owned	utilities	and	the	California	Power	Exchange.	The	freezing	of	retail	prices	avoided	the	natural reduction	in	overall	demand	that	would	have	been	the	result	of	higher	prices	caused	by	undersupply,	which	left	the	state's	electricity	system	out	of	balance.	In	response	to persistent	high	prices,	the	Federal	Energy	Regulatory	Commission	issued	a	number	of	orders,	most	notably	on	April	26	and	June	19	of	2001,	adopting	a	price	mitigation plan	that	included	price	caps,	obligations	on	generators	to	offer	all	available	capacity	into	the	market,	and	tighter	requirements	on	generators	to	coordinate	their	outage schedules	with	the	California	Independent	System	Operator.	Many	commercial	and	regulatory	issues	existing	at	the	beginning	of	2002	remain	to	be	settled,	the	ultimate resolution	of	which	may	result	in	significant	market	or	regulatory	changes	that	cannot	currently	be	determined	or	predicted.	The	outcome	of	any	such	changes	will	affect market	conditions	for	all	participants,	including	AES.	Among	the	outstanding	commercial	issues	are	the	status	of	certain	payables	owed	to	generators	and	marketers	for power	delivered	during	2000	and	2001.	Although	AES's	overall	exposure	to	this	risk	is	largely	mitigated	as	a	result	of	its	tolling	agreement	related	to	the	Southland plants	(see	description	below),	at	December	31,	2002	the	Company	had	receivables	of	$4	million	relating	to	this	period	from	various	California	entities,	and	is	actively pursuing	recovery	of	these	amounts.	In	addition,	the	State	of

California	is	seeking	refunds	from	certain	entities	that	supplied	power	within	the	state	during	2000	and	2001,	including	AES.	Because	the	pricing	of	the	majority	of power	sold	by	the	Company	during	that	period	was	determined	under	the	tolling	agreement,	the	Company	does	not	anticipate	that	its	exposure	to	such	refunds	will	be material.	Nonetheless,	it	has	been	named	in	a	number	of	proceedings	and	lawsuits	related	to	refunds	and	cannot	be	certain	of	their	outcome.	See	"Legal	Proceedings."

# Foregin	Regulatory	Environment

# 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.

The	new	regulations	in	the	energy	sector	effectively	overturn	the	U.S.	dollar	based	nature	of	the	electricity	sector.	Formerly,	both	the	wholesale	generation	market	and the	distribution	sector	received	payments	that	were	linked	to	the	U.S.	dollar,	not	only	because	of	the	Convertibility	Law	that	pegged	the	peso	at	a	1:1	exchange	rate	with the	U.S.	dollar	but	also	because	the	price	paid	for	wholesale	generation	reflected	the	U.S.	dollar-linked	nature	of	the	fuels	used	by	the	country's	generating	facilities.

In	the	wholesale	power	market,	electricity	generators	declared	on	a	semi-annual	basis	their	costs	of	generation	which	reflected	the	costs	of	their	fuel.	For	thermal generators	these	fuel	costs	reflected	the	U.S.	dollar	costs	of	these	commodities.	Under	the	current	regulations	both	the	declaration	of	costs	and	the	prices	received	as capacity	and	energy	payments	are	denominated	in	pesos	but	are	not	permitted	to	reflect	the	devaluation	of	the	peso	against	the	U.S.	dollar.	As	a	result,	the	fuel	costs	for thermal	generators	no	longer	reflect	the	true	costs	of	producing	or	delivering	that	fuel.	At	the	same	time	generation	prices	now	reflect	an	artificially	low	price	of	fuels and	as	a	result	the	real	price	received	for	wholesale	generation	has	been	reduced	by	nearly	50%	from	the	previous	year.

Under	the	previous	regulations,	distribution	companies	were	granted	long-term	concessions	(up	to	99	years)	which	provided,	directly	or	indirectly,	tariffs	based	upon U.S.	dollars	and	adjusted	by	the	U.S.	consumer	price	index	and	producer	price	index.	Under	the	new	regulations,	tariffs	have	been	delinked	from	the	U.S.	dollar	and	U.S. inflation	indices.	The	tariffs	of	all	distribution	companies	have	been	converted	to	pesos	and	frozen	at	the	peso	notional	rate	as	of	December	31,	2001.

# Brazil

The	Brazilian	electricity	industry	is	regulated	by	ANEEL.	Its	responsibilities	include,	among	others,	(i)	granting	and	supervising	concessions	for	electricity	generation, transmission	and	distribution,	(ii)	establishing	regulations	for	the	electricity	sector,	including	the	approval	of	electricity	tariffs,	(iii)	overseeing	and	auditing	the	activities of	electric	power	concessionaires,	and	(iv)	implementing	and	regulating	the	use	of	electricity,	in	the	form	of	both	thermal	and	hydroelectric	power.

In	order	to	establish	competition	and	to	ensure	short-term	power	supply	to	the	market	in	Brazil	upon	deregulation	of	the	power	industry,	the	Federal	Government	created the	MAE.	The	MAE	was	originally	a	self-regulated	body,	responsible	for	settling	and	clearing	short-term	power	purchases	according	to	the	rules	established	by	the market	participants	(generators	and	distributors)	under	a

collective	agreement,	the	Market	Agreement,	and	to	regulations	issued	by	governing	authorities,	primarily	ANEEL.

The	electricity	industry	in	Brazil	reached	a	critical	point	in	2001,	as	the	result	of	a	series	of	regulatory,	meteorological	and	market-driven	problems.	The	MAE	had	a	poor performance	record	due	to	an	inability	to	resolve	commercial	disputes.	In	addition,	the	combined	effects	of	growth	in	demand,	decreased	rainfall	on	the	country's	heavily hydro-electric	dependent	generating	capacity	and	delays	by	the	Brazilian	energy	regulatory	authorities	in	developing	an	attractive	regulatory	structure	(necessary	to encourage	new	generation	in	the	country)	have	led	to	shortages	of	electricity	to	meet	expected	demand	in	certain	regions	of	Brazil.	As	a	result,	the	Brazilian	government, effective	as	of	June	2001,	implemented	a	program	for	the	rationing	of	electricity	consumption.

Under	these	conditions,	another	issue	arose,	which	is	referred	to	as	Annex	V.	It	is	an	appendix	included	in	all	the	regulated	contracts	established	prior	to	the	privatization of	the	generation	companies	in	Brazil,	which	are	known	as	the	Initial	Contracts.	Under	the	Initial	Contracts,	ANEEL	defined	both	prices	and	volumes,	which	were	then entered	into	between	all	generators	(both	privatized	and	state-owned)	and	distribution	companies.	Annex	V	contains	a	mathematical	formula	that	was	designed	to	reduce the	impact	on	generators	during	times	when	reservoir	levels	are	low	(such	as	those	during	rationing	periods)	and	spot	electricity	prices	are	high.	In	these	situations, Annex	V	decreases	the	generators'	contractual	fixed	volume	obligations.	However,	that	contractual	reduction	is	generally	not	sufficient	to	cover	the	full	extent	of	the actual	reductions	in	energy	available	resulting	from	the	water	shortage	conditions.	As	such,	the	generators	are	required	to	fulfill	the	remaining	portion	of	their	reduced contractual	obligations	to	the	distributors	with	a	calculated	and	financially	settled	payment	under	the	terms	of	Annex	V.	Such	calculated	payment	effectively	provides compensation	to	distributors	for	the	shortfall	in	actual	electricity	delivered	by	generators	and	serves	to	partially	offset	the	reductions	in	operating	income	experienced	by the	distributors	resulting	from	the	implications	of	lower	electricity	demand	under	imposed	rationing	conditions.

In	order	to	restore	the	economic	equilibrium	contained	in	all	of	the	concession	contracts,	an	industry-wide	agreement,	sometimes	referred	to	herein	as	the	MAE settlement,	that	applies	to	both	AES's	generation	and	distribution	businesses	in	Brazil	was	reached.	This	agreement	applies	to	the	rationing-related	loss	of	income incurred	by	both	generation	and	distribution	businesses	as	a	result	of	the	imposition	of	rationing	in	June	2001	and	replaces	the	former	Annex	V	contractual	provisions,	as follows:

•Initial	Contracts	will	be	amended	to	eliminate	Annex	V	provisions;

•Distribution	companies	will	be	entitled	to	recover	rationing-related	loss	recovery	through	a	tariff	increase	which	has	been	in	effect	since	December	26, 2001	and	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;

•Non-contracted	(thermal)	power	plants,	dispatched	in	order	to	fulfill	the	contractual	requirements	of	the	hydroelectric	power	plants,	are	to	be	paid	at	the spot	price	by	the	hydroelectric	power	plant	generators	(up	to	a	price	cap);	with	the	consumers	of	electricity	paying	the	difference	between	the	spot	price and	the	allowed	price	cap;

•Distribution	companies	will	use	their	tariff	increase	to	pay	approximately	97%	of	the	amounts	originally	payable	under	the	Initial	Contracts	in	order	to provide	the	generation	companies	with	recovery	of	their	contractually	allowed	revenue	amount;

•A	loan	funded	by	the	National	Development	Bank	of	Brasil	(BNDES)	will	provide	liquidity	prior	to	recovery	through	the	allowed	tariff	increases.	The loan	will	amortize	in	line	with	the	recovery	of	costs	through	future	tariff	increases	and	will	cover	approximately	90%	of	the	rationing-related	losses	for the	distribution	companies	and	the	non-contracted	energy	payment	of	the	generators.

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.	In	addition,	the	agreement	provided	a	resolution	to	a	long-standing	regulatory	issue	related	to	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	agreement,	Sul	was	permitted	to	record	additional	revenue	and	a	corresponding	receivable	from	the	spot	market	in	the	fourth	quarter	of	2001.	However, ANEEL	promulgated	Order	288	during	May	2002	which	retroactively	changed	certain	previously	communicated	methodologies,	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.

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.

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,	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.	Currently,	ten	companies	are	under	the	tariff reset	public	hearing	process,	including	Sul.	These	results	are	likely	to	influence	Eletropaulo's	tariff	reset.

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.	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.

# Chile

In	Chile,	the	regulation	of	production	schedules	for	electricity	generation	facilities	is	based	on	the	marginal	cost	of	production,	which	is	the	cost	of	the	most	expensive unit	required	by	the	system	at	the	time.	The	spot	price	among	generation	companies	for	both	electrical	capacity	(the	amount	of	electricity	available	at	any	point	in	time) and	electrical	energy	(the	amount	of	electricity	produced	or	consumed	over	a	period	of	time)	is	also	the	marginal	cost	of	production.	Chile	has	four	electricity	systems; the	major	two	interconnected	electricity	systems	are	the	SIC	and	the	SING,	which	cover	almost	97%	of	the	population	of	the	country.

In	order	to	meet	demand	for	electricity	at	any	point	in	time,	the	lowest	marginal	cost	generating	plant	in	an	interconnected	system	is	used	before	the	next	lowest	marginal cost	plant	is	dispatched.	As	a	result,	at	any	specific	level	of	demand,	the	appropriate	supply	will	be	provided	at	the	lowest	possible	marginal	cost	of	production	available in	the	system.	Generation	companies	are	free	to	enter	into	sales	contracts	with	distribution	companies	and	other	customers	for	the	sale	of	capacity	and	energy.	However,

the	electricity	necessary	to	fulfill	these	contracts	is	provided	by	the	contracting	generation	company	only	if	the	generation	company's	marginal	cost	of	production	is	low enough	for	its	generating	capacity	to	be	dispatched	to	meet	demand.	Otherwise,	the	generation	company	will	purchase	electricity	from	other	generation	companies	at	the marginal	cost	of	production	in	the	system,	if	the	contracting	generation	company's	marginal	cost	is	above	that	of	the	last	generator	required	to	meet	demand	at	the	time.

According	to	existing	law,	during	periods	when	production	cannot	meet	system	demands,	regardless	of	whether	the	government	has	enacted	a	rationing	decree,	the	price of	energy	exchanges	among	generation	companies	is	valued	at	the	"unserved	energy	cost"	or	"shortage	cost"	which	is	the	cost	to	consumers	for	not	having	energy available.	This	law	remained	untested	until	November	1998	when	generators	in	the	SIC	were	unable	to	agree	on	the	implementation	of	the	shortage	cost	during	the supply	deficit	and	associated	mandated	rationing	periods.	The	matter	was	referred	to	the	Ministry	of	Economy,	which	in	March	1999	ruled	the	application	of	the	shortage cost.	Based	on	this	decision,	generators	with	energy	deficits	at	the	time	were	required	to	pay	companies	with	energy	surpluses	the	shortage	cost	or	corresponding	spot price	equal	to	the	cost	of	unserved	energy	for	energy	purchases	during	that	period.	The	prices	paid	to	generation	companies	by	distribution	companies	for	capacity	and energy	to	be	resold	to	their	retail	customers	are	based	on	the	expected	average	marginal	cost	of

capacity	or	energy.	In	order	to	ensure	price	stability,	however,	the	regulatory	authorities	in	Chile	establish	prices,	known	as	"node	prices,"	every	six	months	to	be	paid	by distribution	companies	for	the	energy	and	capacity	requirements	of	regulated	consumers.	Node	prices	for	energy	are	calculated	on	the	basis	of	the	projections	of	the expected	marginal	costs	within	the	system	over	the	next	24	to	48	months	in	the	case	of	the	SIC	and	the	SING.	The	formula	takes	into	account,	among	other	things, assumptions	regarding	available	supply	and	demand	in	the	future.	Node	prices	for	capacity	are	based	on	the	marginal	investment	required	to	meet	peak	demand,	based on	the	cost	of	a	diesel-fired	turbine.	Prices	for	capacity	and	energy	sold	to	large	customers	(over	2MW)	and	other	generation	companies	purchasing	on	a	contractual basis	are	unregulated	and	are	often	set	with	reference	to	node	prices,	alternative	fuel	prices,	exchange	rates	and	other	factors.	If	average	prices	for	capacity	and	energy sold	to	non-regulated	customers	differ	from	node	prices	by	more	than	10%,	node	prices	are	adjusted	upward	or	downward,	as	the	case	may	be,	so	that	the	difference between	such	prices	equals	10%.	In	contrast,	the	spot	price	paid	by	one	generation	company	to	another	for	energy	is	referred	to	as	the	"system	marginal	cost,"	which	is based	on	the	actual	marginal	cost	of	the	highest	cost	generator	producing	electricity	in	the	system	during	the	relevant	period,	as	determined	on	an	hourly	basis.

Since	the	system	marginal	cost	for	energy	is	set	weekly	(but	may	in	certain	circumstances	be	changed	on	a	daily	basis)	based	on	variables	that	can	change	on	an instantaneous	basis,	and	the	node	price	for	energy	is	set	every	six	months	based	on	projections	of	these	variables	over	the	next	24	to	48	months,	in	the	case	of	the	SIC,	or 24	to	48	months,	in	the	case	of	the	SING,	the	system	marginal	cost	for	energy	of	a	system	tends	to	be	more	volatile	than	the	node	price	for	energy	of	that	system.	In periods	of	low	water	conditions	that	require	greater	generation	of	energy	by	more	costly	thermoelectric	plants,	the	system	marginal	cost	typically	exceeds	the	node	price. In	periods	of	high	water	conditions	when	lower	cost	hydroelectric	facilities	can	meet	the	majority	of	demand,	the	system	marginal	cost	is	typically	below	the	node	price and	may	in	fact	decline	to	zero	at	some	hours.

# United	Kingdom

The	New	Electricity	Trading	Arrangements	("NETA")	became	effective	on	March	27,	2001.	The	NETA	system	is	structured	around	bilateral	trading	between generators,	suppliers,	traders	and	customers.	The	system	operates	like	a	standard	commodity	market,	but	makes	special	provision	for	the	electricity	system	to	be	kept	in physical	balance.	NETA	includes	forward	and	futures	markets,	allowing	contracts	for	future	delivery	of	electricity	to	be	entered	into	up	to	several	years	in	advance.	The balancing	mechanism	enables	the	system	operator,	The	National	Grid	Company,	to	change	levels	of	generation	and	demand	in	near	real-time.	If	an	imbalance	between	a party's	net	physical	and	net	contractual	positions	occurs,	the	system	provides	a	mechanism	for	settlement	which	creates	an	incentive	for	generators	to	accurately	forecast their	availability.	A	number	of	power	exchanges	have	now	emerged	to	facilitate	medium-	and	short-term	trading	of	standard	products.	It	is	anticipated	that	more sophisticated	trading	tools	and	financial	instruments	will	develop	as	the	market	matures.

Since	the	introduction	of	NETA,	there	has	been	a	marked	decline	in	the	price	paid	for	wholesale	electricity.	Day	ahead	and	one-year	forward	prices	have	declined approximately	30%	and	appear	to	result	from	a	combination	of	factors,	some	of	which	are	specific	to	the	new	structure	of	the	market	and	others	which	relate	to fundamental	market	conditions	(specifically	warmer	weather	during	the	Winter	2001-2002).	Specifically	with	reference	to	NETA,	it	appears	that	the	new	trading	rules have	increased	competitiveness	in	the	market.	As	a	result	of	the	significant	price	declines	over	this	past	year,	virtually	all	generation	facilities	which	do	not	have	long- term	contracts	to	sell	their	power	have	come	under	severe	financial	pressure	and	several	have	been	taken	off-line	or	shut-down	as	prices	have	fallen	below	their	variable costs.	In	February	2002,	the	Company	announced	that	it	would	take	its	Fifoots	plant	off-line	as	it	had	become	no	longer	possible	to	sell	power	above	its	marginal	cost	of generation.	Subsequently	in	March	2002,	the	Fifoots	plant	was	placed	into	administrative	receivership.

# Venezuela

In	September	1999	the	Electric	Service	Law	(LSE),	which	provides	a	framework	for	the	deregulation	of	the	electric	utility	industry	in	Venezuela,	was	enacted.	On December	14,	2000	the	Ministry	of	Energy	and	Mines	enacted	the	Electric	Law	Regulations	pursuant	to	the	LSE.	The	LSE,	as	amended	in	December	2001,	requires	the restructuring	of	integrated	electric	companies	by	January	2003.	On	November	20,	2002	the	MEM	extended	the	date	for	the	restructuring	of	integrated	utilities	to January	2004.	The	restructuring	involves	legally	dividing	generation,	transmission,	distribution	and	commercialization	businesses	into	new	independent	legal	entities that	are	financially,	operationally	and	administratively	autonomous.	Under	the	LSE,	generation	and	commercialization	will	be	deregulated	and	will	be	opened	up	to competition	whereas	distribution	and	transmission	will	remain	regulated	businesses.	The	Ministry	of	Energy	and	Mines	in	consultation	with	the	electric	utility	companies in	Venezuela	is	currently	developing	a	framework	for	the	implementation	of	the	LSE	requirements.

In	addition,	in	January	1999	a	joint	resolution	of	the	Ministry	of	Energy	and	Mines	and	the	Ministry	of	Industry	and	Commerce	(the	"Joint	Resolution")	established	the basic	tariff	rates	applicable	during	the	Four-Years	Tariff	Regime	(1999-2002).	The	tariffs	were	established	by	the	Ministry	of	Energy	and	Mines	using	a	cost-plus methodology	in	that	tariffs	are	calculated	based	on	a	return	on	investment	methodology.	Each	company	provides	information	about	their	business	(assets	and	costs),	and the	tariffs	are	calculated	by	the	regulator	based	on	the	expected	return	for	a	model	company.	Tariffs	are	adjusted:	(i)	semi-annually	to	reflect	fluctuations	in	inflation	and the	currency	exchange	rate;	and	(ii)	monthly	to	reflect	fluctuations	in	fuel	prices.	In	light	of	the	potential	for	energy	shortages	facing	Venezuela	due	primarily	to	a	long dry	season,	the	government	has	been	considering	introducing	incentives	to	reduce	the	consumption	of	energy.	Under	the	current	plan	there	would	be	an	increased	tariff for	energy	consumption	over	certain	thresholds.	The	increased	tariff	will	apply	to	all	commercial,	industrial	and	residential	sectors.

# United	States	Environmental	and	Land	Use	Regulations

The	Company's	businesses	are	subject	to	extensive	environmental	and	land	use	laws	and	regulations.	In	the	United	States	the	laws	and	regulations	applicable	to	AES primarily	involve	the	emissions	into	the	air,	discharge	of	effluents	into	the	water	and	the	use	of	water,	as	well	as	wetlands	preservation,	endangered	species,	waste disposal	and	noise	regulation.	These	laws	and	regulations	often	require	a	lengthy	and	complex	process	of	obtaining	licenses,	permits	and	approvals	from	federal,	state and	local	agencies.	If	AES	violates	or	fails	to	comply	with	such	laws,	regulations,	licenses,	permits	or	approvals,	AES	could	be	fined	or	otherwise	sanctioned	by regulators.	In	addition,	under	certain	environmental	laws,	AES	could	be	responsible	for	costs	relating	to	contamination	at	its	facilities	or	at	third-party	waste	disposal sites.	AES	has	accrued	liabilities	for	projected	environmental	remediation	costs.	See	Note	11	of	the	consolidated	financial	statements	for	more	detail.	AES	has	at	times been	in	non-compliance	with	environmental	laws,	regulations,	licenses,	permits	and	approvals,	although	no	such	instance	has	resulted	in	revocation	of	any	material permit	or	license.	AES	has	incurred	and	will	continue	to	incur	significant	capital	and	other	expenditures	to	comply	with	environmental	laws	and	regulations,	in particular,	with	respect	to	the	laws	and	regulations	described	below.	Although	AES	is	not	aware	of	any	costs	of	complying	with	environmental	laws	and	regulations which	would	reasonably	be	expected	to	result	in	a	material	adverse	effect	on	its	business,	consolidated	financial	position	or	results	of	operations	except	as	described below,	there	can	be	no	assurance	that	AES	will	not	be	required	to	incur	material	compliance	costs	in	the	future.

Environmental	laws	and	regulations	affecting	power	generation	and	distribution	are	complex,	change	frequently	and	have	tended	to	become	more	stringent	over	time.	If such	laws	and	regulations	are	changed	and	any	of	AES's	facilities	are	not	"grandfathered"	(that	is,	made	exempt	by	the	fact	that	the	facility	pre-existed	the	law)	or	are	not otherwise	excluded,	extensive	modifications	to	a	facility's	technologies	and	operations	could	be	required.	Should	environmental	laws	or	regulations	change	in	the

future,	there	can	be	no	assurance	that	AES	would	be	able	to	recover	all	or	any	increased	costs	from	its	customers	or	that	its	consolidated	financial	position	or	results	of operations	would	not	be	materially	and	adversely	affected.	In	addition,	the	Company	may	be	required	to	make	significant	capital	or	other	expenditures	in	connection with	such	changes	in	environmental	laws	or	regulations.	The	Company	is	not	aware	of	any	currently	planned	changes	in	law,	however,	that	would	reasonably	be expected	to	have	a	material	adverse	effect	on	its	business,	consolidated	financial	position	or	results	of	operations,	except	as	described	below.

# Clean	Air	Act

The	Clean	Air	Act	of	1970	(the	"Clean	Air	Act"),	as	amended	in	1990	(the	"1990	Amendments"),	sets	guidelines	for	emissions	standards	for	major	pollutants	including sulfur	dioxide	("SO 2")	and	nitrogen	oxides	("NOx").	Among	other	things,	the	1990	Amendments	require	reductions	in	acid	rain	precursor	emissions	(SO 	and	NOx) from	existing	sources,	particularly	large,	older	power	plants	that	were	exempted	from	certain	requirements	of	the	Clean	Air	Act.	Other	provisions	of	the	Clean	Air	Act relate	to	the	reduction	of	ozone	precursor	emissions	(volatile	organic	compounds	("VOC")	and	NOx)	and	have	resulted	in	the	imposition	by	various	U.S.	states	of "reasonably	available	control	technology"	requirements	to	reduce	such	emissions.

# National	Ambient	Air	Quality	Standards

In	1997,	the	U.S.	Environmental	Protection	Agency	("EPA")	published	new	standards	that	tighten	national	ambient	air	quality	standards	("NAAQS")	for	ozone	and	fine particulate	matter	("PM").	In	October	1999,	a	federal	appeals	court	overturned	the	new	standards.	In	February	2001,	the	U.S.	Supreme	Court	reversed	and	remanded	the case	to	the	appeals	court	for	further	review	of	the	standards	but	held	that	EPA's	policy	for	implementing	the	new	ozone	standard	was	unlawful.	In	March	2002,	the federal	appeals	court	upheld	the	new	standards.	However,	as	directed	by	the	U.S.	Supreme	Court,	EPA	must	develop	a	new	implementation	policy	for	the	ozone	standard in	2003.	Although	we	cannot	predict	what	EPA's	final	policy	for	implementing	the	new	ozone	and	PM	standards	will	be,	AES's	plants	will	likely	be	faced	with	further emission	reduction	requirements	that	could	necessitate	both	the	installation	of	additional	control	technology	and	a	related	increase	in	capital	expenditures.

Also,	EPA	intends	to	propose	a	rule	in	December	2003	which	would	control	certain	SO 2	emissions	which	form	fine	PM	that	is	transported	to	downwind	states.	The	rule will	likely	require	an	approximately	70%	reduction	in	SO 2	emissions	by	2010	through	market-based	emissions	trading.

# NOx	SIP	Call

In	October	1998,	EPA	issued	a	final	rule	addressing	the	regional	transport	of	ground-level	ozone	across	state	boundaries	to	the	eastern	United	States.	The	rule	("NOx	SIP Call"),	as	amended	in	June	and	August	of	2000,	requires	twenty-two	states	and	the	District	of	Columbia,	including	Illinois,	Indiana,	New	York	and	Pennsylvania,	states in	which	AES's	plants	are	located,	to	reduce	NOx	emissions	that	cross	state	boundaries,	including	emissions	from	electric	generating	units.	The	District	of	Columbia	and these	states	were	required	to	submit	revised	state	implementation	plans	("SIPs")	by	October	2000,	with	a	compliance	date	for	affected	emissions	sources,	including electric	generating	plants,	of	May	31,	2004.	As	a	result	of	the	NOx	SIP	Call,	AES	will	likely	be	required	to	make	further	reductions	in	NOx	emissions	at	some	of	its facilities.

# Section	126	Petitions

In	December	1999,	EPA	granted	petitions	filed	by	four	northeastern	states	seeking	to	reduce	ozone	damage	from	certain	sources	in	midwestern	upwind	states.	In granting	the	petitions,	submitted	under

Section	126	of	the	Clean	Air	Act,	the	EPA	made	a	finding	that	certain	large	electric	generating	units	in	upwind	states	significantly	contribute	to	non-attainment	of	the NAAQS	for	ozone	in	the	northeastern	downwind	states.	The	compliance	date	for	affected	emission	sources,	including	electric	generating	plants,	is	May	31,	2004.	As	a result	of	EPA's	ruling,	certain	AES	plants	may	be	required	to	make	further	reductions	in	NOx	emissions,	in	addition	to	those	needed	to	comply	with	the	ozone	NAAQs and	the	NOx	SIP	Call	described	above.

# New	Source	Review

In	the	1990s,	EPA	commenced	an	industry-wide	investigation	of	coal-fired	electric	generators	to	determine	compliance	with	environmental	requirements	under	the 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	("NSR")	regulations	which	require	companies	to	obtain	permits	prior	to	making	major	modifications	to	their	facilities.	In December	2002,	EPA	promulgated	revised	NSR	regulations.	However,	EPA	has	stated	that	the	revised	regulations	will	not	affect	existing	enforcement	cases.	See	Item	3 —Legal	Proceedings	for	a	description	of	certain	related	litigation	affecting	AES.

# Regional	Haze

The	EPA	published	the	final	regional	haze	rule	on	July	1,	1999.	This	rule	establishes	planning	and	emission	reduction	timelines	for	states	to	use	to	improve	visibility	in national	parks	throughout	the	United	States.	On	June	22,	2001,	the	EPA	signed	a	proposed	rule	to	guide	states	in	implementing	the	1999	rule	and	in	controlling	power plant	emissions	that	cause	regional	haze	problems.	The	proposed	rule	set	guidelines	for	states	in	determining	best	available	retrofit	technology,	or	BART,	at	older	power plants.	Under	the	rule,	states	are	required	to	submit	to	the	EPA	their	regional	haze	SIPs	by	sometime	during	2004	through	2008,	depending	on	whether	and	when	the EPA	determines	that	state	is	in	"attainment"	or	"non-attainment."	The	ultimate	effect	of	the	regional	haze	rule	could	be	requirements	for	(i)	newer	and	cleaner technologies	and	additional	controls	on	conventional	particulates,	and	(ii)	reductions	in	SO2,	NOx	and	particulate	matter	emissions	from	utility	sources.	If	the	proposed rule	is	finalized	and	implemented,	and	utility	emissions	reductions	are	required,	compliance	costs	to	AES	could	be	significant.

# Hazardous	Air	Pollutants

The	1990	Amendments	also	regulate	certain	hazardous	air	pollutants	("HAPs").	In	February	1998,	the	EPA	released	a	final	report	on	HAP	emissions	from	power	plants that,	among	other	things,	concluded	that	the	risk	of	contracting	cancer	from	exposure	to	HAPs	(other	than	mercury)	from	most	plants	is	low	(less	than	one	in	one million)	and	that	further	research	on	mercury	emissions	was	necessary.	In	December	2000,	the	EPA	announced	it	would	adopt	rules	to	regulate	mercury	emissions	from coal-	and	oil-fired	power	plants.	The	EPA	expects	to	propose	these	regulations	by	December	2003	and	issue	final	regulations	by	December	2004	with	reductions required	in	2007-2008.	Once	these	final	regulations	have	been	issued,	the	use	of	"maximum	available	control	technology"	may	be	required	to	control	these	emissions. See	"Recent	Legislative	and	Regulatory	Proposals"	below	for	a	description	of	other	proposed	mercury	restrictions.

Global	Warming

Global	warming	continues	to	be	a	concern	and	remains	a	policy	issue	that	is	regularly	considered	for	possible	government	regulation.	The	Kyoto	Protocol	to	the	United Nations	Framework	Convention	on	Climate	Change,	if	ratified	by	the	requisite	number	of	signatory	countries,	would	require	the	signatory	countries	to	make	substantial reductions	in	"greenhouse	gas"	emissions	which	include	carbon	dioxide	(CO 2).	Although	the	United	States	agreed	to	the	Kyoto	Protocol,	the	treaty	has	not	been	sent	to the

Senate	for	ratification.	Several	U.S.	states,	including	Massachusetts,	California	and	New	Hampshire,	have	taken	action	to	reduce	greenhouse	gas	emissions.	Also, several	European	countries	have	some	regulations	concerning	greenhouse	gases.	U.S.	federal	legislation	requiring	reductions	in	greenhouse	gases	could	substantially affect	both	the	costs	and	the	operating	characteristics	of	AES's	fossil-fuel	(coal,	oil,	gas)	fired	businesses.	See	"Recent	Legislative	and	Regulatory	Proposals"	below.

# Recent	Legislative	and	Regulatory	Proposals

New	legislation	has	been	introduced	in	Congress	which,	if	passed	into	law,	would	require	reduction	in	power	plant	air	emissions	beyond	the	requirements	described above.	In	particular,	various	bills	sponsored	by	members	of	Congress	would	require	significant	reductions	for	CO 2,	NOx,	SO 2	and	mercury.	In	addition,	President Bush's	"Clear	Skies"	legislation,	which	would	cap	emissions	of	three	pollutants	(NOx,	SO 2	and	mercury),	with	voluntary	reductions	of	CO 2,	was	introduced	in	Congress in	July	2002	and	reintroduced	by	Senator	Inhofe	in	February	2003.

In	February	2002,	the	New	York	Department	of	Environmental	Conservation	("DEC")	issued	proposed	regulations	requiring	electric	generators	to	reduce	SO 	emissions by	50%	below	current	Clean	Air	Act	standards.	The	state	environmental	authorities	are	scheduled	to	vote	on	this	regulation	on	March	26,	2003.	If	adopted,	the	SO 2 regulation	would	be	phased	in	beginning	on	January	1,	2005	with	implementation	completed	by	January	1,	2008.	DEC's	proposed	regulations	would	also	require	electric generators	to	meet	stringent	NOx	reduction	requirements	year-round,	rather	than	just	during	the	summertime	ozone	season.	These	new	NOx	regulations,	if	adopted, would	take	effect	on	October	1,	2004.	If	any	of	these	and/or	other	similar	rules	or	legislation	are	passed	into	law,	AES's	generation	facilities	would	likely	be	required	to incur	additional	significant	costs	to	install	additional	environmental	pollution	control	technology.

In	early	2002,	the	EPA,	pursuant	to	Section	316	of	the	United	States	Federal	Water	Pollution	Control	Act,	proposed	a	regulation	establishing	location,	design, construction	and	capacity	standards	for	cooling	water	intake	structures	at	existing	power	plants,	including	many	of	AES's	U.S.	facilities.	The	proposed	regulation,	which is	designed	to	protect	aquatic	life	affected	by	these	intake	structures,	would	require	subject	facilities	to	demonstrate	their	cooling	water	intake	systems	meet	best technology	available	("BTA").	While	the	proposed	regulation	is	subject	to	public	comment	and	potential	revision	prior	to	being	finalized,	the	EPA	is	required	to	publish a	final	rule	by	August	2003.	If	the	proposed	regulation	is	adopted,	AES	will	be	required,	for	each	subject	facility,	(i)	to	demonstrate	the	facility	already	meets	the proposed	performance	requirements;	(ii)	to	select,	design	and	construct	new	technologies,	operational	measures	and/or	restorative	measures	that	meet	the	proposed requirements	or	(iii)	to	request	a	facility-specific	determination	of	BTA	if	the	costs	of	compliance	are	significantly	greater	than	those	estimated	by	EPA	or	if	the	costs	of compliance	would	be	significantly	greater	than	the	benefits	of	complying	with	the	requirements.	These	requirements	could	result	in	significant	capital	expenditures	and operating	costs	for	each	subject	facility.

# Foreign	Environmental	Regulations

AES	has	ownership	interests	in	power	plants	and	projects	in	many	countries	outside	the	United	States.	Each	of	these	countries	(and	the	localities	therein)	have	separate laws	and	regulations	governing	the	siting,	construction,	permitting,	ownership,	operation,	decommissioning	and	remediation	of,	and	power	sales	from,	such	power plants.	These	countries	also	have	laws	governing	waste	disposal,	the	discharge	of	pollutants	into	the	air,	water	or	ground	and	noise	pollution.	These	laws	and	regulations are	often	different	from	those	in	effect	in	the	United	States.	In	addition	to	such	foreign	laws	and	regulations,	projects	funded	by	the	World	Bank	are	subject	to	World Bank	environmental	standards.	These	standards	may	be	more	stringent	than	local	country	standards	but	are	typically	not	as	strict	as	corresponding	standards	in	the United	States.	AES	has	incurred	and	will	continue	to	incur	capital	and	other	expenditures	to	comply	with	these	laws	and	regulations,	in	particular,	laws	governing	air

emissions.	Whenever	feasible,	AES	attempts	to	use	advanced	environmental	technologies	(such	as	CFB	coal	technology	or	advanced	gas	turbines)	in	its	non-U.S. businesses	in	order	to	minimize	environmental	impacts.

Our	operations	in	the	European	Union	(the	"EU")	are	subject	to	EU	directives	and	national	legislation	implementing	those	directives.	Many	of	AES's	non-U.S.	facilities are	also	subject	to	international	conventions	and	protocols,	including,	without	limitation,	the	Kyoto	Protocol	described	in	"United	States	Environmental	and	Land	Use Regulation"	above.	On	March	4,	2002,	the	fifteen	Member	Nations	of	the	EU	agreed	to	ratify	the	Kyoto	Protocol.	Also,	in	December	2002,	Canada	ratified	the	Kyoto Protocol,	and	the	Russian	Federation	has	declared	its	intention	to	ratify	the	Protocol	in	the	spring	of	2003.	If	ratified	by	the	Russian	Federation,	the	Protocol	will	enter into	force	for	all	countries	that	have	ratified	it.	If	the	governments	of	the	United	Kingdom	and	The	Netherlands,	in	particular,	ratify	and	adopt	regulations	implementing the	Kyoto	Protocol,	our	facilities	in	those	countries	will	be	required	to	incur	significant	costs	to	reduce	CO 2	emissions,	and	their	operating	characteristics	may	be affected.	These	costs	would	be	in	addition	to	costs	to	comply	with	any	other	foreign	regulations	governing	greenhouse	gas	emissions,	including	those	already	in	effect	in Europe.

Based	on	current	trends,	AES	expects	that	environmental	and	land	use	regulations	affecting	its	plants	located	outside	the	United	States	will	likely	become	more	stringent over	time.	This	may	be	due	in	part	to	a	greater	participation	by	local	citizenry	in	the	monitoring	and	enforcement	of	environmental	laws,	better	enforcement	of	applicable environmental	laws	by	the	regulatory	agencies,	and	the	adoption	of	more	sophisticated	environmental	requirements.	If	foreign	environmental	and	land	use	regulations were	to	change	in	the	future,	the	Company	may	be	required	to	make	significant	capital	or	other	expenditures.	There	can	be	no	assurance	that	AES	would	be	able	to recover	from	its	customers	all	or	any	increased	costs	to	comply	with	current	or	future	environmental	or	land	use	regulations	or	that	its	business,	financial	condition	or results	of	operations	would	not	be	materially	and	adversely	affected	by	such	foreign	environmental	and	land	use	regulations.

# Competition

In	the	contract	generation	line	of	businesses,	AES	faces	most	of	its	competition	during	the	development	phase	of	its	projects.	Its	competitors	in	this	business	include other	independent	power	producers	as	well	as	various	utilities	and	their	affiliates.	Traditionally,	competition	in	this	segment	is	limited	due	to	the	long-term	nature	of	the generation	contracts.	However,	due	to	the	introduction	of	competitive	power	markets,	and	the	addition	of	new	market	participants,	there	may	be	increased	competition	in attracting	new	customers	and	maintaining	our	current	customers	as	their	existing	contracts	expire.

AES	competes	in	the	competitive	supply	segment	with	numerous	other	independent	power	producers,	energy	marketers	and	traders,	energy	merchants,	transmission	and distribution	providers	and	retail	energy	suppliers.	Competitive	factors	include	price,	contract	terms,	including	credit	requirements	and	quality	of	service.

Historically,	energy	utilities	operated	within	specific	service	territories	where	they	were	essentially	the	sole	suppliers	of	electricity	services,	and	therefore	competition was	limited	to	alternative	means	of	energy	such	as	gas	and	fuel.	However,	in	certain	locations,	the	large	utilities	business	is	facing	significant	challenges	and	increased competition	as	a	result	of	changes	in	laws	and	regulations	allowing	wholesale	and	retail	services	to	be	provided	on	a	competitive	basis.	There	can	be	no	assurance	that the

deregulation	will	not	adversely	affect	the	future	operations,	cash	flows	and	financial	condition	of	our	large	utilities.

In	the	growth	distribution	line	of	business	there	may	be	competition	to	acquire	facilities.	However,	there	is	currently	little	competition	in	growth	distribution	business	due to	the	significant	barriers	to	entry	present	in	these	markets.	AES	competes	against	a	number	of	other	participants,	some	of	which	have	greater	financial	resources	and have	been	engaged	in	growth	distribution	related	businesses	for	periods	longer	than	AES	and	have	accumulated	more	significant	portfolios.	Relevant	competitive	factors include	financial	resources,	governmental	assistance,	and	access	to	non-recourse	financing	and	regulatory	factors.

# Customers

The	Company	sells	to	a	wide	variety	of	customers.	No	individual	customer	accounted	for	more	than	10%	of	the	Company's	2002	net	sales.

# Employees

# Executive	Officers	and	Significant	Employees	of	the	Registrant

The	following	is	information	concerning	the	present	executive	officers	and	significant	employees	of	the	Registrant	set	out	in	alphabetical	order.

Joseph	C.	Brandt,	38	years	old,	was	appointed	Chief	Restructuring	Officer	and	Vice	President	in	February	2003.	From	January	2002	to	February	2003,	Mr.	Brandt	was Group	Manager	for	AES	Andes,	a	business	group	responsible	for	AES's	business	interests	in	Argentina.	From	1999	to	2002,	Mr.	Brandt	held	various	corporate	and development	positions	with	the	Company.	From	1998	to	1999,	Mr.	Brandt	worked	as	an	investment	advisor.	Mr.	Brandt	received	a	JD	from	Georgetown	University	Law Center,	an	MA	from	the	University	of	Virginia	and	an	AB	from	George	Mason	University	and	was	a	Fulbright	Scholar	at	the	University	of	Helsinki,	Finland.

Mark	Fitzpatrick,	52	years	old,	was	appointed	Executive	Vice	President	of	the	Company	in	February	2000.	His	responsibilities	included	overseeing	the	AES	businesses in	the	Latin	American	Region.	Mr.	Fitzpatrick	was	Senior	Vice	President	until	February	2000,	and	was	appointed	Vice	President	of	the	Company	in	1987. Mr.	Fitzpatrick	became	Managing	Director	of	Applied	Energy	Services	Electric	Limited	for	the	United	Kingdom	and	Western	Europe	operations	in	1990.	From	1984	to 1987,	he	served	as	a	project	director	of	the	AES	Beaver	Valley	and	AES	Thames	projects.

Paul	T.	Hanrahan,	45	years	old,	was	appointed	President	and	Chief	Executive	Officer	in	June	2002.	He	was	one	of	the	four	Chief	Operating	Officers	appointed	in February	2002.	He	was	appointed	Executive	Vice	President	in	February	2000,	Senior	Vice	President	since	in	1997,	and	was	appointed	Vice	President	of	the	Company effective	January	1994.	From	May	1,	2000	to	February	2002,	Mr.	Hanrahan	was	Managing	Director	of	AES	Americas,	a	business	group	responsible	for	Bolivia, Colombia,	Ecuador,	Peru,	Venezuela	and	Southern	Brazil.	From	May	1,	1998	until	becoming	director	of	AES	Americas,	Mr.	Hanrahan	was	Managing	Director	of	AES Americas	South,	a	business	group	within	AES	responsible	for	all	of	AES's	activities	in	Argentina,	Paraguay,	and	Chile.	From	February	1995	until	becoming	Managing Director	of	AES	Americas	South	he	was	President	and	Chief	Executive	Officer	of	AES	Chigen,	where	he	served	as	Executive	Vice	President,	Chief	Operating	Officer and	Secretary	from	December	1993	until	February	1995.	He	was	General	Manager	of	AES	Transpower,	Inc.,	a	subsidiary	of	the	Company,	from	1990	to	1993.

William	R.	Luraschi,	39	years	old,	was	appointed	Senior	Vice	President	in	February	2002	and	has	been	Vice	President	of	the	Company	since	January	1998,	and	General Counsel	of	the	Company	since	January	1994.	He	also	was	Secretary	from	February	1996	until	June	2002.	Prior	to	that,	Mr.	Luraschi	was	an	attorney	with	the	law	firm	of Chadbourne	&	Parke	L.L.P.

Dr.	Roger	F.	Naill,	56	years	old,	was	appointed	Senior	Vice	President	in	February	2001	and	has	been	Vice	President	for	Planning	at	AES	since	1981.	Dr.	Naill	is responsible	for	AES's	financial	forecasts	and	other	corporate	issues.	Prior	to	joining	the	Registrant,	Dr.	Naill	was	Director	of	the	Office	of	Analytical	Services	at	the Department	of	Energy.	Dr.	Naill	received	a	Ph.D	in	Engineering	from	Dartmouth	College	and	a	MSM	Degree	from	the	A.P.	Sloan	School	of	Business	(MIT).

John	Ruggirello,	52	years	old,	was	appointed	Chief	Operating	Officer	for	Generation	in	February	2003.	He	was	appointed	Executive	Vice	President	of	the	Registrant	in February	2000,	was	Senior	Vice	President	until	February	2000	and	was	appointed	Vice	President	in	January	1997.	Mr.	Ruggirello	led	the	AES	Enterprise	group,	with responsibility	for	project	development,	construction	and	plant	operations	in	the	United	States.	Prior	to	joining	the	Company	in	1987,	Mr.	Ruggirello	was	Operations Manager	for	a	division	of	the	Diamond	Shamrock	Corporation.

Barry	J.	Sharp,	43	years	old,	holds	the	position	of	Chief	Financial	Officer.	His	responsibilities	include	overseeing	the	finance	function.	He	was	appointed	Executive	Vice President	in	February	2001.	Mr.	Sharp	was	appointed	Senior	Vice	President	in	January	1998	and	had	been	Vice	President	and	Chief	Financial	Officer	since	1987.	He also	served	as	Secretary	of	the	Company	until	February	1996.	From	1986	to	1987,	he	served	as	the	Company's	Director	of	Finance	and	Administration.	Mr.	Sharp	is	a certified	public	accountant.

Kenneth	R.	Woodcock,	59	years	old,	has	been	Senior	Vice	President	of	the	Company	since	1987.	Mr.	Woodcock	is	responsible	for	coordinating	AES's	relationships with	the	investment	community,	and	he	provides	support	for	AES	business	development	activities	worldwide.	From	1984	to	1987,	he	served	as	a	Vice	President	for Business	Development.	Prior	to	the	founding	of	AES	he	served	in	the	United	States	federal	government	in	energy	and	environment	departments.

# How	to	Contact	AES	and	Sources	of	Other	Information

The	Company,	a	corporation	organized	under	the	laws	of	Delaware,	was	formed	in	1981.	AES	has	its	principal	offices	located	at	1001	North	19th	Street,	Suite	2000, Arlington,	Virginia	22209.	Its	telephone	number	is	(703)	522-1315,	and	its	web	address	is	http://www.aes.com.	The	Company's	annual	reports	on	Form	10-K,	quarterly reports	on	Form	10-Q	and	current	reports	on	Form	8-K	and	any	amendments	to	such	reports	filed	pursuant	to	section	13(a)	or	Section	15(d)	of	the	Securities	Exchange Act	of	1934	are	posted	on	the	Company's	website	at	http://www.aes.com	as	soon	as	practical	after	they	are	filed	with	the	Securities	and	Exchange	Commission	and	are available	free	of	charge.	Material	contained	on	the	Company's	website	is	not	incorporated	by	reference	in	this	report	on	Form	10-K.

Offices	are	maintained	by	the	Registrant	in	many	places	around	the	world,	which	are	generally	occupied	pursuant	to	the	provisions	of	long-	and	short-term	leases,	none of	which	are	material	to	the	Company.	With	a	few	exceptions,	the	Registrant's	facilities,	which	are	described	in	Item	1	hereof,	are	subject	to	mortgages	or	other	liens	or

encumbrances	as	part	of	the	project's	related	finance	facility.	The	land	interest	held	by	the	majority	of	the	facilities	is	that	of	a	lessee	or,	in	the	case	of	the	facilities located	in	the	People's	Republic	of	China,	a	land	use	right	that	is	leased	or	owned	by	the	related	joint	venture	that	owns	the	project.	However,	in	a	few	instances,	there exists	no	accompanying	project	financing	for	the	facility,	and	in	a	few	of	these	cases,	the	land	interest	may	not	be	subject	to	any	encumbrance	and	is	owned	by	the subsidiary	or	affiliate	owning	the	facility	outright.

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	the	Company's	joint	venture	("SEB")	and	the	state	of	Minas	Gerais	concerning	CEMIG	which	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	November	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	April	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.	In	August	2002,	SEB	filed	two	interlocutory	appeals	against	the	state	appellate court's	refusal	to	consider	SEB's	appeal	on	the	merits,	one	directed	to	the	Federal	Superior	Court	and	the	other	to	the	Supreme	Court	of	Justice.	The	appeals	continue	to be	pending.	The	Company,	together	with	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	the	Company	and	SEB	will	be	successful	in	their	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.	In	December	2000,	the	case	was	removed	from	the	San	Diego	County	Superior	Court	to the	U.S.	District	Court	for	the	Southern	District	of	California.	The	case	has	been	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.	Defendants	have	filed	a	motion	to	dismiss	the	action	in	its	entirety. 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)	are	subject	to	overlapping	state	investigations	by	the	California	Attorney	General's	Office,	the	Market	Oversight	and	Monitoring Committee	of	the	California	Independent	System	Operator	("ISO"),	the	California	Public	Utility	Commission	and	a	subcommittee	of	the	California	Senate.	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	the	national	wholesale	power	markets,	with	particular	emphasis upon	the	California	wholesale	electricity	market,	in	order	to	determine	whether	there	has	been	anti-competitive	activity	by	wholesale	generators	and	marketers	of electricity.	The	FERC	has	requested	documents	from	each	of	the	AES	Southland	plants	and	AES	Placerita.	AES	Southland	and	AES	Placerita	have	cooperated	fully with	the	FERC	investigation.

In	May	2001,	the	Antitrust	Division	of	the	United	States	Department	of	Justice	initiated	an	investigation	to	determine	whether	a	provision	in	the	AES	Southland	plants' Tolling	Agreement	with	Williams	Energy	Services	Company	has	restricted	the	addition	of	new	capacity	in	the	Los	Angeles	area

in	contravention	of	the	antitrust	laws.	The	AES	Southland	businesses	have	provided	documents	and	other	information	to	the	Department	of	Justice.

In	July	of	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.	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 now	asked	the	arbitrators	themselves	to	rule	on	the	same	motion,	which	motion	again	requests	their	removal	from	the	panel.	Although	that	motion	remains	pending,	the present	panel	has	requested	that	the	parties'	statements	of	claim	be	filed	by	April	2003.	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	seeks,	inter	alia,	certain	categories	of	documents	related	to	the	generation	and	sale	of	electricity	in	California	from	January	1998	to	the	present.	The	Company intends	to	comply	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	Employment	Retirement	Income	Securities	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.	Discovery	continues	in	the	lawsuit.	The	subsidiary	believes	it	has	meritorious	defenses	to	the	claims	asserted	against	them	and intends	to	defend	these	lawsuits	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.	This	consolidation	motion	is	pending.	On	November	5,	2002,	the	Court	appointed lead	plaintiffs	and	lead

and	local	counsel.	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	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 thereunder	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.	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	4,	2002,	six	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	stock	between	April	26,	2001	and 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	seven	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	consolidation	action	to	the	United	States	District	Court	for	the	Southern	District	of	Indiana.

The	Company	and	the	individuals	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	is	developing	in	Uganda,	have	made	or	have	agreed	to	make	certain	improper	payments	in	violation	of	the	Foreign	Corrupt	Practices	Act.	The	Company	is conducting	its	own	internal	investigation	and	is	cooperating	with	the	Department	of	Justice	in	this	investigation.

In	November	2002,	a	lawsuit	was	filed	against	AES	Wolf	Hollow	L.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.	The	subsidiary	believes	it	has	meritorious	defenses	to	the	claims	asserted against	it	and	intends	to	defend	the	lawsuit	vigorously.

On	August	24,	2002,	Bechtel	Power	Corporation	("Bechtel")	filed	a	lawsuit	against	the	Company	in	California	State	court	alleging	three	claims	for	breach	of	guaranty and	one	claim	for	fraud.	Bechtel	contends	that	AES	owes	Bechtel	approximately	$47	million	based	on	AES's	alleged	guaranty	of	purported	payment	obligations	of Mountainview	to	Bechtel	under	a	certain	construction	contract.	Bechtel	also	asserts	that	the	Company	fraudulently	induced	Bechtel	to	enter	into	such	construction contract.	In	December	2002,	the	Company's	motion	seeking	a	stay	of	the	lawsuit	as	issues	asserted	in	the	lawsuit	are	the	subject	of	a	mandatory	arbitration	currently pending	between	Bechtel	and	Mountainview	(see	"Bechtel	Arbitration"	referenced	below)	was	granted	by	the	Court.	In	January	2003,	Bechtel	and	the	Company	agreed to	a	further	stay	of	the	litigation	pending	the	parties'	finalization	of	an	agreement	whereby	the	Mountainview	project	would	be	sold	by	the	Company.	In	March	2003,	in connection	with	the	sale	of	Mountainview,	the	parties	agreed	to	file	a	voluntary	dismissal	of	the	arbitration.

On	September	25,	2002,	Mountainview	filed	a	demand	for	arbitration	against	Bechtel	Power	Corporation	(the	"Bechtel	Arbitration").	The	claims	asserted	in	the	Bechtel Arbitration	relate	to	existing	disputes	between	the	parties	regarding	amounts	that	Bechtel	asserts	are	owing	by	Mountainview	due	to	purported	services	provided	in connection	with	the	construction	of	the	Mountainview	power	project	located	in	California.	Mountainview	seeks	a	determination	in	the	arbitration	that	Mountainview	has fully	performed	all	obligations	owing	to	Bechtel	and	Mountainview	owes	no	further	amounts	to	Bechtel.	In	December	2003,	the	members	of	the	arbitration	panel	were appointed	by	the	parties.	In	January	2003,	Bechtel	and	the	Company	agreed	to	a	further	stay	of	the	arbitration	pending	the	parties'	finalization	of	an	agreement	whereby the	Mountainview	project	would	be	sold	by	the	Company.	In	March	2003,	in	connection	with	the	sale	of	Mountainview,	the	parties	agreed	to	file	a	voluntary	dismissal of	the	arbitration.

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.	Also	in March	2003,	the	Commission	for	Public	Works	and	Services	of	the	Sao	Paulo	Congress	requested	Eletropaulo	to	appear	at	a	hearing	relating	to	the	default	by	AES	Elpa and	AES	Transgas	with	BNDES	and	the	quality	of	service	rendered.

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	dollars	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	dollars	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	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	28,	2003,	a	motion	to	dismiss	the	action	was	filed	based	on the	plaintiff's	failure	to	make	a	demand	on	the	Company	to	investigate	the	allegations.	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"). It	is	anticipated	that	a	similar	motion	to	dismiss,	as	filed	in	the	Schoellerman	Lawsuit,	will	be	filed	to	dismiss	the	Pearce	Lawsuit.

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,	2002	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.	The	Company	and the	individual	defendants	have	not	yet	responded	to	the	complaint.

The	Company	is	also	involved	in	certain	other	legal	proceedings	in	the	normal	course	of	business.

# 								Item	4—Submission	of	Matters	to	a	Vote	of	Security	Holders

No	matters	were	submitted	to	a	vote	of	security	holders	during	the	fourth	quarter	of	2002.

# Part	II

# 								Item	5—Market	for	Registrant's	Common	Equity	and	Related	Stockholder	Matters

# Market	Information.

The	common	stock	of	the	Company	is	currently	traded	on	the	New	York	Stock	Exchange	(NYSE)	under	the	symbol	"AES."	The	following	tables	set	forth	the	high	and low	sale	prices	for	the	common	stock	as	reported	by	the	NYSE	for	the	periods	indicated.

# Price	Range	of	Common	Stock

| 2002 | High | Low | 2001 | High | Low |
| :--- | :--- | :--- | :--- | :--- | :--- |
| First\tQuarter | $17.84 | $4.11 | First\tQuarter | $60.15 | $41.30 |
| Second\tQuarter | 9.17 | 3.55 | Second\tQuarter | 52.25 | 39.95 |
| Third\tQuarter | 4.61 | 1.56 | Third\tQuarter | 44.50 | 12.00 |
| Fourth\tQuarter | 3.57 | 0.95 | Fourth\tQuarter | 17.80 | 11.60 |

# Holders.

# Dividends.

Under	the	terms	of	the	Company's	senior	secured	credit	facilities	entered	into	with	a	commercial	bank	syndicate,	the	Company	is	not	allowed	to	pay	cash	dividends.	In addition,	the	Company	is	precluded	from	paying	cash	dividends	on	its	Common	Stock	under	the	terms	of	a	guaranty	to	the	utility	customer	in	connection	with	the	AES Thames	project	in	the	event	certain	net	worth	and	liquidity	tests	of	the	Company	are	not	met.

The	ability	of	the	Company's	project	subsidiaries	to	declare	and	pay	cash	dividends	to	the	Company	is	subject	to	certain	limitations	in	the	project	loans,	governmental provisions	and	other	agreements	entered	into	by	such	project	subsidiaries.

# Securities	Authorized	for	Issuance	under	Equity	Compensation	Plans.

See	the	information	contained	under	the	caption	"Securities	Authorized	for	Issuance	under	Equity	Compensation	Plans"	of	the	Proxy	Statement	for	the	Annual	Meeting of	Stockholders	of	the	Registrant	to	be	held	on	May	1,	2003,	which	information	is	incorporated	herein	by	reference.

# 								Item	6—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.

|  | 2002 | 2001 | 2000 | 1999 | 1998 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  | (in\tmillions,\texcept\tper\tshare\tdata) | (in\tmillions,\texcept\tper\tshare\tdata) |  |  |
| Statement\tof\tOperations\tData: |  |  |  |  |  |
| Revenues | $8,632 | $7,645 | $6,206 | $3,772 | $3,237 |
| (Loss)\tincome\tfrom\tcontinuing\toperations | (2,590) | 446 | 806 | 365 | 453 |
| Discontinued\toperations,\tnet\tof\ttax | (573) | (173) | (11) | (8) | (12) |
| Cumulative\teffect\tof\tchange\tin\taccounting\tprinciple,\tnet\tof\ttax | (346) | — | — | — | — |
| Net\t(loss)\tincome | $(3,509) | $273 | $795 | $357 | $441 |
| Basic\t(loss)\tearnings\tper\tshare: |  |  |  |  |  |
| (Loss)\tincome\tfrom\tcontinuing\toperations | $(4.81) | $0.84 | $1.67 | $0.86 | $1.14 |
| Discontinued\toperations | (1.05) | (0.32) | (0.01) | (0.02) | (0.03) |
| Cumulative\teffect\tof\tchange\tin\taccounting\tprinciple | (0.65) | — | — | — | — |
| Basic\t(loss)\tearnings\tper\tshare | $(6.51) | $0.52 | $1.66 | $0.84 | $1.11 |
| Diluted\t(loss)\tearnings\tper\tshare: |  |  |  |  |  |
| (Loss)\tincome\tfrom\tcontinuing\toperations | $(4.81) | $0.83 | $1.61 | $0.84 | $1.10 |
| Discontinued\toperations | (1.05) | (0.32) | (0.02) | (0.02) | (0.03) |
| Cumulative\teffect\tof\tchange\tin\taccounting\tprinciple | (0.65) | — | — | — | — |
| Diluted\t(loss)\tearnings\tper\tshare | $(6.51) | $0.51 | $1.59 | $0.82 | $1.07 |

|  | 2002 | 2001 | 2000 | 1999 | 1998 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (in\tmillions) |  |  |
| Balance\tSheet\tData: |  |  |  |  |  |
| Total\tassets | $33,776 | $36,812 | $33,038 | $23,222 | $12,900 |
| Non-recourse\tdebt\t(long-term) | 10,928 | 11,515 | 9,456 | 6,086 | 4,448 |
| Non-recourse\tdebt\t(long-term)—Discontinued\toperations | 3,243 | 1,034 | 3,407 | 3,435 | 57 |
| Recourse\tdebt\t(long-term) | 5,778 | 4,913 | 3,458 | 2,167 | 1,644 |
| Mandatorily\tredeemable\tpreferred\tstock\tof\tsubsidiary | 22 | 22 | 22 | 22 | — |
| Company\tobligated\tconvertible\tmandatorily\tredeemable\tpreferred |  |  |  |  |  |
| securities\tof\tsubsidiary\ttrust\tholding\tsolely\tjunior\tsubordinated |  |  |  |  |  |
| debentures\tof\tAES | 978 | 978 | 1,228 | 1,318 | 550 |
| Stockholders'\t(deficit)\tequity | (341) | 5,539 | 5,542 | 3,315 | 2,368 |

# 								Item	7—Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations

In	December	2002,	AES	completed	a	$2.1	billion	refinancing	of	certain	bank	loans	and	debt	securities	by	entering	into	new	$1.6	billion	senior	secured	credit	facilities and	completing	an	exchange	offer	relating	to	$500	million	of	outstanding	debt	securities.	The	refinancing	substantially	eliminates	all	scheduled	parent	debt	maturities until	November	2004.	The	$1.6	billion	senior	secured	credit	facilities	are	comprised	of	a	$350	million	senior	secured	revolving	credit	facility,	three	tranches	of	term	loan facilities	totaling	approximately	$1.2	billion	and	a	£52.25	million	letter	of	credit.	In	the	exchange	offer	the	Company	issued	approximately	$258	million	aggregate principal	amount	of	its	10%	senior	secured	notes	with	certain	mandatory	redemption	provisions.	The	senior	secured	credit	facilities	and	the	senior	secured	notes	are scheduled	to	mature	in	the	second	half	of	2005.	Certain	of	the	Company's	obligations	under	the	senior	secured	credit	facilities	are	guaranteed	by	some	of	its	domestic subsidiaries.	The	Company's	obligations	under	the	senior	secured	credit	facilities	are,	subject	to	certain	exceptions,	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	us	and	65%	of	the	capital	stock	of	certain	foreign	subsidiaries	owned directly	or	indirectly	by	AES	and	(ii)	certain	intercompany	receivables,	certain	intercompany	notes	and	certain	intercompany	tax	sharing	agreements	owed	to	AES	by	its subsidiaries.	On	March	14,	2003,	the	Company	launched	a	consent	solicitation	seeking	to	change	the	definition	of	"Material	Subsidiary"	and	amend	certain	other provisions	of	its	outstanding	senior	and	senior	subordinated	notes	to	conform	those	provisions	to	the	provisions	in	its	10%	senior	secured	notes.	We	cannot	assure	you that	the	consent	solicitation	will	be	successful.

AES	has	announced	a	number	of	strategic	initiatives	designed	to	decrease	its	dependence	on	access	to	the	capital	markets,	strengthen	its	balance	sheet,	reduce	the financial	leverage	at	the	parent	company	and	improve	short-term	liquidity.	One	of	these	initiatives	involves	the	sale	of	all	or	part	of	certain	of	the	Company's subsidiaries.	During	2002,	the	Company	announced	agreements	to	sell	AES	NewEnergy,	CILCORP,	AES	Mt.	Stuart,	and	AES	Ecogen	for	net	equity	proceeds	of approximately	$819	million.	The	NewEnergy	transaction	closed	in	September	2002,	CILCORP	and	AES	Mt.	Stuart	closed	in	January	2003	and	AES	Ecogen	closed	in February	2003.	Additionally,	the	Company	has	reached	agreements	to	sell	100%	of	Songas	Limited	and	AES	Kelvin	(Pty.)	Ltd,	two	generation	businesses	in	Africa,	for net	equity	proceeds	of	approximately	$116	million.	These	transactions	are	expected	to	close	in	early	or	mid-2003.	In	January	2003,	the	Company	announced	the	sale	of Mountainview	for	$30	million	with	another	$20	million	payment	contingent	on	the	achievement	of	project	specific	milestones.	This	transaction	closed	in	March	2003. Additionally,	the	Company	announced	in	March	2003,	agreements	to	sell	100%	of	its	ownership	interest	in	two	generation	businesses	in	Bangladesh	(AES	Haripur Private	Limited	("Haripur")	and	AES	Meghnaghat	Limited	("Meghnaghat"))	and	32%	of	its	ownership	interest	in	AES	Oasis	Limited	("AES	Oasis"),	which	includes	two electric	generation	development	projects	and	desalination	plants	in	Oman	and	Qatar	(AES	Barka	and	AES	Ras	Laffan,	respectively),	and	the	oil-fired	generating facilities,	AES	LalPir	and	AES	PakGen	in	Pakistan.	Proceeds	from	the	sales	of	Haripur	and	Meghnaghat	are	expected	to	be	approximately	$127	million	in	cash	plus

assumption	of	debt,	subject	to	certain	closing	adjustments.	Cash	proceeds	from	the	sale	of	the	minority	interest	in	AES	Oasis	will	be	approximately	$150	million. Completion	of	this	sale	is	subject	to	certain	conditions,	including	government	and	lender	approvals.

The	Company	continues	to	evaluate	which	additional	businesses	it	may	sell.	However,	there	can	be	no	guarantee	that	the	proceeds	from	such	sales	transactions	will cover	the	entire	investment	in	such	subsidiaries.	Additionally,	depending	on	which	businesses	are	eventually	sold,	the	entire	or	partial	sale	of	any	subsidiaries	may change	the	current	financial	characteristics	of	the	Company's	portfolio	and	results	of	operations,	and	in	the	future	may	impact	the	amount	of	recurring	earnings	and	cash flows	the	Company	would	expect	to	achieve.

In	July,	2002	the	Company	established	a	Restructuring	Office,	formerly	referred	to	as	the	Turnaround	Office,	to	focus	on	improving	the	operating	and	financial performance	of,	selling	or	abandoning	certain	of	its	underperforming	businesses.	Businesses	are	considered	to	be	underperforming	if	they	do	not	meet	the	Company's internal	rate	of	return	criteria,	among	other	factors.	The	Restructuring	Office	is	actively	managing	Drax,	Barry,	Gener,	the	Company's	businesses	within	the	Dominican Republic	and	the	Company's	Argentine	businesses,	as	well	as	evaluating	Sul,	Uruguaiana,	Telasi,	Eletropaulo,	CEMIG	and	certain	development	projects.	The	Company is	evaluating	whether	the	profitability	and	cash	flows	of	such	businesses	can	be	sufficiently	improved	to	achieve	acceptable	returns	on	the	Company's	investment,	or whether	such	businesses	should	be	disposed	of	or	sold.	If	the	Company	determines	that	certain	businesses	are	to	be	sold	or	otherwise	disposed	of,	there	can	be	no guarantee	that	the	proceeds	from	such	transactions	would	cover	the	Company's	entire	investment	in	such	subsidiaries	or	that	such	proceeds	will	be	available	to	the Company.	It	is	possible	that	the	restructuring	efforts	will	change	the	ownership	structure	or	the	manner	in	which	a	business	operates,	and	these	efforts	may	result	in	an impairment	charge	if	the	Company	is	not	able	to	recover	its	investment	in	such	business.	In	2002	the	Company	took	after-tax	charges	of	approximately	$465	million	on investments	in	certain	development	and	construction	projects,	$301	million	on	businesses	classified	as	discontinued	operations,	and	$2.3	billion	of	asset	impairment charges	at	Drax,	Barry,	Eletropaulo	and	CEMIG.	The	inability	of	the	Company	to	successfully	restructure	the	underperforming	businesses	may	result	in	less	earnings and	cash	flows	in	2003	and	beyond.

# Additional	Developments

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	effective	January	1,	2002.	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	experienced	a	significant	devaluation	relative	to	the	U.S.	dollar	during	2002.	The	Company	recorded	foreign currency	transaction	losses	on	the	U.S.	dollar	denominated	net	liabilities	of	its	Argentine	subsidiaries	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	total	investment	in	the	competitive	supply	business	in	Argentina	was	approximately	$141	million	and	the	total	investment	in	the	growth	distribution	business was	approximately	negative	$61	million.	These	investment	amounts	are	net	of	foreign	currency	translation	losses.

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.

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	2002,	the	Brazilian	Real	experienced	a	significant	devaluation	relative	to	the	U.S.	dollar,	declining	from	2.41	Reais	to	the	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	U.S.	dollar	at	December	31,	2001.	This	continued	devaluation	resulted	in significant	foreign	currency	translation	and	transaction	losses,	particularly	during	2002	and	2001.	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	net	liabilities	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 earnings	of	affiliates	in	the	accompanying	consolidated	statements	of	operations	since	Eletropaulo	was	accounted	for	as	an	equity	method	investment	during	those	years. Further	devaluation	of	the	Brazilian	Real	will	continue	to	have	a	negative	impact	on	the	Company's	results	of	operations.

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.

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.

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.

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	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	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.	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 Participaçoes	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,	Sul	and	Uruguaiana.	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	the	fourth	quarter	of	2001. 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.

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.	Currently,	ten	companies	are	under	the	tariff reset	public	hearing	process,	including	Sul.	These	results	are	likely	to	influence	Eletropaulo's	tariff	reset.

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.

At	December	31,	2002,	EDC	was	not	in	compliance	with	two	of	its	net	worth	covenants	on	$131	million	and	$9	million	of	non-recourse	debt	primarily	due	to	the	impact of	the	devaluation	of	the	Venezuelan	Bolivar.	EDC	requested	and	received	from	its	lenders	waivers	for	both	covenants,	which	are	effective	through	March	31,	2003.	Of the	related	debt,	approximately	$102	million	is	classified	as	non-recourse	debt—long	term	in	the	accompanying	consolidated	balance	sheets.	The	remainder	is	classified as	non-recourse	debt—current.

Drax	a	subsidiary	of	AES,	is	the	operator	of	the	Drax	Power	Plant,	Britain's	largest	power	station.	On	November	14,	2002,	TXU	Europe	Energy	Trading	Limited	("TXU EET")	was	required	to	make	a	£49	million	payment	to	Drax	for	power	purchased	in	October	under	the	hedging	contract	("Hedging	Agreement")	between	Drax	and	TXU EET.	TXU	EET	failed	to	make	the	payment,	and	attempts	to	negotiate	a	solution	acceptable	to	both	parties	proved	unsuccessful.	On	November	18,	2002,	Drax terminated	the	Hedging	Agreement,	with	immediate	effect,	on	the	grounds	of	TXU	EET's	failure	to	provide	the	credit	support	of	approximately	£270	million	required under	the	terms	of	the	Hedging	Agreement.	On	November	19,	2002,	TXU	EET	and	certain	other	entities	including	the	guarantor	of	the	Hedging	Agreement,	TXU

Europe	Group	plc	("TXU	Group"),	were	placed	into	administration.	Following	termination	of	the	Hedging	Agreement,	and	the	placing	of	TXU	EET	and	TXU	Group into	administration,	Drax	has	been	working	cooperatively	with	its	lenders	to	address	the	liquidity	needs	of	the	project,	including	letters	of	credit	required	to	support trading	Drax's	output	in	the	open	market.	Drax	has	submitted	a	claim	for	capacity	damages	of	approximately	£266	million	in	accordance	with	the	terms	of	the	Hedging Agreement	as	well	as	a	claim	of	approximately	£85	million	for	unpaid	electricity	delivered	in	October	and	November.	The	Hedging	Agreement	accounted	for approximately	60%	of	the	revenues	generated	by	Drax	and	payments	under	this	agreement	were	significantly	higher	than	Drax	is	currently	receiving	in	the	open	market. As	a	result	of	the	termination	of	the	Hedging	Agreement,	the	Company	recorded	an	after-tax	impairment	loss	of	approximately	$893	million	in	the	fourth	quarter	of 2002.	Drax	is	classified	as	held	for	sale	in	the	accompanying	consolidated	balance	sheets.	On	December	13,	2002,	Drax	signed	a	standstill	agreement	with	its	senior lenders	to	provide	Drax	time	to	restructure	its	business	after	the	termination	of	the	Hedging	Agreement.	The	standstill	agreement	provides	temporary	and/or	permanent waivers	by	the	senior	lenders	of	defaults	that	have	occurred	or	could	occur	up	to	the	expiry	of	the	standstill	period	on	May	31,	2003	including	a	permanent	waiver resulting	from	termination	of	the	Hedging	Agreement.

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	at	that	time.	Drax	expects	that	the	ratios,	if	calculated	as	of	December	31,	2002,	would	again	be	below	the	required	levels	at	December	31,	2002	since	any improvement	in	the	ratios	for	the	period	ended	December	31,	2002	would	have	required	a	favorable	change	in	the	forward	curve	for	electricity	prices	during	the	period from	June	30,	2002	to	December	31,	2002	and	such	favorable	change	did	not	occur.	As	part	of	the	standstill	agreement	signed	by	the	Drax	entities	and	its	senior	lenders, the	debt	service	coverage	ratios	as	of	December	31,	2002	were	not	calculated	by	the	bank	group.	As	a	consequence	of	the	foregoing,	Drax	was	not	permitted	to	make	any distributions	to	Drax	Energy,	the	holding	company	high-yield	note	issuer.	As	a	result,	Drax	Energy	was	unable	to	make	the	full	amount	of	the	interest	payment	of $11.5	million	and	£7.6	million	due	on	its	high-yield	notes	on	February	28,	2003.	Drax	Energy's	failure	to	make	the	full	amount	of	the	required	interest	payment constitutes	an	event	of	default	under	its	high-yield	notes,	although	pursuant	to	intercreditor	agreements	the	holders	of	the	high-yield	notes	have	no	enforcement	rights until	90	days	following	the	delivery	of	certain	notices	under	the	intercreditor	arrangements.	Drax	is	currently	a	material	subsidiary	for	certain	bankruptcy-related	events of	default

contained	in	AES's	parent	company	indebtedness,	and	therefore	certain	bankruptcy	events	of	Drax	could	result	in	a	default	under	our	corporate	debt	agreements.

On	September	30,	2002,	Barry	entered	into	a	tolling	agreement	with	TXU	EET	and	an	associated	guarantee	agreement	(subject	to	a	cap)	with	TXU	Group.	On November	19,	2002,	TXU	EET	and	certain	other	entities	including	TXU	Group	were	placed	into	administration,	and	Barry	subsequently	terminated	the	tolling agreement	on	November	26,	2002	on	the	grounds	of	insolvency	of	TXU	EET	and	TXU	Group.	As	a	result	of	the	termination	of	the	tolling	agreement,	the	Company recorded	an	after-tax	impairment	loss	of	approximately	$120	million	in	the	fourth	quarter	of	2002.	On	December	20,	2002,	Barry	signed	a	standstill	agreement	with	its senior	lenders	to	provide	time	for	Barry	to	investigate	the	options	available	to	restructure	the	business.	The	standstill	agreement	provides	waivers	by	the	senior	lenders	of certain	defaults	that	have	occurred	or	could	occur	up	to	the	expiry	of	the	standstill	period	on	March	31,	2003.

# Reporting	Segments

The	AES	Corporation	(including	all	its	subsidiaries	and	affiliates,	and	collectively	referred	to	herein	as	"AES"	or	the	"Company"	or	"we"),	founded	in	1981,	is	a	leading global	power	company.	The	Company's	goal	is	to	help	meet	the	world's	need	for	electric	power	in	ways	that	benefit	all	of	our	stakeholders,	to	build	long-term	value	for the	Company's	shareholders,	and	to	assure	sustained	performance	and	viability	of	the	Company	for	its	owners,	employees	and	other	individuals	and	organizations	who depend	on	the	Company.	AES	participates	primarily	in	four	lines	of	business:	large	utilities,	growth	distribution,	contract	generation	and	competitive	supply.

AES's	large	utility	business	is	comprised	of	three	utilities	located	in	the	U.S.	(IPALCO),	Brazil	(Eletropaulo),	and	Venezuela	(EDC).	AES's	equity	interest	in	each	of these	utilities	is	over	70%.	All	of	these	utilities	are	of	significant	size,	and	all	maintain	a	monopoly	franchise	within	a	defined	service	area.	In	most	cases	large	utilities combine	generation,	transmission	and	distribution	capabilities.	Large	utilities	are	subject	to	extensive	local,	state	and	national	regulation	relating	to	ownership, marketing,	delivery	and	pricing	of	electricity	and	gas	with	a	focus	on	protecting	customers.	Large	utility	revenues	result	primarily	from	electricity	sales	to	customers under	regulated	tariff	or	concession	agreements	and	to	a	lesser	extent	from	contractual	agreements	of	varying	lengths	and	provisions.	The	results	of	operations	of	the Company's	large	utility	businesses	are	sensitive	to	changes	in	economic	growth,	abnormal	weather	conditions	affecting	their	markets,	and	regulatory	changes.

AES's	growth	distribution	line	of	business	includes	distribution	facilities	located	in	developing	countries	or	regions	where	the	demand	for	electricity	is	expected	to	grow at	a	higher	rate	than	in	more	developed	parts	of	the	world.	However,	these	businesses	face	particular	challenges	associated	with	their	presence	in	developing	countries such	as	outdated	equipment,	significant	theft-related	losses,	cultural	problems	associated	with	safety	and	non-payment,	emerging	economies	and	potentially	less	stable governments	or	regulatory	regimes.	Often	however,	the	conditions	of	the	business	environment	in	a	developing	nation	also	provide	for	significant	opportunities	to implement	operating	improvements	that	may	stimulate	growth	in	earnings	and	cash	flow	performance	at	rates	greater	than	those	typically	achievable	in	AES's	large utility	segment.	Distribution	facilities	included	in	this	line	of	business	may	include	integrated	generation,	transmission,	distribution	or	related	services	companies.	The results	of	operations	of	the	Company's	growth	distribution	business	are	sensitive	to	changes	in	economic	growth,	abnormal	weather	conditions	affecting	their	market	and regulatory	changes.

AES's	contract	generation	line	of	business	consists	of	multiple	power	generation	facilities	located	around	the	world.	Provided	the	counterparty's	credit	remains	viable, these	facilities	have	contractually	limited	their	exposure	to	commodity	price	risks,	primarily	electricity	prices.	These	facilities	generally	limit	their	exposure	to	electricity price	volatility	by	entering	into	long-term	(five	years	or	longer)	power	purchase	agreements	for	75%	or	more	of	their	output	capacity.	Because	they	have	contracted	for	a majority	of	their	anticipated	output,	they	are	able	to	project	their	fuel	supply	requirements	and	also,	generally,	enter	into	long-term	agreements	for	most	of	their	fuel (coal,	natural	gas	or	fuel	oil	or	other	similar	fuel)	supply	requirements,	thereby	also	limiting	their	exposure	to	fuel	price	volatility.	Through	these	contractual	agreements, the	businesses	generally	increase	the	predictability	of	their	cash	flows	and	earnings.	In	order	to	meet	AES's	definition	of	its	contract	generation	segment,	long-term power	purchase	agreements	have	minimum	initial	durations	of	five	years	or	longer	and	are	typically	entered	into	with	one	major	customer,	but	may	also	be	with	a	series of	unrelated	customers.	In	addition,	AES	may	enter	into	tolling	or	"pass	through"	arrangements	whereby	the	counterparty	directly	assumes	the	risks	associated	with providing	the	necessary	fuel	and	markets	the	resulting	power	output	generated.	However,	not	all	businesses	within	AES's	contract	generation	line	of	business	have	the same	degree	of	contractually	limited	exposure,	and	therefore,	the	degree	of	predictability	may	vary	from	business	to	business.

For	instance,	with	Gener,	the	Company's	contract	generation	business	in	Chile,	the	price	for	electricity	received	under	its	electricity	sales	contracts	is	impacted	by decisions	of	the	regulatory	authorities	in	Chile	that	establish	prices	known	as	"node	prices"	every	six	months	to	be	paid	by	distribution	companies	for	the	energy	and capacity	requirements	of	regulated	customers.	Node	prices	for	energy	are	calculated	on	the	basis	of	the	projections	of	the	expected	marginal	costs	within	the	system. Node	prices	for	capacity	are	calculated	based	on	the	marginal	investment	required	to	meet	peak	demand,	based	on	the	cost	of	a	diesel-fired	turbine.	The	prices	for	energy and	capacity	sold	on	a	contractual	basis	in	Chile	are	generally	set	with	reference	to	those	node	prices.	This	administratively-determined	pricing	mechanism	has	more volatility	than	other	contractual	arrangements	where	the	price	for	electricity	is	not	subject	to	similar	adjustment.

Certain	of	the	Company's	contract	generation	customers	are	regulated	utilities	that	are	regulated	by	PUCs.	PUCs	often	restrict	the	amount	of	debt	those	utilities	are permitted	to	incur,	as	well	as	the	types	of	business	activities	in	which	they	participate.	This	generally	results	in	a	stronger	customer	credit	quality.

Two	of	these	types	of	customers,	at	the	Company's	Warrior	Run	and	Beaver	Valley	plants,	are	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	three	subsidiaries	is 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.

AES's	competitive	supply	line	of	business	consists	of	generating	facilities	that	sell	electricity	directly	to	wholesale	customers	in	competitive	markets.	Additionally,	as compared	to	the	contract	generation	segment	discussed	above,	these	generating	facilities	generally	sell	less	than	75%	of	their	output	pursuant	to	long-term	contracts	with pre-determined	pricing	provisions	and/or	sell	into	power	pools,	under	shorter-term	contracts	or	into	daily	spot	markets.	The	prices	paid	for	electricity	under	short-term contracts	and	in	the	spot	markets	are	unpredictable	and	can	be,	and	from	time	to	time	have	been,	volatile.	The	results	of	operations	of	AES's	competitive	supply	business are	also	more	sensitive	to	the	impact	of	market	fluctuations	in	the	price	of	electricity,	natural	gas,	coal	and	other	raw	materials.	In	the	United	Kingdom,	TXU	Europe entered	administration	in	November	2002	and	is	no	longer	performing	under	its	contracts	with	Drax	and	Barry.	As	described	in	the	footnotes	and	in	other	sections	of	the Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations,	TXU	Europe's	failure	to	perform	under	its	contracts	has	had	a	material	adverse	effect	on	the results	of	operations	of	these	businesses.

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,	L.P.'s	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.

The	revenues	from	our	facilities	that	distribute	electricity	to	end-use	customers	are	generally	subject	to	regulation.	These	businesses	are	generally	required	to	obtain	third party	approval	or	confirmation	of	rate	increases	before	they	can	be	passed	on	to	the	customers	through	tariffs.	These	businesses	comprise	the	large	utilities	and	growth distribution	segments	of	the	Company.	Revenues	from	contract	generation	and	competitive	supply	are	not	regulated.

The	distribution	of	revenues	between	the	segments	for	the	years	ended	December	31,	2002,	2001	and	2000	is	as	follows:

| Large	utilities | 36% | 21% | 22% |
| :--- | :--- | :--- | :--- |
| Growth\tdistribution | 14% | 21% | 21% |
| Contract\tgeneration | 29% | 32% | 27% |
| Competitive\tsupply | 21% | 26% | 30% |

# Development	Costs

Certain	subsidiaries	and	affiliates	of	the	Company	(domestic	and	non-U.S.)	are	in	various	stages	of	developing	and	constructing	greenfield	power	plants,	some	but	not all	of	which	have	signed	long-term	contracts	or	made	similar	arrangements	for	the	sale	of	electricity.	Successful	completion	depends	upon	overcoming	substantial	risks, including,	but	not	limited	to,	risks	relating	to	failures	of	siting,	financing,	construction,	permitting,	governmental	approvals	or	the	potential	for	termination	of	the	power sales	contract	as	a	result	of	a	failure	to	meet	certain	milestones.	As	of	December	31,	2002,	capitalized	costs	for	projects	under	development	and	in	early	stage construction	were	approximately	$15	million	and	capitalized	costs	for	projects	under	construction	were	approximately	$3.2	billion.	The	Company	believes

that	these	costs	are	recoverable;	however,	no	assurance	can	be	given	that	individual	projects	will	be	completed	and	reach	commercial	operation.

During	2002,	the	Company	took	an	after-tax	charge	of	approximately	$465	million	to	write	off	its	investments	in	certain	development	projects	including	AES	Lake Worth	("Lake	Worth"),	AES	Greystone,	LLC	("Greystone")	and	Mountainview.

Lake	Worth	is	a	210	megawatt	gas-fired	power	plant	currently	under	construction	in	Florida.	In	the	fourth	quarter	of	2002,	circumstances	surrounding	the	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	value.	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,	Greystone	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.

Mountainview	consists	of	a	completed	126	megawatt	gas-fired	power	plant	and	a	1,056	megawatt	gas-fired	power	plant	under	construction	in	California.	In December	2002,	AES	classified	its	investments	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.

Derivatives	and	Energy	Trading	Activities

The	Company	utilizes	derivative	financial	instruments	to	manage	interest	rate	risk,	foreign	exchange	risk	and	commodity	price	risk.	Although	the	majority	of	the Company's	derivative	instruments	qualify	for	hedge	accounting,	the	adoption	of	SFAS	No.	133	in	2001	has	resulted	in	more	variation	to	the	Company's	results	of operations	from	changes	in	interest	rates,	foreign	exchange	rates	and	commodity	prices.	For	the	year	ended	December	31,	2002,	the	Company	recognized	$42	million	of gains,	net	of	income	taxes,	primarily	related	to	derivatives	which	did	not	qualify	for	hedge	accounting.	See	Note	10	to	the	consolidated	financial	statements	which provides	a	more	complete	discussion	of	the	Company's	accounting	for	derivatives.

The	Company	does	not	engage	in	significant	energy	trading	activities	associated	with	its	retail	and	wholesale	supply	businesses.	For	the	years	ended	December	31,	2002, 2001	and	2000,	the	Company	recorded	net	gains	from	energy	trading	activities	of	$0	million,	$5	million	and	$21	million,	respectively.

# Related	Party	Transactions

The	Company	did	not	enter	into	any	related	party	transactions	that	were	material	for	financial	reporting	purposes	during	the	years	ended	December	31,	2002,	2001	and 2000.

# Pension	Plans

Certain	foreign	and	domestic	subsidiaries	of	the	Company	maintain	defined	benefit	pension	plans	(the	"Pension	Plans",	or	the	"Plans")	covering	substantially	all	of	their respective	employees.	Pension	benefits	are	generally	based	on	years	of	credited	service,	age	of	the	participant	and	average	earnings.	Of	the	thirteen	Pension	Plans existing	at	December	31,	2002,	three	are	at	domestic	subsidiaries	and	ten	are	at	foreign	subsidiaries.	These	exclude	one	domestic	Plan	and	one	foreign	Plan	maintained at	businesses	classified	as	held	for	sale	or	discontinued	operations	during	2002.

Two	defined	benefit	pension	plans	constitute	85%	of	pension	cost	for	the	year	ended	December	31,	2002,	89%	of	the	benefit	obligation	at	December	31,	2002	and	86% of	the	fair	value	at	December	31,	2002.	One	plan	is	a	plan	administered	in	the	United	States	(the	"US	Plan")	and	the	other	plan	is	administered	in	Brazil	(the	"Brazilian Plan").	Of	the	remaining	plans,	no	one	plan	represents	a	significant	portion	of	the	pension	cost,	benefit	obligation	or	fair	value	at	December	31,	2002.

Pension	cost	for	the	US	Plan	is	calculated	based	upon	a	number	of	actuarial	assumptions,	including	an	expected	long-term	rate	of	return	on	plan	assets	of	9%	in	2002 and	2001	and	8%	in	2000.	In	developing	our	expected	long-term	rate	of	return	assumption,	we	evaluated	input	from	our	actuaries,	including	their	review	of	asset	class return	expectations	by	several	respected	consultants	and	economists,	as	well	as	long-term	inflation	assumptions.	Projected	returns	by	such	consultants	and	economists are	selected	from	within	the	"best	estimate	range",	which	is	the	smallest	range	which	the	actuary	reasonably	anticipates	that	the	actual	results,	compounded	over	the measurement	period,	are	more	likely	to	fall	than	not.	The	best	estimate	of	this	range	is	based	on	asset	class	return	expectations	which	reflect	historical	data	as	well	as	the opinion	of	several	consultants	and	economists	about	the	forecasted	returns	of	each	class.	The	best	estimate	range	is	a	probability	distribution	of	returns	that	spans	the 25 th 	to	75 	percentiles	of	20-year	returns.	It	is	anticipated	that	our	investment	managers	will	continue	to	generate	long-term	returns	of	at	least	9%.	Our	expected	long- th term	rate	of	return	on	plan	assets	is	based	on	an	asset	allocation	assumption	of	45%	U.S.	equities,	10%	non-U.S.	equities,	40%	fixed	income	and	5%	real	estate	which	is equal	to	our	actual	asset	allocation.	We	continue	to	believe	that	9%	is	a	reasonable	long-term	rate	of	return	on	our	plan	assets.	We	will	continue	to	evaluate	our	actuarial assumptions,	including	our	expected	rate	of	return,	at	least	annually,	and	will	adjust	as	necessary.

The	US	Plan	bases	its	determination	of	pension	expense	or	income	on	the	fair	value	of	assets	on	the	measurement	date.	As	of	December	31,	2002,	the	US	Plan	has generated	cumulative	unrecognized	net	actuarial	losses	of	approximately	$91	million	which	remain	to	be	recognized	in	pension	cost.	These	unrecognized	net	actuarial losses	result	in	decreases	in	future	pension	income	depending	on	several	factors,	including	whether	such	losses	at	each	measurement	date	exceed	10%	of	the	greater	of the	projected	benefit	obligation	or	the	market-related	value	of	plan	assets	in	accordance	with	SFAS	No.	87,	"Employers	Accounting	for	Pensions".

The	discount	rate	used	for	determining	future	pension	obligations	for	the	US	Plan	is	based	upon	the	Aa	rated	annual	yield	as	of	the	measurement	date	as	published	in	the Moody's	Daily	Long-term	Corporate	Bond	Yields	based	on	bonds	with	maturities	of	20	years	and	above.	The	discount	rates	determined	using	this	basis	were	6.75%	in 2002,	7.25%	in	2001,	and	8.00%	in	2000.

Lowering	the	expected	long-term	rate	of	return	on	the	US	Plan	assets	by	1.0%	would	have	increased	our	2002	pension	cost	by	approximately	$2.5	million.	Lowering	the discount	rate	by	100	basis	points	would	increase	our	2002	pension	cost	by	approximately	$2.8	million.

The	fair	value	of	the	US	Plan's	assets	has	decreased	to	$224	million	at	December	31,	2002	from	$257	million	at	December	31,	2001.	The	investment	performance returns	and	benefits	paid	during	2002	has	increased	the	underfunded	position,	net	of	benefit	obligations,	of	the	US	Plan	from	$127	million	at	December	31,	2001	to	$187 million	at	December	31,	2002.

The	Brazilian	Plan	began	to	be	reported	on	a	consolidated	basis	when	the	acquisition	of	an	additional	ownership	interest	in	Eletropaulo	occurred	in	February	2002. Pension	cost	for	the	Brazilian	Plan	is	calculated	based	upon	a	number	of	actuarial	assumptions,	including	an	expected	long-term	rate	of	return	on	plan	assets	of	15%	in 2002.	In	developing	our	expected	long-term	rate	of	return	assumption,	we	evaluated	input	from	our	actuaries,	including	their	review	of	asset	class	return	expectations which	are	based	on	studies	of	historical	data	series	as	well	as	the	opinion	of	several	respected	consultants	and	economists	about	forecasts,	long-term	inflation assumptions,	dollar	spot	assumptions	and	local	interest	rate	assumptions.	Each	asset	class	return	expectation	is	based	upon	historical	returns	for	assets	with	similar maturities	and	risk.	It	is	anticipated	that	our	investment	managers	will	continue	to	generate	long-term	returns	of	at	least	15%.	Over	the	past	seven	years,	the	Brazilian Plan	has	had	actual	returns	of	18%.	Our	expected	long-term	rate	of	return	on	plan	assets	is	based	on	an	asset	allocation	assumption	of	83%	fixed	income	investments, 12%	equities	and	5%	real	estate.	Our	assumed	asset	allocation	uses	a	lower	exposure	to	equities	to	more	closely	match	market	conditions	and	near-term	forecasts.	We will	continue	to	evaluate	our	actuarial	assumptions,	including	our	expected	rate	of	return,	at	least	annually,	and	will	adjust	as	necessary.

The	Brazilian	Plan	bases	its	determination	of	pension	expense	or	income	on	the	fair	value	of	assets	on	the	measurement	date.	As	of	December	31,	2002,	the	Brazilian Plan	has	generated	cumulative	unrecognized	net	actuarial	losses	of	approximately	$562	million	which	remain	to	be	recognized	in	pension	cost.	These	unrecognized	net actuarial	losses	result	in	decreases	in	future	pension	income	depending	on	several	factors,	including	whether	such	losses	at	each	measurement	date	exceed	10%	of	the greater	of	the	projected	benefit	obligation	or	the	market-related	value	of	plan	assets	in	accordance	with	SFAS	No.	87,	"Employers	Accounting	for	Pensions".

The	discount	rate	used	for	determining	future	pension	obligations	for	the	Brazilian	Plan	is	based	on	long-term	annuity	contracts	since	there	is	no	active	corporate	bond market	in	Brazil.	The	discount	rate	determined	on	this	basis	is	9%	for	2002.

Lowering	the	expected	long-term	rate	of	return	on	our	Plan	assets	by	1.0%	would	have	increased	our	2002	pension	cost	by	approximately	$6.5	million.	Lowering	the discount	rate	by	100	basis	points	would	increase	our	2002	pension	cost	by	approximately	$12	million.

The	fair	value	of	the	Brazilian	Plan	assets	is	$642	million	at	December	31,	2002.	The	Brazilian	Plan	has	an	underfunded	position,	net	of	benefit	obligations,	of	$969 million	at	December	31,	2002.

Annually,	we	review	all	Pension	Plans	to	determine	if	the	Plans'	accumulated	benefit	obligations	exceed	the	fair	value	of	the	Plans'	assets.	If	the	accumulated	benefit obligations	exceed	the	fair	value	of	plan	assets,	an	additional	minimum	pension	liability	is	recorded	on	the	balance	sheet,	with	a	corresponding	charge	to	other comprehensive	income.	We	may	incur	additional	minimum	pension	liabilities	in	future	periods	and	they	could	be	material.

# Significant	Accounting	Policies

AES	prepares	its	consolidated	financial	statements	in	accordance	with	accounting	principles	generally	accepted	in	the	U.S.	As	such,	it	is	required	to	make	certain estimates,	judgments	and	assumptions	that	it	believes	are	reasonable	based	upon	the	information	available.	These	estimates	and	assumptions	affect	the	reported	amounts of	assets	and	liabilities	at	the	date	of	the	financial	statements	and	the	reported	amounts	of	revenues	and	expenses	during	the	periods	presented.	The	significant accounting	policies	which	AES	believes	are	most	critical	to	understanding	and	evaluating	its	reported	financial	results	include	those	pertaining	to	the	following: Property,	Plant	and	Equipment;	Long-Lived	Assets;	Functional	Currency	Determination;	Regulatory	Assets	and	Contingencies.

# Property,	Plant	and	Equipment

Property,	plant	and	equipment	is	recorded	at	cost	and	is	depreciated	over	its	estimated	useful	life.	The	estimated	useful	lives	of	AES's	generation	and	distribution facilities	range	from	10	to	50	years.	A	significant	decrease	in	the	estimated	useful	life	of	a	material	amount	of	property,	plant	and	equipment	could	have	a	material adverse	impact	on	our	operating	results	in	the	period	in	which	the	estimate	is	revised	and	subsequent	periods.	The	loss	of	a	long-term	contract	and	the	inability	to	replace it	at	one	of	our	contract	generation	businesses	or	a	significant	overabundance	of	supply	and	a	sustained,	significant	decline	in	market	prices	in	the	regions	served	by	our competitive	supply	businesses	could	cause	us	to	decrease	the	estimated	useful	life	of	our	impacted	generation	facilities.	The	loss	of	a	long-term	concession	agreement and	the	inability	to	replace	it	at	one	of	our	growth	distribution	businesses	or	large	utilities	could	cause	us	to	decrease	the	estimated	useful	life	of	our	impacted distribution	facilities.	Additionally,	significant	physical	damage	or	a	significant	mechanical	failure	may	cause	us	to	decrease	the	estimated	useful	life	of	the	affected property,	plant	and	equipment.	If	the	useful	life	of	any	of	our	property,	plant	and	equipment	is	changed,	the	new	life	would	be	based	on	engineering	studies	and	expected usage.	The	estimated	average	remaining	useful	life	of	our	property,	plant	and	equipment	is	approximately	23	years.	If	the	estimated	average	remaining	useful	life	of	our property,	plant	and	equipment	decreased	by	5	years,	annual	depreciation	expense	would	increase	by	$220	million.

# Long-Lived	Assets

AES	evaluates	the	impairment	of	its	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.	Estimates	of	future	cash	flows	used	to	test	the	recoverability	of	specific	long-lived	assets	are	based	on	expected cash	flows	from	the	use	and	eventual	disposition	of	the	assets.	AES	has	$8.5	billion	of	long-lived	contract	generation	assets,	and	expected	cash	flows	for	businesses within	the	contract	generation	segment	are	based	on	the	expected	output	of	the	generation	facilities	as	well	as	the	terms	of	our	contractual	agreements.	AES	has $3.2	billion	of	long-lived	competitive	supply	assets,	and	expected	cash	flows	for	businesses	within	the	competitive	supply	segment	are	based	on	the	expected	output	of the	generation	facilities	as	well	as	expected	future	market	prices	as	published	on	industry	forward	curves	and	other	market	price	studies.	AES	has	$6.2	billion	of	large utility	long-lived	assets	and	$1.8	billion	of	growth	distribution	long-lived	assets.	In	determining	expected	cash	flows	for	businesses	within	our	large	utilities	and	growth distribution	segments,	we	consider	historical	experience	as	well	as	future	expectations,	and	the	expected	future	cash	flows	are	based	on	expected	future	tariffs	and expected	future	customer	demand.	A	significant	reduction	in	actual	cash	flows	and	estimated	cash	flows	may	have	a	material	adverse	impact	on	AES's	operating	results and	financial	condition.

# Functional	Currency	Determination

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.	AES's	consolidated	financial	results	are	reported	in	U.S.	dollars	and	include	the	effects	of	translating	the	financial	statements	from	our international	businesses	with	a	functional	currency	different	from	the	U.S.	dollar	to	the	U.S.	dollar.	Assets	and	liabilities	are	translated	at	the	exchange	rate	in	effect	at the	end	of	the	period.	Revenues	and	expenses	are	translated	at	the	average	exchange	rate	for	the	period.	Translation	adjustments	that	result	from	translating	financial statements	into	the	U.S.	dollar	are	not	included	in	determining	net	income	and	are	reported	in	other	comprehensive	income	in	the	equity	section	of	the	consolidated balance	sheet.	Some	of	AES's	businesses	have	foreign	currency	transactions	which	are	transactions	denominated	in	a	currency	other	than	the	business's	functional currency.	A	change	in	exchange	rates	between	the	functional	currency	and	the	currency	in	which	the	transaction	is	denominated	results	in	a	foreign	currency	transaction gain	or	loss	that	is	included	in	the	determination	of	net	income.	If	facts	and	circumstances	require	a	change	in	the	functional	currency	of	a	significant

subsidiary,	the	change	in	functional	currency	could	have	a	material	impact	on	AES's	operating	results	and	financial	condition.	A	change	in	the	commercial	contracts	of	a business	which	resulted	in	indexation	of	revenues	and	expenses	to	a	currency	other	than	the	local	currency	of	the	business	would	require	us	to	evaluate	the	appropriate functional	currency	for	that	respective	business.	Additionally,	a	significant	change	in	the	denomination	of	the	financing	and	the	availability	of	cash	flows	for	remittance to	the	parent	would	require	us	to	evaluate	the	appropriate	functional	currency	for	that	respective	business.

# Regulatory	Assets

AES	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.	The	Company's	expectation	that	it	will	be	able	to	recover	the	costs	is based	upon	the	regulation	within	the	regions	in	which	we	operate	as	well	as	precedent.	The	assets	are	recovered	when	AES	collects	the	related	costs	through	billings	to customers.	AES	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	$11	million	and	$12	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	AES	are	recorded	in	other assets	on	the	consolidated	balance	sheets.	If	the	regulator	disallows	a	material	amount	of	capitalized	costs	to	be	included	in	future	tariffs,	the	write	off	of	the	regulatory assets	may	have	a	material	adverse	impact	on	AES's	operating	results.

# Contingencies

AES	accrues	for	loss	contingencies	when	the	amount	of	the	loss	is	probable	and	estimable.	Estimates	of	the	probability	and	the	amount	of	loss	are	often	made	in consultation	with	third-party	experts	and	vary	based	on	specific	facts	and	circumstances.	AES	is	subject	to	various	environmental	regulations,	and	is	involved	in	certain legal	proceedings.	If	the	Company's	actual	environmental	and/or	legal	obligations	are	materially	different	from	its	estimates,	the	recognition	of	the	actual	amounts	may have	a	material	impact	on	AES's	operating	results	and	financial	condition.

# 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	SFAS	No.	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.

# RESULTS	OF	OPERATIONS

# 2002	COMPARED	TO	2001	(prior	year	amounts	have	been	restated	for	discontinued	operations)

# Revenues

Revenues	increased	$1.0	billion,	or	13%,	to	$8.6	billion	in	2002	from	$7.6	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	17%	to	$6.1	billion	in	2002.	AES	is	a	global	power	company	which	operates	in	31	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.

(in	$millions)

| North	America | $818 | $836 | (2)% |
| :--- | :--- | :--- | :--- |
| South\tAmerica | 1,685 | — | NM |
| Caribbean* | 634 | 806 | (21)% |
| Total\tLarge\tUtilities | $3,137 | $1,642 | 91% |
| Growth\tDistribution: |  |  |  |
| South\tAmerica | $263 | $781 | (66)% |
| Caribbean* | 559 | 635 | (12)% |
| Europe/Africa | 358 | 197 | 82% |
| Total\tGrowth\tDistribution | $1,180 | $1,613 | (27)% |
| Total\tRegulated\tRevenues | $4,317 | $3,255 | 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	$3.3	billion	in	2001.	The	$1.5	billion	increase	in	large utilities	revenues	was	offset	by	a	$433	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 27%	to	$2.3	billion	during	2002.

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	revenues	decreased	27%	or	$0.4	billion	to	$1.2	billion	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	$161	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	as	well	as	improvements	at	Telasi	in	Georgia.

| North	America | $830 | $742 | 12% |
| :--- | :--- | :--- | :--- |
| South\tAmerica | 738 | 807 | (9)% |
| Caribbean* | 180 | 204 | (12)% |
| Europe/Africa | 369 | 331 | 11% |
| Asia | 361 | 333 | 8% |
| Total\tContract\tGeneration | $2,478 | $2,417 | 3% |
| Competitive\tSupply: |  |  |  |
| North\tAmerica | $443 | $513 | (14)% |
| South\tAmerica | 98 | 156 | (37)% |
| Caribbean* | 195 | 196 | (1)% |
| Europe/Africa | 1,012 | 1,025 | (1)% |
| Asia | 89 | 83 | 7% |
| Total\tCompetitive\tSupply | $1,837 | $1,973 | (7)% |
| Total\tNon-Regulated\tRevenues | $4,315 | $4,390 | (2)% |

Non-regulated	revenues.				Non-regulated	revenues	decreased	2%	or	$75	million	to	$4.3	billion	in	2002	compared	to	$4.4	billion	in	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	United	Kingdom	and	the	Northeastern	U.S.	Excluding	businesses	acquired	or	that	commenced	operations	in	2002	or	2001,	non-regulated revenues	decreased	10%	to	$3.8	billion	in	2002.

Contract	generation	revenues	increased	3%	or	$61	million	to	$2.5	billion	in	2002	compared	to	$2.4	billion	in	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	$38	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	$28	million	most	significantly	at	Haripur	in	Bangladesh	and	Jiaozuo	in	China.

Competitive	supply	revenues	decreased	7%	or	$136	million	to	$1.8	billion	in	2002	compared	to	$2.0	billion	in	2001	due	to	decreases	in	all	geographic	regions	except	for Asia.	North	America	revenues	declined	$70	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	$58	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	declined	slightly	due	to	declines	at	Colombia	I	and	Panama	offset	in	part	by	an	increase	at	Chivor	in	Colombia.	Europe/Africa	revenues	declined	$13	million due	to	a	decline	in	merchant	energy	prices	in	the	United	Kingdom	that	was	driven	by	mild	weather	conditions,	increased	competition	and	the	significant	over-capacity that	exists	in	the	United	Kingdom	generation	market,	and	reduced	revenues	from	the	closure	of	Belfast	West	in	Northern	Ireland	offset	slightly	by	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	$258	million,	or	12%,	to	$1.9	billion	in	2002	from	$2.2	billion	in	2001.	Gross	margin	as	a	percentage	of	revenues	decreased	to	22%	in	2002 from	28%	in	2001.	The	decrease	in	gross	margin	is	due	to	lower	market	prices	in	the	U.S.,	the	United	Kingdom	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	27%	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.

| North	America | $302 | 37% $ | 290 | 35% | 4% |
| :--- | :--- | :--- | :--- | :--- | :--- |
| South\tAmerica | 163 | 10% | (14) | — | NM |
| Caribbean* | 220 | 35% | 342 | 42% | (36)% |
| Total\tLarge\tUtilities: | $685 | 22% $ | 618 | 38% | 11% |
| Growth\tDistribution: |  |  |  |  |  |
| South\tAmerica | (61) | (23)% | 249 | 32% | (124)% |
| Caribbean* | 53 | 9% | 31 | 5% | 71% |
| Europe/Africa | 16 | 4% | (56) | (28)% | 129% |
| Asia | (3) | NM | (3) | NM | — |
| Total\tGrowth\tDistribution | $5 | 0% $ | 221 | 14% | (98)% |
| Total\tRegulated\tGross\tMargin | $690 | 16% $ | 839 | 26% | (18)% |

Regulated	gross	margin.				Regulated	gross	margin	decreased	18%	or	$149	million	to	$690	million	in	2002	compared	to	$839	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	16%	in	2002	from	26%	in 2001.	Excluding	businesses	acquired	or	that	commenced	operations	in	2002	or	2001,	regulated	gross	margin	decreased	42%	to	$499	million	in	2002.

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.	Excluding	this	adjustment,	the	large	utilities	gross	margin	as	a	percentage	of	revenues	would	have	been	24%	in	2002.	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	gross	margin	decreased	98%	or	$216	million	to	$5	million	in	2002	compared	to	$221	million	in	2001.	The	decline	of	$310	million	in	South	America gross	margin	was	offset	in	part	by	increases	of	$72	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	operational	improvements	at	Telasi	in	Georgia	and	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	0%	in	2002	from	14%	in	2001.	However,	excluding	the	$146	million	nonrecurring	provision	for	the	Brazilian	Regulatory	decision	at Sul,	growth	distribution	gross	margin	as	a	percentage	of	revenues	would	have	been	13%	in	2002.

| North	America | $426 | 51% | $368 | 50% | 16% |
| :--- | :--- | :--- | :--- | :--- | :--- |
| South\tAmerica | 280 | 38% | 253 | 31% | 11% |
| Caribbean* | 32 | 18% | 27 | 13% | 19% |
| Europe/Africa | 147 | 40% | 96 | 29% | 53% |
| Asia | 165 | 46% | 110 | 33% | 50% |
| Total\tContract\tGeneration | $1,050 | 42% | $854 | 35% | 23% |
| Competitive\tSupply: |  |  |  |  |  |
| North\tAmerica | $93 | 21% | $137 | 27% | (32)% |
| South\tAmerica | 15 | 15% | 37 | 24% | (59)% |
| Caribbean* | 66 | 34% | 56 | 29% | 18% |
| Europe/Africa | (14) | (1)% | 239 | 23% | (106)% |
| Asia | 19 | 21% | 15 | 18% | 27% |
| Total\tCompetitive\tSupply | $179 | 10% | $484 | 25% | (63)% |
| Total\tNon-Regulated\nGross\tMargin | $1,229 | 28% | $1,338 | 30% | (8)% |

Non-regulated	gross	margin.				Non-regulated	gross	margin	decreased	8%	or	$109	million	to	$1.2	billion	in	2002	compared	to	$1.3	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	decreased	to	28%	in	2002	from	30%	in	2001.	Excluding	businesses acquired	or	that	commenced	operations	in	2002	or	2001,	non-regulated	gross	margin	decreased	16%	to	$1.1	billion	in	2002.

Contract	generation	gross	margin	increased	23%	or	$196	million	to	$1.1	billion	in	2002	compared	to	$0.9	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	42%	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	$51	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	gross	margin	decreased	63%	or	$305	million	to	$179	million	in	2002	compared	to	$484	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	$44	million	mainly due	to	the	lower	energy	prices	in	New	York	and	milder	weather	in	California.	South	America	gross	margin	decreased	$22	million	mainly	due	to	the	devaluation	of	the peso	in	Argentina.	Europe/Africa	gross	margin	decreased	$253	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	10%	in	2002 from	25%	in	2001.	Gross	margin	at	Drax	in	2002	included	the	write	off	of	approximately	$215	million	of	trade	receivables	due	to	the	bankruptcy	of	TXU	Europe. Excluding	this	adjustment,	the	competitive	supply	gross	margin	as	a	percentage	of	revenues	would	have	been	21%	in	2002.

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	$456	million,	or	29%,	to	$2.0	billion	in	2002	from	$1.6	billion	in	2001.	Interest	expense	as	a	percentage	of	revenues	was 24%	in	2002	and	21%	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	$123	million,	or	65%,	to	$312	million	in	2002	from	$189	million	in	2001.	Interest	income	as	a	percentage	of	revenues	was 4%	in	2002	and	2%	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	$103	million,	or	89%,	to	$219	million	in	2002	from	$116	million	in	2001.	Approximately	$169	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	$22	million,	or	34%,	to	$87	million	in	2002	from	$65	million	in	2001.	Approximately	$76	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	$426	million	to	$456	million	in	2002	from	$30	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	$379	million	to	a	loss	of	$203	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	$3	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	$1.6	billion	in	2002	primarily	resulting	from	impairment	charges	taken	in	2002.	Financial	distress	of	certain	TXU	Europe	companies	during	late	2002	resulted in	the	issuance	of	an	administration	order	for	TXU	EET	and	TXU	Group,	and	led	to	the	termination	of	the	long-term	electricity	sales	hedging	arrangement	at	Drax	and	a tolling	agreement	at	Barry.	As	a	result	of	these	terminations,	the	Company	recorded	pre-tax	asset	impairment	charges	of	$955	million	at	Drax	and	$172	million	at	Barry in	the	fourth	quarter	of	2002.	Drax	and	Barry	are	competitive	supply	businesses	located	in	the	United	Kingdom.	Additionally,	the	Company	recorded	pre-tax	charges totaling	approximately	$357	million	related	to	the	sale	or	impairment	of	development	projects	and	approximately	$116	million	related	to	the	sale	or	impairment	of investments	during	2002.

Drax	is	the	operator	of	Drax	Power	Plant,	Britain's	largest	power	station.	In	November	2002,	Drax	terminated	its	Hedging	Agreement	with	TXU	EET.	In November	2002,	TXU	Group,	the	guarantor	under	the	power	supply	hedging	agreement	between	Drax	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	$955	million was	taken	to	write-down	the	net	assets	to	their	fair	value.

Barry	had	a	tolling	agreement	with	TXU	EET	which	contracted	all	of	the	output	of	the	Barry	plant.	The	TXU	EET	administration	order	discussed	above	constituted	a change	in	circumstance,	as	defined	by	SFAS	No.	144,	which	indicated	that	the	carrying	amount	of	the	Barry	net	assets	may	not	be	recoverable.	Accordingly,	in	the fourth	quarter	of	2002,	an	impairment	charge	of	$172	million	was	recorded	to	write-down	the	net	assets	to	their	fair	value.

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 .	Prior	to	January	1,	2002,	goodwill	was	amortized	on	a	straight-line	basis	over	the	estimated	benefit	period,	which	ranged st 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	taxes	(including	income	taxes	on	equity	in	earnings)	on	continuing	operations	changed	to	a	benefit	of	$27	million	in	2002	from	expense	of $206	million	in	2001.	The	Company's	tax	position	changed	from	tax	expense	at	a	32%	effective	tax	rate	in	2001	to	a	tax	benefit	at	a	1%	effective	tax	rate	in	2002.	The 2002	effective	tax	rate	resulted	from	a	small	tax	benefit	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	$137	million,	or	133%,	to	a	benefit	of	$34	million	in	2002	from	an	expense	of	$103	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	$22	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	$3.0	billion	to	a	loss	of	$2.6	billion	for	2002	from	income	of $446	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	$573	million	and	$173	million,	respectively,	in	2002	and	2001.	During 2002,	the	Company	discontinued	certain	of	its	operations	including	Fifoots,	CILCORP,	NewEnergy,	Eletronet,	Mt.	Stuart,	Ecogen,	two	Altai	businesses,	Mountainview and	Kelvin.	The	Company	closed	the	sale	of	CILCORP	in	January	2003.	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	(prior	year	amounts	have	been	restated	for	discontinued	operations)

Revenues	increased	$1.4	billion,	or	23%	to	$7.6	billion	in	2001	from	$6.2	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	1%	to	$5.5	billion	in	2001.	AES	is	a	global	power	company	which	operates	in	31	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.

|  | (in	$millions) | (in	$millions) |  |
| :--- | :--- | :--- | :--- |
| Large\tUtilities: |  |  |  |
| North\tAmerica | $836 | $892 | (6)% |
| Caribbean* | 806 | 493 | 63% |
| Total\tLarge\tUtilities | $1,642 | $1,385 | 19% |
| Growth\tDistribution: |  |  |  |
| South\tAmerica | $781 | $767 | 2% |
| Caribbean* | 635 | 338 | 88% |
| Europe/Africa | 197 | — | NM |
| Asia | — | 171 | NM |
| Total\tGrowth\tDistribution | $1,613 | $1,276 | 26% |
| Total\tRegulated\tRevenues | $3,255 | $2,661 | 22% |

Regulated	revenues.				Regulated	revenues	increased	$594	million,	or	22%,	to	$3.3	billion	in	2001	from	$2.7	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	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	revenues	increased	$337	million,	or	26%,	to	$1.6	billion	in	2001	from	$1.3	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	$197	million	primarily	from	the	acquisition	of	SONEL.	In	Asia,	growth	distribution	segment	revenues	decreased	$171	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.

|  | (in	$millions) | (in	$millions) |  |
| :--- | :--- | :--- | :--- |
| Contract\tGeneration: |  |  |  |
| North\tAmerica | $742 | $696 | 7% |
| South\tAmerica | 807 | 286 | 182% |
| Caribbean* | 204 | 193 | 6% |
| Europe/Africa | 331 | 213 | 55% |
| Asia | 333 | 320 | 4% |
| Total\tContract\tGeneration | $2,417 | $1,708 | 42% |
| Competitive\tSupply: |  |  |  |
| North\tAmerica | $513 | $506 | 1% |
| South\tAmerica | 156 | 109 | 43% |
| Caribbean* | 196 | 74 | 165% |
| Europe/Africa | 1,025 | 1,077 | (5)% |

| Asia | 83 | 71 | 17% |
| :--- | :--- | :--- | :--- |
| Total\tCompetitive\tSupply | $1,973 | $1,837 | 7% |
| Total\tNon-Regulated\tRevenues | $4,390 | $3,545 | 24% |

Non-regulated	revenues.				Non-regulated	revenues	increased	$845	million,	or	24%,	to	$4.4	billion	in	2001	from	$3.5	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	4%	to	$3.3	billion	during	2001

Contract	generation	revenues	increased	$709	million,	or	42%	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	$118	million,	and	the	acquisition	of	a	controlling	interest	in	Kilroot during	2000	was	the	largest	contributor	to	the	increase.	North	America	and	Asia	contract	generation	revenues	increased	$46	million	and	$13	million,	respectively. 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.

Competitive	supply	revenues	increased	$136	million	or	7%	to	$2.0	billion	in	2001	from	$1.8	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	North	America,	South	America	and Asia.	Europe/Africa	reported	a	$52	million	decrease	due	to	lower	pool	prices	in	the	United	Kingdom	offset	by	the	acquisition	of	Ottana.	In	North	America,	competitive supply	segment	revenues	increased	$7	million	due	primarily	to	increased	operations	at	Placerita	offset	by	lower	market	prices	at	our	New	York	businesses.

Gross	margin	increased	$274	million,	or	14%,	to	$2.2	billion	in	2001	from	$1.9	billion	in	2000.	Gross	margin	as	a	percentage	of	revenues	decreased	to	28%	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	offset	by	lower	market	prices	in	the United	Kingdom.	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	$1.6	billion	in	2001.

| North	America | $290 | 35% $ | 262 | 29% | 11% |
| :--- | :--- | :--- | :--- | :--- | :--- |
| South\tAmerica | (14) | — | (2) | — | NM |
| Caribbean* | 342 | 42% | 177 | 36% | 93% |
| Total\tLarge\tUtilities | $618 | 38% $ | 437 | 32% | 41% |
| Growth\tDistribution: |  |  |  |  |  |
| South\tAmerica | $249 | 32% $ | 169 | 22% | 47% |
| Caribbean* | 31 | 5% | (8) | (2)% | NM |
| Europe/Africa | (56) | (28)% | — | — | NM |
| Asia | (3) | NM | (30) | (18)% | 90% |
| Total\tGrowth\tDistribution | $221 | 14% $ | 131 | 10% | 69% |
| Total\tRegulated\tGross\tMargin | $839 | 26% $ | 568 | 21% | 48% |

Regulated	gross	margin.				Regulated	gross	margin	increased	$271	million,	or	48%,	to	$839	million	in	2001	from	$568	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	26%	during	2001	from	21%	for	2000.	Excluding	businesses	acquired	or	that	commenced	operations	in 2001	or	2000,	regulated	gross	margin	increased	36%	to	$545	million	during	2001.

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	gross	margin	increased	$90	million,	or	69%,	to	$221	million	in	2001	from	$131	million	in	2000.	Growth	distribution	gross	margin	as	a	percentage of	revenue	increased	to	14%	in	2001	from	10%	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	$56	million	and was	negative	due	to	losses	at	SONEL.	In	Asia,	growth	distribution	margin	improved	$27	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.

| North	America | $368 | 50% $ | 360 | 52% | 2% |
| :--- | :--- | :--- | :--- | :--- | :--- |
| South\tAmerica | 253 | 31% | 189 | 66% | 34% |
| Caribbean | 27 | 13% | 16 | 8% | 69% |
| Europe/Africa | 96 | 29% | 46 | 22% | 109% |
| Asia | 110 | 33% | 136 | 43% | (19)% |
| Total\tContract\tGeneration | $854 | 35% $ | 747 | 44% | 14% |
| Competitive\tSupply: |  |  |  |  |  |
| North\tAmerica | $137 | 27% $ | 145 | 29% | (6)% |
| South\tAmerica | 37 | 24% | 63 | 58% | (41)% |
| Caribbean | 56 | 29% | 41 | 55% | 37% |
| Europe/Africa | 239 | 23% | 326 | 30% | (27)% |
| Asia | 15 | 18% | 13 | 18% | 15% |
| Total\tCompetitive\tSupply | $484 | 25% $ | 588 | 32% | (18)% |
| Total\tNon-Regulated\nGross\tMargin | $1,338 | 30% $ | 1,335 | 38% | 0% |

Non-regulated	gross	margin.				Non-regulated	gross	margin	remained	relatively	consistent	at	$1.3	billion	in	both	2001	and	2000.	Non-regulated	gross	margin	as	a percentage	of	revenues	decreased	to	30%	during	2001	from	38%	in	2000	due	to	a	decline	in	market	prices	in	the	United	Kingdom	and	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	17%	to	$1.1	billion	in	2001.

Contract	generation	gross	margin	increased	$107	million,	or	14%,	to	$854	million	in	2001	from	$747	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	$50	million	and	was	29%	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	$26	million	and	was	33%	of	revenues.	The	decrease	is	due	mainly	to	additional	bad	debt	provisions	at Jiaozuo,	Hefei	and	Aixi	in	China	that	were	partially	offset	by	the	start	of	commercial	operations	at	Haripur.	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.

The	competitive	supply	gross	margin	decreased	$104	million,	or	18%,	to	$484	million	in	2001	from	$588	million	in	2000.	The	overall	decrease	is	due	to	declines	in North	America,	Europe/Africa	and	South	America	that	were	partially	offset	by	slight	increases	in	the	Caribbean	and	Asia.	The	competitive	supply	gross	margin	as	a percentage	of	revenues	decreased	to	25%	in	2001	from	32%	in	2000.	In	South	America,	competitive	supply	segment	gross	margin	decreased	$26	million	and	was	24% of	revenues	due	to	declines	at	several	of	our	businesses	in	Argentina.	In	Europe/Africa,	competitive	supply	segment	gross	margin	decreased	$87	million	and	was	23%	of revenues.	The	decrease	is	due	primarily	to	declines	at	Drax	and	Barry	from	the	lower	market	prices	in	the	United	Kingdom	In	North	America,	competitive	supply segment	gross	margin	decreased	$8	million	and	was	27%	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	increased	to	2%	in	2001	from	1%	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	$313	million,	or	25%,	to	$1,575	million	in	2001	from	$1,262	million	in	2000.	Interest	expense	as	a	percentage	of revenues	increased	to	21%	in	2001	from	20%	in	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	$12	million,	or	6%,	to	$189	million	in	2001	from	$201	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	$65	million,	or	127%,	to	$116	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	$13	million,	or	25%,	to	$65	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	$26	million,	or	650%,	to	$30	million	in	2001	from	$4	million	in	2000.	Foreign currency	transaction	losses	increased	primarily	due	to	devaluations	in	Argentina	and	to	a	much	lesser	extent	in	the	United	Kingdom,	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	$162	million	to	$206	million	in	2001	from	$368	million in	2000.	The	Company's	effective	tax	rate	was	32%	in	2001	and	31%	in	2000.

Minority	interest	(income)	expense.				Minority	interest	expense	(before	income	taxes)	decreased	$17	million,	or	14%,	to	$103	million	in	2001	from	$120	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	$15	million	to	$16	million	in	2001	from	$31	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.				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.	All	of	the	operations	for	these	businesses	and the	related	write	offs	from	dispositions	in	2001	are	reported	in	this	line	item.	Results	of	discontinued	operations	in	2001	were	a	loss	of	approximately	$173	million	and the	write	off	from	dispositions	was	a	loss	of	approximately	$145	million,	net	of	tax.	All	amounts	in	2000	represent	results	from	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	$173	million.	This	decrease	was	partially	offset	by	increased	gross	margins	from	large	utilities,	growth

distribution	and	contract	generation.

# CAPITAL	RESOURCES	AND	LIQUIDITY

# Non-recourse	project	financing

AES	is	a	holding	company	that	conducts	all	of	its	operations	through	subsidiaries.	AES	has,	to	the	extent	practicable,	utilized	non-recourse	debt	to	fund	a	significant portion	of	the	capital	expenditures	and	investments	required	to	construct	and	acquire	its	electric	power	plants,	distribution	companies	and	related	assets.	Non-recourse borrowings	are	substantially	non-recourse	to	other	subsidiaries	and	affiliates	and	to	AES	as	the	parent	company,	and	are	generally	secured	by	the	capital	stock,	physical assets,	contracts	and	cash	flow	of	the	related	subsidiary	or	affiliate.	At	December	31,	2002,	AES	had	$5.8	billion	of	recourse	debt	and	$14.2	billion	of	non-recourse	debt outstanding.	For	more	information	on	AES's	long	term	debt	see	Note	9	of	the	consolidated	financial	statements.

The	Company	intends	to	continue	to	seek,	where	possible,	non-recourse	debt	financing	in	connection	with	the	assets	or	businesses	that	the	Company	or	its	affiliates	may develop,	construct	or	acquire.	However,	depending	on	market	conditions	and	the	unique	characteristics	of	individual	businesses,	non-recourse	debt	financing	may	not	be available	or	available	on	economically	attractive	terms.	If	the	Company	decides	not	to	provide	any	additional	funding	or	credit	support,	the	inability	of	any	of	our subsidiaries	that	are	under	construction	or	that	have	near-term	debt	payment	obligations	to	obtain	non-recourse	project	financing	may	result	in	such	subsidiary's insolvency	and	the	loss	of	the	Company's	investment	in	such	subsidiary.	Additionally,	the	loss	of	a	significant	customer	at	any	of	our	subsidiaries	may	result	in	the	need to	restructure	the	non-recourse	project	financing	at	that	subsidiary,	and	the	inability	to	successfully	complete	a	restructuring	of	the	non-recourse	project	financing	may result	in	a	loss	of	the	Company's	investment	in	such	subsidiary.

In	addition	to	the	non-recourse	debt,	if	available,	AES	as	the	parent	company	provides	a	portion,	or	in	certain	instances	all,	of	the	remaining	long-term	financing	or credit	required	to	fund	development,	construction	or	acquisition.	These	investments	have	generally	taken	the	form	of	equity	investments	or	loans,	which	are subordinated	to	the	project's	non-recourse	loans.	The	funds	for	these	investments	have	been	provided	by	cash	flows	from	operations	and	by	the	proceeds	from	issuances of	debt,	common	stock	and	other	securities	issued	by	the	Company.	Similarly,	in	certain	of	its	businesses,	the	Company	may	provide	financial	guarantees	or	other	credit support	for	the	benefit	of	counter	parties	who	have	entered	into	contracts	for	the	purchase	or	sale	of	electricity	with	the	Company's	subsidiaries.	In	such	circumstances, were	a	subsidiary	to	default	on	a	payment	or	supply	obligation,	the	Company	would	be	responsible	for	its	subsidiary's	obligations	up	to	the	amount	provided	for	in	the relevant	guarantee	or	other	credit	support.

As	a	result	of	recent	declines	in	the	trading	prices	of	AES's	equity	and	debt	securities,	counter	parties	may	no	longer	be	as	willing	to	accept	general	unsecured commitments	by	AES	to	provide	credit	support.	Accordingly,	with	respect	to	both	new	and	existing	commitments,	AES	may	be	required	to	provide	some	other	form	of assurance,	such	as	a	letter	of	credit,	to	backstop	or	replace	any	AES	credit	support.	AES	may	not	be	able	to	provide	adequate	assurances	to	such	counter	parties.	In addition,	to	the	extent	AES	is	required	and	able	to	provide	letters	of	credit	or	other	collateral	to	such	counter	parties,	it	will	limit	the	amount	of	credit	available	to	AES	to meet	its	other	liquidity	needs.

At	December	31,	2002,	AES	had	provided	outstanding	financial	and	performance	related	guarantees	or	other	credit	support	commitments	to	or	for	the	benefit	of	its subsidiaries,	which	were	limited	by	the	terms	of	the	agreements,	to	an	aggregate	of	approximately	$657	million	(excluding	those	collateralized	by	letters-of-credit	and other	obligations	discussed	below).	The	Company	is	also	obligated	under	other	commitments,	which	are	limited	to	amounts,	or	percentages	of	amounts,	received	by AES	as	distributions	from	its	project	subsidiaries.	These	amounts	aggregated	$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 (excluding	those	collateralized	by	letter-of-credit	obligations).

At	December	31,	2002,	the	Company	had	$213	million	in	letters	of	credit	outstanding,	which	operate	to	guarantee	performance	relating	to	certain	project	development activities	and	subsidiary	operations.	Of	these	letters	of	credit,	$104	million	were	provided	under	the	Company's	revolver.	The	Company	pays	letter-of-credit	fees	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.

# Project	level	defaults

While	the	lenders	under	AES's	non-recourse	project	financings	generally	do	not	have	direct	recourse	to	the	parent,	defaults	thereunder	can	still	have	important consequences	for	AES's	results	of	operations	and	liquidity,	including,	without	limitation:

•Reducing	AES's	cash	flows	since	the	project	subsidiary	will	typically	be	prohibited	from	distributing	cash	to	AES	during	the	pendancy	of	any	default

•Triggering	AES's	obligation	to	make	payments	under	any	financial	guarantee,	letter	of	credit	or	other	credit	support	AES	has	provided	to	or	on	behalf	of such	subsidiary

•Causing	AES	to	record	a	loss	in	the	event	the	lender	forecloses	on	the	assets

•Triggering	defaults	in	the	parent's	outstanding	debt.	For	example,	the	parent's	revolving	credit	agreement	and	outstanding	senior	notes,	senior subordinated	notes	and	junior	subordinated	notes	include	events	of	default	for	certain	bankruptcy	related	events	involving	material	subsidiaries.	In addition,	the	parent's	revolving	credit	agreement	and	senior	subordinated	notes	include	events	of	default	related	to	payment	defaults	and	accelerations	of outstanding	debt	of	material	subsidiaries.

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.

# Off	Balance	Sheet	Arrangements

In	May	1999,	a	subsidiary	of	the	Company	acquired	six	electric	generating	stations	from	New	York	State	Electric	and	Gas.	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	transaction	with	operating	lease	treatment.	Accordingly,	these	assets	are	not	recorded	on	the	books	of	the	Company,	and	periodic	lease	payments, which	amounted	to	$54	million	in	2002,	are	expensed	as	incurred.	Combined	revenues	and	operating	income	of	the	two	plants	were	$281	million	and	$65	million, respectively,	in	2002.	The	lease	obligations	bear	an	imputed	interest	rate	of	approximately	9%	which	approximates	fair	market	value.	The	Company	is	not	subject	to	any additional	liabilities	or	contingencies	if	the	arrangement	were	to	terminate,	and	the	Company	believes	there	would	be	minimal	effects	on	operating	cash	flows	if	the	off balance	sheet	arrangement	was	dissolved.	The	terms	of	the	lease	include	restrictive	covenants	such	as

the	maintenance	of	certain	coverage	ratios.	As	of	December	31,	2002,	the	Company	fulfilled	a	lease	requirement	on	the	subsidiary's	behalf	by	funding	an	additional liquidity	account,	as	defined	in	the	lease	agreement,	in	the	form	of	a	$36	million	letter	of	credit.	However,	the	subsidiary	is	required	to	replenish	or	replace	this	letter	of credit	in	the	event	it	is	drawn	upon	or	requires	replacement.	Historically,	the	plants	have	satisfied	the	restrictive	covenants	of	the	lease,	and	there	are	no	known	trends	or uncertainties	that	would	indicate	early	termination	of	the	lease.	See	Note	11	to	the	consolidated	financial	statements	for	a	more	complete	discussion	of	this	transaction.

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,	but	may	be	replaced	as	servicing	agent	if IPL	fails	to	meet	certain	financial	covenants	regarding	interest	coverage	and	debt-to-capital.	The	transfers	of	such	retail	accounts	receivable	from	IPL	to	IPL	Funding	are recorded	as	sales;	however,	no	gain	or	loss	is	recorded	on	the	sale.	See	Note	11	to	the	consolidated	financial	statements	for	additional	discussion	about	this	arrangement.

The	Company	has	investments	in	several	equity	method	affiliates	including	CEMIG,	and	does	not	consolidate	the	financial	information	of	equity	method	affiliates. Therefore,	none	of	the	assets	or	liabilities	of	our	equity	method	affiliates	are	included	on	our	consolidated	balance	sheets.	See	Note	7	to	the	consolidated	financial statements	for	summarized	financial	information	from	our	equity	method	affiliates.

As	of	December	31,	2002,	the	Company's	known	contractual	obligations	are	as	follows.

| Contractual	obligations | Total | Less	than	1	year | 1	to	3	years | 3	to	5	years | Over	5	years |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Indebtedness\t(excluding\tinterest) | $20,047 | $3,341 | $4,742 | $2,968 | $8,996 |
| Trust\tpreferred\tsecurities\t(excluding\tdividends) | $978 | — | — | — | $978 |
| Construction\tcommitments | $65 | $65 | — | — | — |
| Operating\tlease\tobligations | $1,726 | $88 | $157 | $145 | $1,336 |
| Purchase\tobligations | $14,991 | $1,654 | $2,512 | $1,433 | $9,392 |
| Total | $37,807 | $5,148 | $7,411 | $4,546 | $20,702 |

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

# Parent	company	liquidity

Because	of	the	non-recourse	nature	of	most	of	AES's	indebtedness,	AES	believes	that	unconsolidated	parent	company	liquidity	is	an	important	measure	of	liquidity.

The	parent	company's	principal	sources	of	liquidity	are:

•Dividends	and	other	distributions	from	its	subsidiaries,	including	refinancing	proceeds

•Proceeds	from	debt	and	equity	financings	at	the	parent	company	level,	including	borrowings	under	its	revolving	credit	facility,	and

•Proceeds	from	asset	sales.

The	parent	company's	cash	requirements	through	the	end	of	2003	are	primarily	to	fund:

•Interest	and	preferred	dividends

•Principal	repayments	of	debt

•Construction	commitments

•Other	equity	commitments

•Taxes,	and

•Parent	company	overhead.

In	addition,	certain	of	the	Company's	regulatory	subsidiaries	are	subject	to	rules	and	regulations	that	could	possibly	result	in	a	restriction	on	their	ability	to	pay dividends.	For	example,	on	February	12,	2003,	the	Indiana	Utility	Regulatory	Commission	(IURC)	issued	an	Order	in	connection	with	a	petition	filed	by	IPL	for approval	of	its	financing	program,	including	the	issuance	of	additional	long-term	debt.	The	Order	approved	the	requested	financing	but	set	forth	a	process	whereby	IPL must	file	a	report	with	the	IURC,	prior	to	declaring	or	paying	a	dividend,	that	sets	forth	(1)	the	amount	of	any	proposed	dividend,	(2)	the	amount	of	dividends distributed	during	the	prior	twelve	months,	(3)	an	income	statement	for	the	same	twelve-month	period,	(4)	the	most	recent	balance	sheet,	and	(5)	IPL's	capitalization	as of	the	close	of	the	preceding	month,	as	well	as	a	pro	forma	capitalization	giving	effect	to	the	proposed	dividend,	with	sufficient	detail	to	indicate	the	amount	of unappropriated	retained	earnings.	If	within	twenty	(20)	calendar	days	the	IURC	does	not	initiate	a	proceeding	to	further	explore	the	implications	of	the	proposed dividend,	the	proposed	dividend	will	be	deemed	approved.	The	Order	stated	that	such	process	should	continue	in	effect	during	the	term	of	the	financing	authority,	which expires	December	31,	2006.	On	February	28,	2003,	IPL	filed	a	petition	for	reconsideration,	or	in	the	alternative,	for	rehearing	with	the	IURC.	This	petition	seeks clarification	of	certain	provisions	of	the	Order.	In	addition,	the	petition	requests	that	the	IURC	establish	objective	criteria	in	connection	with	the	reporting	process	related to	IPL's	long	term	debt	capitalization	ratio.	Whether	or	not	such	petition	is	successful,	the	Company	has	no	reason	to	believe	the	IURC	will	prevent	IPL	from	paying future	dividends	in	the	ordinary	course	of	prudent	business	operations.

In	December	2002,	the	Company	completed	a	$2.1	billion	refinancing	of	its	bank	and	short-term	debt	securities	by	entering	into	$1.6	billion	in	senior	secured	credit facilities	and	exchanging	a	portion	of	$500	million	of	outstanding	debt	securities.	The	refinancing	substantially	eliminates	all	scheduled	parent	company	debt	maturities until	November	2004.	The	$1.6	billion	senior	secured	credit	facilities	are	comprised	of	a	$350	million	senior	secured	revolving	credit	facility,	three	tranches	of	term	loan facilities	totaling	approximately	$1.2	billion	and	a	£52.25	million	additional	letter	of	credit.

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:

| Non-contingent	contractual	obligation | Less	than	1	year | 1	to	3	years | Over	3	years | Total |
| :--- | :--- | :--- | :--- | :--- |
| Indebtedness\t(excluding\tinterest) | $26 | $1,810 | $3,968 | $5,804 |
| Trust\tpreferred\tsecurities\t(excluding\tdividends) | — | — | $978 | $978 |
| Construction\tcommitments | $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<br>Agreements |  | Exposure	Range<br>for	Each<br>Agreement | Recorded<br>On	Balance<br>Sheet |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Guarantees | $652 |  | 52 | &lt;$1\t–\t$100 | $273 |
| Letters\tof\tcredit—under\tthe\tRevolver | $104 |  | 14 | &lt;$1\t–\t$36 | $51 |
| Letters\tof\tcredit—outside\tthe\tRevolver | $109 |  | 5 | &lt;$1\t–\t$84 | $84 |
| Surety\tbonds | $6 |  | 6 | &lt;$1\t–\t$3 | — |
| Total | $871 |  | 77 |  | $408 |

The	Company	has	a	varied	portfolio	of	performance	related	contingent	contractual	obligations.	Amounts	related	to	the	balance	sheet	items	represent	credit enhancements	made	by	AES	the	parent	company	and	other	third	parties	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.	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	AES	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	AES's	control.	There	can	be	no	assurance	that	it	would	have	adequate	sources	of	liquidity	to fund	its	obligations	under	these	contingent	contractual	obligations	if	it	were	required	to	make	substantial	payments	thereunder.

Interim	needs	for	shorter-term	and	working	capital	financing	at	the	parent	company	have	been	met	with	borrowings	under	the	$350	million	senior	secured	revolving credit	facility	(the	"Revolver")	which	comprises	part	of	the	new	$1.6	billion	senior	secured	credit	facilities.	The	senior	secured	credit	facilities	contain	certain	restrictive covenants.	The	covenants	provide	for,	among	other	items:

•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;

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

•maintenance	of	certain	financial	ratios.

At	December	31,	2002,	cash	borrowings	and	letters	of	credit	outstanding	under	the	Revolver	amounted	to	$228	million	and	$104	million,	respectively.	Letters	of	credit outstanding	outside	the	Revolver	amounted	to	$109	million.

The	Company	has	a	secured	equity-linked	loan	("SELL")	of	$225	million	due	in	2005	that	is	secured	by	a	pledge	of	218	million	shares	of	the	Company's	common	stock at	December	31,	2002.	As	of	December	31,	2001,	111	million	shares	of	the	Company's	common	stock	had	been	issued	to	consolidated	subsidiaries	with	respect	to	this SELL	and	another	SELL,	which	was	refinanced	in	December	2002.	These	shares	are	not	considered	outstanding	and	therefore	have	been	excluded	from	the	calculation of	earnings	per	share.

The	Company's	senior	secured	notes	due	2005	are	subject	to	mandatory	redemption	provisions	including	provisions	which	require	the	Company,	on	November	25,	2004, to	redeem	40%	of	the	aggregate	principal	amount	of	the	senior	secured	notes	issued	on	December	13,	2003	and	not	previously	redeemed	(at	the	Company's	option	or pursuant	to	the	other	mandatory	redemption	provisions),	at	a	price	equal	to	100%	of	the	principal	amount	of	the	senior	secured	notes	to	be	redeemed	plus	accrued	and unpaid	interest.	As	of	December	31,	2002	approximately	$258	million	aggregate	principal	amount	of	senior	secured	notes	were	outstanding.

The	Company's	senior	secured	notes	also	contain	covenants	which	limit	the	Company's	ability	to	incur	secured	indebtedness	and	provide	guarantees.

# 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	56%	of	the	Company's	total	assets	and	was	$18.8	billion	at	December	31,	2002.	Net property,	plant	and	equipment	increased	$734	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	$1.2	billion,	or	6%,	to	$20.0	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	$780	million	of	cash	and	cash	equivalents	representing	a	decrease	of	$22	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.

# Parent	cash	flows

The	net	cash	provided	by	operating	activities	of	the	parent	was	$1.0	billion	for	2002	as	shown	on	Schedule	I	on	page	S-4.	Cash	received	by	the	parent	from	operating subsidiaries	and	affiliates	includes:

•Consulting	and	management	fees

•Tax	sharing	payments

•Interest	and	other	distributions	paid	during	the	period	with	respect	to	cash	and	other	temporary	cash	investments	less	parent	operating	expenses

This	amount	does	not	include	$0.1	billion	of	cash	sent	by	operating	subsidiaries	and	affiliates	to	qualifying	holding	companies	during	2002.

The	cash	held	at	qualifying	holding	companies	represents	cash	sent	to	subsidiaries	of	the	Company	domiciled	outside	of	the	U.S.	Such	subsidiaries	had	no	contractual restrictions	on	their	ability	to	send	cash	to	AES,	the	parent	company.	Cash	at	those	subsidiaries	was	used	for	investment	and	related	activities	outside	of	the	U.S.	These investments	included	equity	investments	and	loans	to	other	foreign	subsidiaries	as	well	as	development	and	general	costs	and	expenses	incurred	outside	the	U.S.

Approximately	70%	of	cash	sent	by	operating	subsidiaries	and	affiliates	in	2002	were	from	businesses	located	in	investment	grade	countries	compared	with approximately	72%	in	2001	and	56%	in	2000.

At	year	end,	the	parent	company	and	qualified	holding	companies	had	approximately	$197	million	of	cash	and	$18	million	of	availability	under	our	$350	million revolver.

# 								Item	7a—Quantitative	and	Qualitative	Disclosures	About	Market	Risk

# Market	Risks

AES	is	exposed	to	market	risks	associated	with	interest	rates,	foreign	exchange	rates	and	commodity	prices.	AES	often	utilizes	financial	instruments	and	other	contracts to	hedge	against	such	fluctuations.	AES	also	utilizes	financial	and	commodity	derivatives	for	the	purpose	of	hedging	exposures	to	market	risk.	AES	generally	does	not enter	into	derivative	instruments	for	trading	or	speculative	purposes.

# Interest	Rate	Risk

AES	is	exposed	to	risk	resulting	from	changes	in	interest	rates	as	a	result	of	its	issuance	of	variable-rate	debt,	fixed-rate	debt	and	trust	preferred	securities,	as	well	as interest	rate	swap	and	option	agreements.	Depending	on	whether	a	plant's	capacity	payments	or	revenue	stream	is	fixed	or	varies	with	inflation,	AES	partially	hedges against	interest	rate	fluctuations	by	arranging	fixed-rate	or	variable-rate	financing.	In	certain	cases,	AES	executes	interest	rate	swap,	cap	and	floor	agreements	to effectively	fix	or	limit	the	interest	rate	exposure	on	the	underlying	financing.

# Foreign	Exchange	Rate	Risk

AES	is	exposed	to	foreign	currency	risk	and	other	foreign	operations	risk	that	arise	from	investments	in	foreign	subsidiaries	and	affiliates.	A	key	component	of	this	risk is	that	some	of	our	foreign	subsidiaries	and	affiliates	utilize	currencies	other	than	AES's	consolidated	reporting	currency,	the	U.S.	dollar.	Additionally,	certain	of	AES's foreign	subsidiaries	and	affiliates	have	entered	into	monetary	obligations	in	U.S.	dollars	or	currencies	other	than	their	own	functional	currencies.	Primarily,	AES	is exposed	to	changes	in	the	U.S.	dollar/United	Kingdom	Pound	Sterling	exchange	rate,	the	U.S.	dollar/Brazilian	Real	exchange	rate,	the	U.S.	dollar/Venezuelan	Bolivar exchange	rate	and	the	U.S.	dollar/Argentine	peso	exchange	rate.	Whenever	possible,	these	subsidiaries	and	affiliates	have	attempted	to	limit	potential	foreign	exchange

exposure	by	entering	into	revenue	contracts	that	adjust	to	changes	in	foreign	exchange	rates.	AES	also	uses	foreign	currency	forward	and	swap	agreements,	where possible,	to	manage	our	risk	related	to	certain	foreign	currency	fluctuations.

# Commodity	Price	Risk

AES	is	exposed	to	the	impact	of	market	fluctuations	in	the	price	of	electricity,	natural	gas	and	coal.	Although	AES	primarily	consists	of	businesses	with	long-term contracts	or	retail	sales	concessions,	a	portion	of	AES's	current	and	expected	future	revenues	are	derived	from	businesses	without	significant	long-term	revenue	or supply	contracts.	These	competitive	supply	businesses	subject	our	results	of	operations	to	the	volatility	of	electricity	and	natural	gas	prices	in	competitive	markets.	AES's businesses	hedge	certain	aspects	of	their	"net	open"	positions	in	the	U.S.	We	have	used	a	hedging	strategy,	where	appropriate,	to	hedge	our	financial	performance against	the	effects	of	fluctuations	in	energy	commodity	prices.	The	implementation	of	this	strategy	involves	the	use	of	commodity	forward	contracts,	futures,	swaps	and options	as	well	as	long-term	supply	contracts	for	the	supply	of	fuel	and	electricity.

# Value	at	Risk

In	2000,	AES	adopted	a	value	at	risk	("VaR")	approach	to	assess	and	manage	risk	across	the	Company	and	its	subsidiaries.	VaR	measures	the	potential	loss	in	a portfolio's	value	due	to	market	volatility,	over	a	specified	time	horizon,	stated	with	a	specific	degree	of	probability.	The	quantification	of	market	risk	using	VaR	provides a	consistent	measure	of	risk	across	diverse	markets	and	instruments.	The	VaR	approach	was	adopted	because	the	Company	feels	that	statistical	models	of	risk measurement,	such	as	VaR,	provide	an	objective,	independent	assessment	of	risk	exposure	to	the	Company.	The	use	of	VaR	requires	a	number	of	key	assumptions, including	the	selection	of	a	confidence	level	for	expected	losses,	the	holding	period	for	liquidation	and	the	treatment	of	risks	outside	the	VaR	methodology,	including

liquidity	risk	and	event	risk.	VaR,	therefore,	is	not	necessarily	indicative	of	actual	results	that	may	occur.

The	use	of	VaR	allows	AES	to	aggregate	risks	across	all	AES	businesses	compare	risk	on	a	consistent	basis	and	identify	the	drivers	of	risk.	Because	of	the	inherent limitations	of	VaR,	including	those	specific	to	the	variance/covariance	approach,	specifically	the	assumption	that	values	or	returns	are	normally	distributed,	AES	relies on	VaR	as	only	one	component	in	its	risk	assessment	process.	In	addition	to	using	VaR	measures,	AES	performs	stress	and	scenario	analyses	to	estimate	the	economic impact	of	market	changes	on	the	value	of	our	portfolios.	These	results	are	used	to	supplement	the	VaR	methodology.

AES	has	performed	a	company-wide	VaR	analysis	of	all	of	its	material	financial	assets,	liabilities	and	derivative	instruments.	The	VaR	calculation	incorporates numerous	variables	that	could	impact	the	fair	value	of	AES's	instruments,	including	interest	rates,	foreign	exchange	rates	and	commodity	prices,	as	well	as	correlation within	and	across	these	variables.	AES	performs	its	VaR	calculation	using	a	model	based	on	J.P.	Morgan's	RiskMetrics	approach,	which	utilizes	the	variance/covariance method.	We	express	VaR	as	a	dollar	amount	of	the	potential	loss	in	the	fair	value	of	our	portfolio	based	on	a	95%	confidence	level	and	a	one-day	holding	period.

During	the	year	ended	December	31,	2002,	our	average	daily	VaR	for	interest	rate-sensitive	instruments	was	$83.4	million.	The	daily	VaR	for	interest	rate-sensitive instruments	was	highest	at	the	end	of	the	third	quarter,	and	equaled	$95.2	million.	The	daily	VaR	for	interest	rate-sensitive	instruments	was	lowest	at	the	end	of	the second	quarter,	and	equaled	$76.3	million.	Our	average	daily	VaR	for	interest	rate-sensitive	instruments	was	$73.1	million	during	the	year	ended	December	31,	2001. These	amounts	include	the	financial	instruments	that	serve	as	hedges	and	the	underlying	hedged	items.	VaR	for	interest	rate-sensitive	instruments	increased	in	2002	as compared	with	2001	due	to	higher	interest	rate	volatilities,	caused	by	decreases	in	interest	rates	and	uncertainty	surrounding	the	U.S.	economy,	and	an	increase	in	our fixed-rate	debt	portfolio	due	to	the	addition	of	new	businesses.	During	the	year	ended	December	31,	2002,	our	average	daily	VaR	for	foreign	exchange	rate-sensitive instruments	was	$46.5	million.	The	daily	VaR	for	foreign	exchange	rate-sensitive	instruments	was	highest	at	the	end	of	the	third	quarter,	and	equaled	$68.5	million.	The daily	VaR	for	foreign	exchange	rate-sensitive	instruments	was	lowest	at	the	end	of	the	first	quarter,	and	equaled	$30.4	million.	The	average	daily	VaR	for	foreign exchange	rate-sensitive	instruments	during	the	year	ended	December	31,	2001	was	$3.4	million.	These	amounts	include	the	financial	instruments	that	serve	as	hedges and	the	underlying	hedged	items.	VaR	for	foreign	exchange	rate-sensitive	instruments	increased	in	2002	as	compared	to	2001	primarily	due	to	the	consolidation	of Eletropaulo,	which	caused	an	increase	in	the	Company's	foreign	currency	denominated	debt	portfolio.	During	the	year	ended	December	31,	2002,	our	average	daily	VaR for	commodity	price-sensitive	instruments	was	$5.4	million.	The	daily	VaR	for	commodity	price-sensitive	instruments	was	highest	at	the	end	of	the	first	quarter,	and equaled	$6.7	million.	The	daily	VaR	for	commodity	price-sensitive	instruments	was	lowest	at	the	end	of	the	third	quarter,	and	equaled	$4.8	million.	The	average	daily VaR	for	commodity	price-sensitive	instruments	during	the	year	ended	December	31,	2001	was	$6.2	million.	These	amounts	include	the	financial	instruments	that	serve as	hedges	and	do	not	include	the	underlying	physical	assets	or	contracts	that	are	not	permitted	to	be	settled	in	cash.

# 								Item	8—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. Our	audits	also	included	the	financial	statement	schedules	listed	in	the	index	on	page	S-1	of	the	Company's	annual	report	on	Form	10-K.	These	financial	statements	and financial	statement	schedules	are	the	responsibility	of	the	Company's	management.	Our	responsibility	is	to	express	an	opinion	on	the	financial	statements	and	financial statement	schedules	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	50% 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.	Also,	in	our	opinion,	based	on	our audits	and	the	report	of	other	auditors,	such	financial	statement	schedules,	when	considered	in	relation	to	the	basic	consolidated	financial	statements	taken	as	a	whole, present	fairly	in	all	material	respects	the	information	set	forth	therein.

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

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

THE	AES	CORPORATION CONSOLIDATED	BALANCE	SHEETS DECEMBER	31,	2002	AND	2001

| Cash	and	cash	equivalents | $780 | $802 |
| :--- | :--- | :--- |
| Restricted\tcash | 181 | 357 |
| Short-term\tinvestments | 211 | 215 |
| Accounts\treceivable\t–\tnet\tof\treserves\tof\t$424-2002;\t$239\t-2001 | 1,239 | 1,127 |
| Inventory | 384 | 468 |
| Receivable\tfrom\taffiliates | 25 | 10 |
| Deferred\tincome\ttaxes\t–\tcurrent | 130 | 244 |
| Prepaid\texpenses | 218 | 215 |
| Other\tcurrent\tassets | 708 | 382 |

| Current	assets	of	discontinued	operations	and	businesses	held	for	sale | 473 | 872 |
| :--- | :--- | :--- |
| Total\tcurrent\tassets | 4,349 | 4,692 |
| Property,\tPlant\tand\tEquipment: |  |  |
| Land | 703 | 542 |
| Electric\tgeneration\tand\tdistribution\tassets | 19,125 | 16,326 |
| Accumulated\tdepreciation\tand\tamortization | (4,204) | (3,015) |
| Construction\tin\tprogress | 3,222 | 4,259 |
| Property,\tplant,\tand\tequipment\t—\tnet | 18,846 | 18,112 |
| Other\tAssets: |  |  |
| Deferred\tfinancing\tcosts\t–\tnet | 433 | 368 |
| Project\tdevelopment\tcosts | 15 | 66 |
| Investments\tin\tand\tadvances\tto\taffiliates | 194 | 3,031 |
| Debt\tservice\treserves\tand\tother\tdeposits | 515 | 433 |
| Goodwill\t–\tnet | 1,388 | 2,367 |
| Deferred\tincome\ttaxes\t–\tnoncurrent | 968 | — |
| Long-term\tassets\tof\tdiscontinued\toperations\tand\tbusinesses\theld\tfor\tsale | 5,322 | 6,936 |
| Other\tassets | 1,746 | 807 |
| Total\tother\tassets | 10,581 | 14,008 |
| Total | $33,776 | $36,812 |
| LIABILITIES\tAND\tSTOCKHOLDERS'\tEQUITY\t(DEFICIT) |  |  |
| Current\tLiabilities: |  |  |
| Accounts\tpayable | $1,139 | $727 |
| Accrued\tinterest | 369 | 266 |
| Accrued\tand\tother\tliabilities | 1,165 | 674 |
| Current\tliabilities\tof\tdiscontinued\toperations\tand\tbusinesses\theld\tfor\tsale | 497 | 812 |
| Recourse\tdebt\t–\tcurrent\tportion | 26 | 488 |
| Non-recourse\tdebt\t–\tcurrent\tportion | 3,315 | 1,961 |
| Total\tcurrent\tliabilities | 6,511 | 4,928 |
| Long-Term\tLiabilities: |  |  |
| Non-recourse\tdebt | 10,928 | 11,515 |
| Recourse\tdebt | 5,778 | 4,913 |
| Deferred\tincome\ttaxes | 981 | 627 |
| Pension\tliabilities | 1,273 | 216 |
| Long-term\tliabilities\tof\tdiscontinued\toperations\tand\tbusinesses\theld\tfor\tsale | 4,785 | 4,827 |
| Other\tlong-term\tliabilities | 2,065 | 1,739 |
| Total\tlong-term\tliabilities | 25,810 | 23,837 |
| Minority\tInterest\t(including\tdiscontinued\toperations\tof\t$41\t–\t2002;\t$124\t–\t2001) | 818 | 1,530 |
| Commitments\tand\tContingencies\t(Note\t11) | — | — |
| Company-Obligated\tConvertible\tMandatorily\tRedeemable\tPreferred\tSecurities\tof\tSubsidiary\tTrusts\tHolding\tSolely\tJunior |  |  |
| Subordinated\tDebentures\tof\tAES | 978 | 978 |
| Stockholders'\tEquity\t(Deficit): |  |  |
| Preferred\tstock,\tno\tpar\tvalue\t–\t50\tmillion\tshares\tauthorized;\tnone\tissued | — | — |
| outstanding\tin\t2002,\t645\tmillion\tissued\tand\t533\tmillion\toutstanding\tin\t2001 | 6 | 5 |
| Additional\tpaid-in\tcapital | 5,312 | 5,225 |
| Retained\tearnings\t(accumulated\tdeficit) | (700) | 2,809 |
| Accumulated\tother\tcomprehensive\tloss | (4,959) | (2,500) |
| Total\tstockholders'\t(deficit)\tequity | (341) | 5,539 |
| Total | $33,776 | $36,812 |

See	notes	to	consolidated	financial	statements.

# THE	AES	CORPORATION CONSOLIDATED	STATEMENTS	OF	OPERATIONS YEARS	ENDED	DECEMBER	31,	2002,	2001	AND	2000

(Amounts	in	Millions,	Except	Shares	and	Par	Value)

| Regulated | $4,317 | $3,255 | $2,661 |
| :--- | :--- | :--- | :--- |
| Non-regulated | 4,315 | 4,390 | 3,545 |
| Total\tRevenues | 8,632 | 7,645 | 6,206 |
| Cost\tof\tsales |  |  |  |
| Regulated | (3,627) | (2,416) | (2,093) |
| Non-regulated | (3,086) | (3,052) | (2,210) |
| Total\tcost\tof\tsales | (6,713) | (5,468) | (4,303) |
| Selling,\tgeneral\tand\tadministrative\texpenses | (112) | (120) | (82) |
| Severance\tand\ttransaction\tcosts | — | (131) | (79) |
| Interest\texpense | (2,031) | (1,575) | (1,262) |
| Interest\tincome | 312 | 189 | 201 |
| Other\tincome | 219 | 116 | 51 |
| Other\texpense | (87) | (65) | (52) |
| (Loss)\tgain\ton\tsale\tof\tinvestments\tand\tasset\timpairment |  |  |  |
| expense | (1,600) | 18 | 143 |
| Goodwill\timpairment\texpense | (612) | — | — |
| Foreign\tcurrency\ttransaction\tlosses | (456) | (30) | (4) |
| Equity\tin\tpre-tax\t(loss)\tearnings\tof\taffiliates | (203) | 176 | 475 |
| (LOSS)\tINCOME\tBEFORE\tINCOME\tTAXES\tAND |  |  |  |
| MINORITY\tINTEREST | (2,651) | 755 | 1,294 |
| Income\ttax\t(benefit)\texpense | (27) | 206 | 368 |
| Minority\tinterest\t(income)\texpense | (34) | 103 | 120 |
| (LOSS)\tINCOME\tFROM\tCONTINUING\tOPERATIONS | (2,590) | 446 | 806 |
| Loss\tfrom\toperations\tof\tdiscontinued\tbusinesses\t(net\tof |  |  |  |
| income\ttax\tbenefit\tof\t$90,\t$10\tand\t$5,\trespectively) | (573) | (173) | (11) |
| (LOSS)\tINCOME\tBEFORE\tCUMULATIVE\tEFFECT\tOF |  |  |  |
| ACCOUNTING\tCHANGE | (3,163) | 273 | 795 |
| Cumulative\teffect\tof\tchange\tin\taccounting\tprinciple\t(net\tof |  |  |  |
| income\ttax\tbenefit\tof\t$72) | (346) | — | — |
| Net\t(loss)\tincome | $(3,509) | $273 | $795 |
| BASIC\t(LOSS)\tEARNINGS\tPER\tSHARE: |  |  |  |
| (Loss)\tincome\tfrom\tcontinuing\toperations | $(4.81) | $0.84 | $1.67 |
| Discontinued\toperations | (1.05) | (0.32) | (0.01) |
| Cumulative\teffect\tof\taccounting\tchange | (0.65) | — | — |
| BASIC\t(LOSS)\tEARNINGS\tPER\tSHARE | $(6.51) | $0.52 | $1.66 |
| DILUTED\t(LOSS)\tEARNINGS\tPER\tSHARE: |  |  |  |
| (Loss)\tincome\tfrom\tcontinuing\toperations | $(4.81) | $0.83 | $1.61 |
| Discontinued\toperations | (1.05) | (0.32) | (0.02) |
| Cumulative\teffect\tof\taccounting\tchange | (0.65) | — | — |
| DILUTED\t(LOSS)\tEARNINGS\tPER\tSHARE | $(6.51) | $0.51 | $1.59 |

# CONSOLIDATED	STATEMENTS	OF	CASH	FLOWS

| Net	(loss)	income | $(3,509) | $273 | $795 |
| :--- | :--- | :--- | :--- |
| Adjustments\tto\tnet\t(loss)\tincome: |  |  |  |
| Cumulative\teffect\tof\tchange\tin\taccounting\tprinciple | 418 | — | — |
| Depreciation\tand\tamortization\t—\tcontinuing\tand\tdiscontinued\toperations | 837 | 859 | 697 |
| Loss\t(gain)\tfrom\tsale\tof\tinvestments\tand\tasset\timpairment\texpense | 1,600 | (18) | (143) |
| Goodwill\timpairment\texpense | 612 | — | — |
| Loss\ton\tdisposal\tand\timpairment\twrite-down\tassociated\twith\tdiscontinued\toperations | 784 | 193 | 27 |
| Provision\tfor\tdeferred\ttaxes | (315) | 47 | (2) |
| Minority\tinterest\t(earnings)\texpense | (34) | 103 | 120 |
| Foreign\tcurrency\ttransaction\tlosses | 456 | 30 | 4 |
| Loss\t(earnings)\tof\taffiliates,\tnet\tof\tdividends | 285 | (140) | (320) |

| Other | 16 | (61) | (56) |
| :--- | :--- | :--- | :--- |
| Changes\tin\toperating\tassets\tand\tliabilities: |  |  |  |
| Decrease\t(increase)\tin\taccounts\treceivable | 128 | 712 | (270) |
| Decrease\t(increase)\tin\tinventory | 129 | (10) | (56) |
| Increase\tin\tprepaid\texpenses\tand\tother\tcurrent\tassets | (301) | (34) | (156) |
| Decrease\t(increase)\tin\tother\tassets | (160) | 295 | (132) |
| (Decrease)\tincrease\tin\taccounts\tpayable | 286 | (125) | 257 |
| (Decrease)\tincrease\tin\taccrued\tinterest | 98 | (148) | 126 |
| Increase\t(decrease)\tin\taccrued\tand\tother\tliabilities | 73 | (368) | (225) |
| Increase\t(decrease)\tin\tother\tliabilities | 41 | 83 | (160) |
| Net\tcash\tprovided\tby\toperating\tactivities | 1,444 | 1,691 | 506 |
| INVESTING\tACTIVITIES: |  |  |  |
| Property\tadditions | (2,116) | (3,173) | (2,226) |
| Acquisitions-net\tof\tcash\tacquired | (35) | (1,365) | (1,818) |
| Increase\tin\tcash\tfrom\tEletropaulo\tshare\tswap | 162 | — | — |
| Proceeds\tfrom\tthe\tsales\tof\tassets | 375 | 505 | 234 |
| Sale\tof\tshort-term\tinvestments | 70 | 670 | 81 |
| Purchase\tof\tshort-term\tinvestments | (166) | (649) | (96) |
| Proceeds\tfrom\tsale\tof\tavailable-for-sale\tsecurities | 92 | 59 | 114 |
| Affiliate\tadvances\tand\tequity\tinvestments | (29) | (133) | (515) |
| Decrease\t(increase)\tin\trestricted\tcash | 25 | 832 | (1,110) |
| Project\tdevelopment\tcosts | (22) | (105) | (96) |
| Debt\tservice\treserves\tand\tother\tassets | 23 | 45 | (101) |
| Net\tcash\tused\tin\tinvesting\tactivities | (1,621) | (3,314) | (5,533) |
| FINANCING\tACTIVITIES: |  |  |  |
| Borrowings\t(repayments)\tunder\tthe\trevolving\tcredit\tfacilities,\tnet | 158 | (70) | (195) |
| Issuance\tof\tnon-recourse\tdebt\tand\tother\tcoupon\tbearing\tsecurities | 3,481 | 5,935 | 7,081 |
| Repayments\tof\tnon-recourse\tdebt\tand\tother\tcoupon\tbearing\tsecurities | (3,389) | (4,015) | (2,831) |
| Payments\tfor\tdeferred\tfinancing\tcosts | (67) | (153) | (136) |
| Distributions\tto\tminority\tinterests,\tnet | (11) | (70) | (54) |
| Issuance\tof\tcommon\tstock,\tnet | — | 14 | 1,508 |
| Common\tstock\tdividends\tpaid | — | (15) | (55) |
| Net\tcash\tprovided\tby\tfinancing\tactivities | 172 | 1,626 | 5,318 |
| Effect\tof\texchange\trate\tchanges\ton\tcash | (81) | (31) | (34) |
| Total\t(decrease)\tincrease\tin\tcash\tand\tcash\tequivalents | (86) | (28) | 257 |
| (Increase)\tdecrease\tin\tcash\tand\tcash\tequivalents\tof\tdiscontinued\toperations\tand\tbusinesses\theld\tfor\tsale | 64 | 107 | (48) |
| Cash\tand\tcash\tequivalents,\tbeginning | 802 | 723 | 514 |
| Cash\tand\tcash\tequivalents,\tending | $780 | $802 | $723 |
| SUPPLEMENTAL\tDISCLOSURES: |  |  |  |
| Cash\tpayments\tfor\tinterest-net\tof\tamounts\tcapitalized | $2,007 | $1,846 | $1,191 |
| Cash\tpayments\tfor\tincome\ttaxes-net\tof\trefunds | (3) | 254 | 216 |
| SCHEDULE\tOF\tNONCASH\tINVESTING\tAND\tFINANCING\tACTIVITIES: |  |  |  |
| Common\tstock\tissued\tfor\tacquisitions | — | 511 | 67 |
| Common\tstock\tissued\tfor\tdebt\tretirement | 73 | — | — |
| Liabilities\tassumed\tin\tpurchase\ttransactions | — | 1,362 | 2,098 |
| Liabilities\tconsolidated\tin\tEletropaulo\ttransaction | 4,907 | — | — |
| Conversion\tof\tAES\tTrust\tI\tand\tAES\tTrust\tII\t(see\tNote\t12) | — | — | 550 |

# CONSOLIDATED	STATEMENTS	OF	CHANGES	IN	STOCKHOLDERS'	EQUITY	(DEFICIT)

|  | Common	Stock<br>Shares | Amount | Additional<br>Paid-In<br>Capital | Retained<br>Earnings<br>(Accumulated<br>Deficit) | Accumulated<br>Other<br>Comprehensive<br>Loss | Treasury<br>Stock | Comprehensive |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (Amounts\tin\tMillions) |  |  |  |
| Balance\tat\tDecember\t31,\t1999 | 453.4 | $4 | $3,052 | $1,811 | $(995) | $(557) | $(295) |
| Net\tincome | — | — | — | 795 | — | — | $795 |
| Foreign\tcurrency\ttranslation\tadjustment\t(net\tof |  |  |  |  |  |  |  |
| income\ttax\tbenefit\tof\t$20) | — | — | — | — | (575) | — | (575) |
| Reclassification\tto\tearnings\tof\trealized\tgains\ton |  |  |  |  |  |  |  |
| marketable\tsecurities\t(net\tof\tincome\ttax\tbenefit |  |  |  |  |  |  |  |
| of\t$65) | — | — | — | — | (107) | — | (107) |

| income	tax	benefit	of	$1) | — | — | — | — | (2) | — | (2) |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Comprehensive\tincome |  |  |  |  |  |  | $111 |
| Dividends\tdeclared | — | — | — | (55) | — | — |  |
| Issuance\tof\tcommon\tstock\tthrough\tpublic |  |  |  |  |  |  |  |
| offerings\tand\tTecon\tconversions | 59.2 | 1 | 1,946 | — | — | — |  |
| Issuance\tof\tcommon\tstock\tpursuant\tto |  |  |  |  |  |  |  |
| acquisitions | 1.3 | — | 67 | — | — | — |  |
| Issuance\tof\tcommon\tstock\tunder\tbenefit\tplans |  |  |  |  |  |  |  |
| and\texercise\tof\tstock\toptions\tand\twarrants | 7.8 | — | 50 | — | — | 50 |  |
| Tax\tbenefit\tassociated\twith\tthe\texercise\tof |  |  |  |  |  |  |  |
| options | — | — | 57 | — | — | — |  |
| Balance\tat\tDecember\t31,\t2000 | 521.7 | 5 | 5,172 | 2,551 | (1,679) | (507) |  |
| Cumulative\teffect\tof\tadopting\tSFAS\tNo.\t133\ton |  |  |  |  |  |  |  |
| January\t1,\t2001\t(net\tof\tincome\ttax\tbenefit\tof |  |  |  |  |  |  |  |
| $50) | — | — | — | — | (93) | — | $(93) |
| Net\tincome | — | — | — | 273 | — | — | 273 |
| Foreign\tcurrency\ttranslation\tadjustment\t(net\tof |  |  |  |  |  |  |  |
| reclassification\tto\tearnings\tof\t$12,\tnet\tof\ttax,\tfor |  |  |  |  |  |  |  |
| the\tsale\tor\twrite\toff\tof\tinvestments\tin\tforeign |  |  |  |  |  |  |  |
| entities\tand\tan\tincome\ttax\tbenefit\tof\t$38) | — | — | — | — | (636) | — | (636) |
| Unrealized\tlosses\ton\tmarketable\tsecurities\t(no |  |  |  |  |  |  |  |
| income\ttax\teffect) | — | — | — | — | (48) | — | (48) |
| Minimum\tpension\tliability\tadjustment\t(net\tof |  |  |  |  |  |  |  |
| income\ttax\tbenefit\tof\t$10) | — | — | — | — | (16) | — | (16) |
| Change\tin\tderivative\tfair\tvalue\t(including\ta |  |  |  |  |  |  |  |
| reclassification\tto\tearnings\tof\t($32)\tmillion,\tnet |  |  |  |  |  |  |  |
| of\ttax,\tand\tan\tincome\ttax\tbenefit\tof\t$11) | — | — | — | — | (28) | — | (28) |
| Comprehensive\tloss |  |  |  |  |  |  | $(548) |
| Dividends\tdeclared | — | — | — | (15) | — | — |  |
| Issuance\tof\tcommon\tstock\tpursuant\tto |  |  |  |  |  |  |  |
| acquisitions | 9.4 | — | 511 | — | — |  |  |
| Retirement\tof\ttreasury\tstock | — | — | (507) | — | — | 507 |  |
| Issuance\tof\tcommon\tstock\tunder\tbenefit\tplans |  |  |  |  |  |  |  |
| and\texercise\tof\tstock\toptions\tand\twarrants | 2.1 | — | 34 | — | — | — |  |
| Tax\tbenefit\tassociated\twith\tthe\texercise\tof |  |  |  |  |  |  |  |
| options | — | — | 15 | — | — | — |  |
| Balance\tat\tDecember\t31,\t2001 | 533.2 | $5 | $5,225 | $2,809 | $(2,500) | $— |  |

|  | Common	Stock<br>Shares | Amount | Additional<br>Paid-In<br>Capital | Retained<br>Earnings<br>(Accumulated<br>Deficit) | Accumulated<br>Other<br>Comprehensive<br>Loss | Treasury<br>Stock |  | Comprehensive |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (Amounts\tin\tMillions) |  |  |  |  |
| Balance\tat\tDecember\t31,\t2001 | 533.2 | $5 | $5,225 | $2,809 | $(2,500) $ |  | — |  |
| Net\tloss | — | — | — | (3,509) | — |  | — | $(3,509) |
| Foreign\tcurrency\ttranslation |  |  |  |  |  |  |  |  |
| adjustment\t(net\tof\treclassification\tto |  |  |  |  |  |  |  |  |
| earnings\tof\t$65,\tnet\tof\ttax,\tfor\tthe\tsale |  |  |  |  |  |  |  |  |
| or\twrite\toff\tof\tinvestments\tin\tforeign |  |  |  |  |  |  |  |  |
| entities\t(no\tincome\ttax\teffect) | — | — | — | — | (1,677) |  | — | (1,677) |
| Realized\tlosses\ton\tmarketable |  |  |  |  |  |  |  |  |
| securities\t(no\tincome\ttax\teffect) | — | — | — | — | 48 |  | — | 48 |
| Minimum\tpension\tliability\tadjustment |  |  |  |  |  |  |  |  |
| (net\tof\tincome\ttax\tbenefit\tof\t$229) | — | — | — | — | (553) |  | — | (553) |
| Change\tin\tderivative\tfair\tvalue |  |  |  |  |  |  |  |  |
| (including\ta\treclassification\tto |  |  |  |  |  |  |  |  |
| earnings\tof\t($106)\tmillion,\tnet\tof\ttax, |  |  |  |  |  |  |  |  |
| and\tan\tincome\ttax\tbenefit\tof\t$41) | — | — | — | — | (277) |  | — | (277) |
| Comprehensive\tloss |  |  |  |  |  |  |  | $(5,968) |
| Issuance\tof\tcommon\tstock\tin |  |  |  |  |  |  |  |  |
| exchange\tfor\tcancellation\tof\tdebt | 21.6 | 1 | 73 | — | — |  | — |  |
| Issuance\tof\tcommon\tstock\tunder |  |  |  |  |  |  |  |  |
| benefit\tplans\tand\texercise\tof\tstock |  |  |  |  |  |  |  |  |
| options\tand\twarrants | 3.1 | — | 14 | — | — |  | — |  |
| Balance\tat\tDecember\t31,\t2002 | 557.9 | $6 | $5,312 | $(700) $ | (4,959) $ |  | — |  |

# NOTES	TO	CONSOLIDATED	FINANCIAL	STATEMENTS

# 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):

|  | 2002 | 2001 |
| :--- | :--- | :--- |
| Coal,\tfuel\toil,\tand\tother\traw\tmaterials | $281 | $334 |
| Spare\tparts\tand\tsupplies | 217 | 292 |
| Total | 498 | 626 |
| Less:\tInventory\tof\tdiscontinued\toperations | (114) | (158) |
|  | $384 | $468 |

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,	3.86%,	3.57%	and	3.68%	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\tand\tDistribution\tFacilities | 2.0%\t–\t10.0% | 10\t–\t50\tyrs. |
| Other\tBuildings | 2.5%\t–\t\t5.0% | 20\t–\t40\tyrs. |
| Leasehold\tImprovements | 3.3%\t–\t10.0% | 10\t–\t30\tyrs. |
| Furniture\tand\tFixtures | 14.3%\t–\t50.0% | \t\t2\t–\t\t7\tyrs. |

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	$302	million,	$295	million,	and	$225	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 .	Prior	to	January	1,	2002,	goodwill	was st 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	$178	million and	$154	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.

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	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	$948	million,	$970	million	and	$639	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	$11	million	and	$12	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,	Sul	and	Uruguaiana.	There	were	three	parts	of	the	agreement	that	specifically	affected	AES. The	terms	of	the	agreement	were	implemented	during	2002.

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.	Currently,	ten	companies	are under	the	tariff	reset	public	hearing	process,	including	Sul.	These	results	are	likely	to	influence	Eletropaulo's	tariff	reset.

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:

|  | 2002 | 2001 | 2000 |
| :--- | :--- | :--- | :--- |
| Interest\trate\t(risk-free) | 3.83% | 4.84% | 5.4% |
| Volatility | 68% | 86% | 41% |
| Dividend\tyield | — | — | 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):

|  | 2002 | 2001 | 2000 |
| :--- | :--- | :--- | :--- |
| NET\tINCOME: |  |  |  |
| As\treported | $(3,509) | $273 | $795 |
| Pro\tforma | (3,657) | 179 | 753 |
| BASIC\tEARNINGS\tPER\tSHARE: |  |  |  |
| As\treported | $(6.51) | $0.52 | $1.66 |
| Pro\tforma | (6.79) | 0.34 | 1.56 |
| DILUTED\tEARNINGS\tPER\tSHARE: |  |  |  |
| As\treported | $(6.51) | $0.51 | $1.59 |
| Pro\tforma | (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 | $1,820 |
| IPALCO | 215 |
| Consolidated\tRevenues | $2,035 |
| Net\tIncome: |  |
| AES | $129 |
| IPALCO | (18) |
| Consolidated\tNet\tIncome | $111 |

|  | AES | IPALCO | Combined |
| :--- | :--- | :--- | :--- |
| Comprehensive\tLoss: |  |  |  |
| Net\tIncome\t(Loss) | $129 | $(18) | $111 |
| Foreign\tcurrency\ttranslation\tadjustment | (236) | — | (236) |
| Change\tin\tderivative\tfair\tvalue | (50) | — | (50) |
| Minimum\tpension\tliability | — | (2) | (2) |

|  | (93) | — | (93) |
| :--- | :--- | :--- | :--- |
| Comprehensive\tLoss | $(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.

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.

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,	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	$500	million	in	cash	proceeds,	net	of	transaction	expenses.	CILCORP	was	previously	reported	in	the	large	utilities	segment.

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	$1,714	million,	$1,991	million	and	$1,400	million	for	the	years	ended	December	31,	2002,	2001	and	2000,	respectively.	The	pretax income	associated	with	the	discontinued	operations	were	$121	million,	$10	million	and	$11	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 $633	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\tmillions) | (in\tmillions) |
| ASSETS: |  |  |
| Cash | $109 | $62 |
| Accounts\treceivable,\tnet | 183 | 444 |
| Inventory | 115 | 159 |
| PP&amp;E | 4,234 | 5,322 |
| Other\tassets | 954 | 1,398 |
| Total\tassets | $5,595 | $7,385 |
| LIABILITIES: |  |  |
| Accounts\tpayable | $104 | $92 |
| Current\tportion\tof\tlong-term\tdebt | 170 | 223 |
| Long-term\tdebt | 3,242 | 3,156 |
| Other\tliabilities | 1,706 | 1,871 |
| Total\tliabilities | $5,222 | $5,342 |

# 5.				OTHER	SALE	OF	ASSETS	AND	ASSET	IMPAIRMENT	EXPENSE

Drax,	is	the	operator	of	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	is	available	for	immediate	sale,	and	a	plan	has	been	established	to	locate	a	buyer at	a	reasonable	fair	market	price.	The	Company	believes	it	will	sell	the	business	within	one	year	and	it	is	unlikely	that	significant	changes	will	be	made	to	the	plan	to	sell. The	Company	expects	to	have	a	significant	continuing	involvement	in	the	operations	of	the	business	after	the	sale	transaction.	Accordingly,	Drax	is	classified	as	an	asset held	for	sale	in	the	accompanying	consolidated	balance	sheets	as	of	December	31,	2002	and	2001,	and	is	classified	as	a	competitive	supply	business.

Barry	had	a	tolling	agreement	with	TXU	EET	which	contracted	all	of	the	output	of	the	Barry	plant.	The	TXU	EET	administration	discussed	above	constituted	a	change	in circumstance,	as	defined	by	SFAS	No.	144,	that	indicated	that	the	carrying	amount	of	the	Barry	long-lived	net	assets	may	not	be	recoverable.	Accordingly,	in	the	fourth quarter	of	2002,	a	pre-tax	impairment	charge	of	$172	million	($120	million	after-tax)	was	recorded	to	write-down	the	long-lived	net	assets	of	Barry	to	their	fair	value. The	approximate	fair	value	of	long-lived	assets	was	determined	by	discounting	the	projected	future	cash	flows	of	the	business.	Barry	is	a	competitive	supply	business.

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<br>Generation | Competitive<br>Supply | Large<br>Utilities | Growth<br>Distribution | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Carrying\tamount\tat\tDecember\t31,\t2001 | $1,124 | $149 | $— | $1,094 | $2,367 |
| Goodwill\tacquired\tduring\tthe\tperiod | — | — | 780 | — | 780 |
| Impairment\tlosses\tfrom\tannual\tanalysis | — | (5) | (607) | — | (612) |
| Impairment\tlosses\tfrom\tadoption\tof\tSFAS\tNo.\t142 | — | (80) | — | (681) | (761) |
| Concessions\treclassed\tto\tother\tassets | (11) | — | — | (152) | (163) |
| Translation\tadjustments\tand\tother | (7) | (2) | (173) | (41) | (223) |
| Carrying\tamount\tat\tDecember\t31,\t2002 | $1,106 | $62 | $— | $220 | $1,388 |

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):

|  | 2002 | 2001 | 2000 |
| :--- | :--- | :--- | :--- |
| Net\t(loss)\tincome | $(3,509) | $273 | $795 |
| Add\tback:\tGoodwill\tamortization | — | 70 | 47 |
| Adjusted\tnet\t(loss)\tincome | $(3,509) | $343 | $842 |
| Basic\t(loss)\tearnings\tper\tshare: |  |  |  |
| Reported\tbasic\t(loss)\tearnings\tper\tshare | $(6.51) | $0.52 | $1.66 |
| Goodwill\tamortization | — | 0.13 | 0.10 |
| Adjusted\tbasic\t(loss)\tearnings\tper\tshare | $(6.51) | $0.65 | $1.76 |
| Diluted\t(loss)\tearnings\tper\tshare: |  |  |  |
| Reported\tdiluted\t(loss)\tearnings\tper\tshare | $(6.51) | $0.51 | $1.59 |
| Goodwill\tamortization | — | 0.13 | 0.09 |
| Adjusted\tdiluted\t(loss)\tearnings\tper\tshare | $(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\tIncome | 695 | 1,717 | 1,989 |
| Net\tIncome | 229 | 650 | 859 |
| Current\tAssets | 1,097 | 3,700 | 2,423 |
| Noncurrent\tAssets | 6,751 | 14,942 | 13,080 |
| Current\tLiabilities | 1,418 | 3,510 | 3,370 |
| Noncurrent\tLiabilities | 3,349 | 8,297 | 5,927 |
| Stockholder's\tEquity | 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\taffiliates | China | 30.00 | 30.00 | 30.00 |
| EDC\taffiliates | Venezuela | 45.00 | 45.00 | 45.00 |
| Eletropaulo | Brazil | — | 50.43 | 49.60 |
| Elsta | Netherlands | 50.00 | 50.00 | 50.00 |
| Gener\taffiliates | Chile | 37.50 | 37.50 | — |
| Infovias | Brazil | — | 50.00 | 50.00 |
| Itabo | Dominican\tRepublic | 25.00 | 25.00 | 25.00 |
| Kingston\tCogen\tLtd | Canada | 50.00 | 50.00 | 50.00 |
| Light | Brazil | — | 23.89 | 21.14 |
| Medway\tPower,\tLtd | United\tKingdom | 25.00 | 25.00 | 25.00 |
| OPGC | India | 49.00 | 49.00 | 49.00 |
| Songas\tLimited | 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.

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

|  | 2002 | 2001 |
| :--- | :--- | :--- |
| HELD-TO-MATURITY: |  |  |
| Certificates\tof\tdeposit | $168 | $106 |
| Money\tmarket\tfunds | 40 | 1 |
| Debt\tsecurities\tissued\tby\tforeign\tgovernments | — | 2 |
| Other | 1 | 2 |
| Subtotal | 209 | 111 |
| AVAILABLE-FOR-SALE: |  |  |
| Equity\tsecurities | — | 103 |
| Corporate\tBonds | 2 | — |
| Subtotal | 2 | 103 |
| TRADING:\nEquity\tsecurities | — | 1 |
| TOTAL | $211 | $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.

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

|  | Interest<br>Rate	(1) | Final<br>Maturity | 2002 | 2001 |
| :--- | :--- | :--- | :--- | :--- |
| VARIABLE\tRATE: |  |  |  |  |
| Bank\tloans | 7.75% | 2022 | $7,258 | $5,760 |
| Commercial\tpaper | 5.72% | 2008 | 406 | 501 |
| Notes\tand\tBonds | 8.82% | 2030 | 856 | 889 |
| Debt\tto\t(or\tguaranteed\tby)\tmultilateral\tor\texport\tcredit\tagencies | 5.16% | 2024 | 934 | 945 |
| Other | 13.14% | 2022 | 455 | 602 |

FIXED	RATE:

| Bank	loans | 9.43% | 2014 | 982 | 1,892 |
| :--- | :--- | :--- | :--- | :--- |
| Commercial\tPaper | 11.93% | 2005 | 146 | 63 |
| Notes\tand\tbonds | 8.82% | 2029 | 5,995 | 5,922 |
| Debt\tto\t(or\tguaranteed\tby)\tmultilateral\tor\texport\tcredit\tagencies | 4.89% | 2016 | 347 | 165 |
| Other | 1.72% | 2027 | 279 | 118 |
| SUBTOTAL |  |  | 17,658 | 16,857 |
| Less:\tNon-recourse\tdebt\tof\tdiscontinued\toperations |  |  | (3,415) | (3,381) |
| SUBTOTAL |  |  | 14,243 | 13,476 |
| Less:\tCurrent\tmaturities |  |  | (3,315) | (1,961) |
| TOTAL |  |  | $10,928 | $11,515 |

# (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.

With	the	exception	of	Eletropaulo,	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.

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.

EDC,	a	subsidiary	of	the	Company,	was	not	in	compliance	with	two	of	its	net	worth	covenants	on	$131	million	and	$9	million	of	non-recourse	debt	primarily	due	to	the impact	of	the	devaluation	of	the	Venezuelan	Bolivar.	EDC	requested	and	received	from	its	lenders	waivers	for	both	covenants,	which	are	effective	through	March	31, 2003.	Of	the	related	debt	approximately	$102	million	is	classified	as	non-recourse	debt—long	term	in	the	accompanying	consolidated	balance	sheets.	The	remainder	is classified	as	non-recourse	debt—current.

On	December	13,	2002,	Drax	signed	a	standstill	agreement	with	its	senior	lenders	to	provide	Drax	time	to	restructure	its	business	after	the	termination	of	the	Hedging Agreement.	The	standstill	agreement	provides	temporary	and/or	permanent	waivers	by	the	senior	lenders	of	defaults	that	have	occurred	or	could	occur	up	to	the	expiry	of the	standstill	period	on	May	31,	2003	including	a	permanent	waiver	resulting	from	termination	of	the	Hedging	Contract	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	at	that	time.	Drax	expects	that	the ratios,	if	calculated	as	of	December	31,	2002,	would	again	be	below	the	required	levels	at	December	31,	2002	since	any	improvement	in	the	ratios	for	the	period	ended December	31,	2002	would	have	required	a	favorable	change	in	the	forward	curve	for	electricity	prices	during	the	period	from	June	30,	2002	to	December	31,	2002	and such	favorable	change	did	not	occur.	As	part	of	the	standstill	agreement	signed	by	Drax	and	its	senior	lenders,	the	debt	service	coverage	ratios	as	of	December	31,	2002 were	not	calculated	by	the	bank	group.	As	a	consequence	of	the	foregoing,	Drax	was	not	permitted	to	make	any	distributions	to	Drax	Energy	and	Drax	Energy	was unable	to	make	the	full	amount	of	the	interest	payment	of	$11.5	million	and	£7.6	million	due	on	its	high	yield	notes	on	February	28,	2003.	Drax	Energy's	failure	to	make the	full	amount	of	the	required	interest	payment	constitutes	an	event	of	default	under	its	high	yield	notes,	although	pursuant	to	intercreditor	agreements	the	holders	of	the high	yield	notes	have	no	enforcement	rights	until	90	days	following	the	delivery	of	certain	notices	under	the	intercreditor	arrangements.	Drax	is	currently	a	material subsidiary	for	certain	bankruptcy-related	events	of	default,	and	therefore	certain	bankruptcy	events	of	Drax	could	result	in	a	default	under	our	corporate	debt	agreements. Given	the	default	remedies	to	the	lenders,	the	Company	believes	that	a	bankruptcy	event	is	unlikely.

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<br>Rate	(1) | Final<br>Maturity | First	Call<br>Date	(2) | 2002 | 2001 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Corporate\trevolving\tbank\tloan | — | 2002 | 2000 | $— | $70 |
| Corporate\trevolving\tbank\tloan | 8.10% | 2005 | — | 228 | — |
| Term\tloan | — | 2002 | — | — | 425 |
| Term\tloan | — | 2002 | — | — | 188 |
| Term\tloan | 8.12% | 2005 | — | 500 | — |
| Term\tloan | 7.99% | 2005 | — | 427 | — |
| Term\tloan | 7.94% | 2005 | — | 260 | — |
| Senior\tnotes | — | 2002 | — | — | 300 |
| Senior\tnotes | 8.00% | 2008 | 2000 | 199 | 200 |
| Senior\tnotes | 9.50% | 2009 | — | 750 | 750 |
| Senior\tnotes | 9.38% | 2010 | — | 850 | 850 |
| Senior\tnotes | 8.88% | 2011 | — | 537 | 600 |
| Senior\tnotes | 8.38% | 2011 | — | 217 | 196 |
| Senior\tnotes | 8.75% | 2008 | — | 400 | 400 |
| Senior\tnotes | 10.00% | 2005 | — | 258 | — |
| Remarketable\tor\tRedeemable\tSecurities | 7.38% | 2013 | 2003 | 26 | 200 |
| Senior\tsubordinated\tnotes | 10.25% | 2006 | 2001 | 231 | 250 |
| Senior\tsubordinated\tnotes | 8.38% | 2007 | 2002 | 316 | 325 |
| Senior\tsubordinated\tnotes | 8.50% | 2007 | 2002 | 349 | 375 |
| Senior\tsubordinated\tdebentures | 8.88% | 2027 | 2004 | 125 | 125 |
| Convertible\tjunior\tsubordinated\tdebentures | 4.50% | 2005 | 2001 | 150 | 150 |
| Unamortized\tdiscounts |  |  |  | (19) | (3) |
| SUBTOTAL |  |  |  | 5,804 | 5,401 |
| Less:\tCurrent\tmaturities |  |  |  | (26) | (488) |
| Total |  |  |  | $5,778 | $4,913 |

(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

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 | $3,341 |
| :--- | :--- |
| 2004 | 2,089 |
| 2005 | 2,653 |
| 2006 | 1,616 |
| 2007 | 1,352 |
| Thereafter | 8,996 |
| Total | $20,047 |

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

| 2003 | $204 |
| :--- | :--- |
| 2004 | 198 |
| 2005 | 104 |
| 2006 | 96 |
| 2007 | 154 |
| Thereafter | 2,659 |
| Total | $3,415 |

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:

•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	gain	of	$42	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):

|  | 2002 | 2001 |
| :--- | :--- | :--- |
| Balance,\tbeginning\tof\tyear | $(121) | $— |
| Transition\tadjustment\ton\tJanuary\t1,\t2001 | — | (93) |
| Reclassification\tto\tearnings | (106) | (32) |
| Change\tin\tfair\tvalue | (171) | 4 |
| Balance,\tDecember\t31 | $(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,	2001and	2000,	respectively,	including	commitments	of	businesses	classified	as	discontinued	amounting	to	$6	million	in	2002,	$16	million	in 2001	and	$6	million	in	2000.

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

|  | Total | Discontinued<br>Operations |
| :--- | :--- | :--- |
| 2003 | $30 | $4 |
| 2004 | 20 | 4 |
| 2005 | 15 | 3 |
| 2006 | 11 | 1 |
| 2007 | 9 | 1 |
| Thereafter | 84 | 1 |
| Total | $169 | $14 |

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<br>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	$399	million.

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

|  | Total | Discontinued<br>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<br>Agreements |  | Term<br>Range<br>(years) | Maximum<br>Exposure<br>Range<br>for	Each<br>Agreement | Credit<br>Enhancements<br>for	Non-Recourse	Debt | Performance<br>Related<br>Obligations |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (amounts\tin\t$millions,\texcept\tagreements\tand\tyears) | (amounts\tin\t$millions,\texcept\tagreements\tand\tyears) |  |  |
| Guarantees | $652 |  | 52 | &lt;1\t–\t20+ | &lt;$1\t–\t$100 | $273 | $379 |
| Letters\tof\tcredit\t—\tunder\tthe\tRevolver. | 104 |  | 14 | &lt;1\t–\t2 | &lt;$1\t–\t$36 | 51 | 53 |
| Letters\tof\tcredit\t—\toutside\tthe\tRevolver | 109 |  | 5 | &lt;1\t–\t2 | &lt;$1\t–\t$84 | 84 | 25 |
| Surety\tbonds | 6 |  | 6 | &lt;1 | &lt;$1\t–\t$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	the	Company's	joint	venture	("SEB")	and	the	state	of	Minas	Gerais	concerning	CEMIG	which	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	November	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	April	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.	In	August	2002,	SEB	filed	two	interlocutory	appeals	against	the state	appellate	court's	refusal	to	consider	SEB's	appeal	on	the	merits,	one	directed	to	the	Federal	Superior	Court	and	the	other	to	the	Supreme	Court	of	Justice.	The appeals	continue	to	be	pending.	The	Company,	together	with	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	the	Company	and	SEB	will	be	successful	in	their	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.	In	December	2000,	the	case	was	removed	from	the	San	Diego	County	Superior	Court	to

the	U.S.	District	Court	for	the	Southern	District	of	California.	The	case	has	been	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.	Defendants	have	filed	a	motion	to	dismiss	the	action	in	its	entirety. 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	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	4,	2002,	six	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	stock	between	April	26,	2001	and 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	seven	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	consolidation	action	to	the	United	States	District	Court	for	the	Southern	District	of	Indiana. The	Company	and	the	individuals	believe	that	they	have	meritorious	defenses	to	the	claims	asserted	against	them	and	intend	to	defend	the	lawsuit	vigorously.

recover	approximately	$13	million	dollars	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	dollars	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	portion	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	Company	believes	it	has	meritorious defenses	to	the	claims	asserted	against	it	and	intends	to	defend	the	lawsuits	vigorously.

The	Company	is	also	involved	in	certain	legal	proceedings	in	the	normal	course	of	business.	Certain	claims,	suits	and	complaints	have	been	filed	or	are	pending	against the	Company.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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	the	fourth	quarter	of	2001. 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.

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	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):

| Outstanding	—	beginning	of	year | 33,142 | $16.58 | 13,789 | $14.11 | 15,500 | $9.19 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Exercised\tduring\tthe\tyear | (228) | 5.10 | (1,508) | 8.95 | (3,612) | 6.01 |
| Forfeited\tduring\tthe\tyear | (813) | 8.90 | (216) | 32.92 | (175) | 27.71 |
| Granted\tduring\tthe\tyear | 1,143 | 2.66 | 21,077 | 17.82 | 2,076 | 37.86 |
| Outstanding\t—\tend\tof\tyear | 33,244 | 16.37 | 33,142 | 16.58 | 13,789 | 14.11 |
| Eligible\tfor\texercise\t—\tend\tof\tyear | 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):

| Range	of	Exercise	Prices | Total<br>Outstanding | Weighted-<br>Average<br>Remaining<br>Life<br>(In	Years) |  | Weighted-<br>Average<br>Exercise	Price | Total<br>Exercisable | Weighted-<br>Average<br>Exercise	Price |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| $0.78\t–\t$3.24 | 1,048 |  | 9.6 | $2.15 | —\t $— | —\t $— |
| $3.25\t–\t$9.88 | 4,787 |  | 2.5 | 5.39 | 4,707 | 5.34 |
| $9.89\t–\t$14.40 | 19,828 |  | 8.4 | 13.03 | 19,775 | 13.04 |
| $14.41\t–\t$22.85 | 2,924 |  | 5.7 | 17.85 | 2,884 | 17.89 |
| $22.86\t–\t$58.00 | 4,648 |  | 7.4 | 44.11 | 3,683 | 41.85 |
| $58.01\t–\t$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.

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):

|  | Income | Shares | $	per<br>Share | Income | Shares | $	per<br>Share | Income | Shares | $	per<br>Share |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| BASIC\t(LOSS)\tEARNINGS\tPER\tSHARE: |  |  |  |  |  |  |  |  |  |
| (Loss)\tincome\tfrom\tcontinuing\toperations | $(2,590) | 538.9 | $(4.81) | $446 | 532.2 | $0.84 | $806 | 482.1 | $1.67 |
| EFFECT\tOF\tDILUTIVE\tSECURITIES: |  |  |  |  |  |  |  |  |  |
| Stock\toptions\tand\twarrants | — | — | — | — | 5.3 | (0.01) | — | 9.9 | (0.03) |
| Stock\tunits\tallocated\tto\tdeferred\tcompensation\tplans | — | — | — | — | 0.6 | — | — | 0.5 | — |
| Tecons\tand\tother\tconvertible\tdebt,\tnet\tof\ttax | — | — | — | — | — | — | 19 | 21.1 | (0.03) |
| DILUTED\t(LOSS)\tEARNINGS\tPER\tSHARE | $(2,590) | 538.9 | $(4.81) | $446 | 538.1 | $0.83 | $825 | 513.6 | $1.61 |

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):

|  | 2002 | 2001 | 2000 |
| :--- | :--- | :--- | :--- |
| Gain\ton\tsale\tof\tassets | $12 | $26 | $24 |
| Gain\ton\textinguishment\tof\tliabilities | 68 | 9 | 3 |
| Marked-to-market\tgain\ton\tcommodity\tderivatives | 101 | 9 | — |
| Marked-to-market\tgain\ton\tinvestment | — | 19 | — |
| Legal/dispute\tsettlement | 12 | — | 16 |
| Dividends | — | 41 | 6 |
| Rent | — | 7 | — |
| Other\tnon-operating\tincome | 26 | 5 | 2 |
| Total\tother\tincome | $219 | $116 | $51 |

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

|  | 2002 | 2001 | 2000 |
| :--- | :--- | :--- | :--- |
| Marked-to-market\tloss\ton\tcommodity\tderivatives | $— | $(30) | $— |
| Loss\ton\tsale\tand\tdisposal\tof\tassets | (35) | (13) | (14) |
| Loss\ton\textinguishment\tof\tliabilities | — | — | (16) |
| Legal/dispute\tsettlement | (11) | (3) | — |
| Environmental\tfine | — | — | (17) |
| Other\tnon-operating\texpenses | (41) | (19) | (5) |
| Total\tother\texpense | $(87) | $(65) | $(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.

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

| Deferred | 60 | (12) | (29) |
| :--- | :--- | :--- | :--- |
| State: |  |  |  |
| Current | 6 | — | 20 |
| Deferred | (17) | 7 | (2) |
| Foreign: |  |  |  |
| Current | 118 | 179 | 204 |
| Deferred | (194) | 30 | 29 |
| Total | $(27) | $206 | $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, | Years	Ended	December	31, | Years	Ended	December	31, |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2002 | 2001 |  | 2000 |  |
| Statutory\tFederal\ttax\trate | 35% |  | 35% |  | 35% |
| State\ttaxes,\tnet\tof\tFederal\ttax\tbenefit | 1 |  | 1 |  | 1 |
| Taxes\ton\tforeign\tearnings | (2) |  | (4) |  | (3) |
| Valuation\tallowance | (32) |  | — |  | — |
| Other-net | (1) |  | — |  | (2) |
| Effective\ttax\trate | 1% |  | 32% |  | 31% |

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	$759	million	during	2002	to	$876	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):

|  | 2002 | 2001 |
| :--- | :--- | :--- |
| Differences\tbetween\tbook\tand\ttax\tbasis\tof\tproperty | $1,196 | $1,274 |
| Other\ttaxable\ttemporary\tdifferences | 121 | 109 |
| Total\tdeferred\ttax\tliability | $1,317 | $1,383 |
| Operating\tloss\tcarry\tforwards | (787) | (469) |
| Capital\tloss\tcarry\tforwards | (348) | — |
| Bad\tdebt\tand\tother\tbook\tprovisions | (153) | (109) |
| Retirement\tcosts | (389) | (66) |
| Tax\tcredit\tcarry\tforwards | (91) | (135) |
| Other\tdeductible\ttemporary\tdifferences | (542) | (338) |
| Total\tgross\tdeferred\ttax\tasset | (2,310) | (1,117) |
| Less:\tvaluation\tallowance | 876 | 117 |
| Total\tnet\tdeferred\ttax\tasset | (1,434) | (1,000) |
| Net\tdeferred\ttax\t(asset)/liability | $(117) | $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:

|  | 2002 | 2001 | 2000 |
| :--- | :--- | :--- | :--- |
| U.S | $(173) | $288 | $614 |
| Non\tU.S | (2,444) | 364 | 560 |
| Total | $(2,617) | $652 | $1,174 |

# 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	fifteen	defined	benefit	plans,	four

are	at	U.S.	subsidiaries	and	the	remaining	are	at	foreign	subsidiaries.	These	include	one	domestic	and	one	foreign	plan	maintained	at	businesses	classified	as	held	for sale	or	discontinued	operations	at	December	31,	2002.	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:

|  | U.S. | Foreign |  |  |
| :--- | :--- | :--- | :--- | :--- |
| Discount\trates | 6.5% | 8.7% | 7.0% | 7.2% |
| Rates\tof\tcompensation\tincrease | 1.7% | 5.7% | 3.2% | 3.1% |
| Expected\tlong-term\trate\tof\treturn\ton\tplan\tassets | 8.9% | 13.2% | 9.1% | 9.1% |

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):

|  | U.S. | Foreign |  |  |
| :--- | :--- | :--- | :--- | :--- |
| Service\tcost | $7 | $7 | $9 | $14 |
| Interest\tcost\ton\tprojected\tbenefit\tobligation | 50 | 136 | 61 | 55 |
| Expected\treturn\ton\tplan\tassets | (48) | (87) | (54) | (63) |
| Amount\tof\tcurtailment\t(gain)\tloss\trecognized | (1) | 3 | 6 | 6 |
| VERP\tbenefits | 3 | — | 19 | 57 |
| Amortization\tof\tunrecognized\tactuarial\tloss\t(gain) | 1 | 16 | 1 | (3) |
| Total\tpension\tcost | $12 | $75 | $42 | $66 |

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

|  | U.S. | Foreign |  |
| :--- | :--- | :--- | :--- |
| CHANGE\tIN\tBENEFIT\tOBLIGATION: |  |  |  |
| Benefit\tobligation\tat\tbeginning\tof\tyear | $727 | $182 | $827 |
| Effect\tof\tforeign\tcurrency\texchange\trate\tchange\ton\tbeginning\tbalance | — | (56) | (25) |
| Service\tcost | 7 | 7 | 9 |
| Interest\tcost | 50 | 136 | 61 |
| Plan\tacquired | — | 1,526 | 4 |
| VERP\tbenefits | 3 | — | 19 |
| Benefits\tpaid | (53) | (121) | (61) |
| Actuarial\tloss | 49 | 222 | 86 |
| Other | 8 | 6 | (11) |
| Benefit\tobligation\tas\tof\tDecember\t31 | $791 | $1,902 | $909 |

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

|  | U.S. | Foreign |  |
| :--- | :--- | :--- | :--- |
| CHANGE\tIN\tPLAN\tASSETS: |  |  |  |
| Fair\tvalue\tof\tplan\tassets\tat\tbeginning\tof\tyear | $549 | $55 | $685 |
| Fair\tvalue\tof\tplan\tacquired | — | 698 | — |
| Effect\tof\tforeign\tcurrency\texchange\trate\tchange\ton\tbeginning\tbalance | — | (2) | (6) |
| Actual\treturn\ton\tplan\tassets | (40) | 52 | (32) |
| Benefits\tpaid | (53) | (121) | (58) |
| Employer\tContributions | 19 | 147 | 29 |
| Other | (1) | 1 | (14) |
| Fair\tvalue\tof\tplan\tassets\tas\tof\tDecember\t31 | $474 | $830 | $604 |

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

|  | U.S. | Foreign |  |
| :--- | :--- | :--- | :--- |
| Funded\tstatus | $(317) | $(1,072) | $(305) |
| Unrecognized\tnet\tactuarial\tloss | 221 | 613 | 92 |
| Other | — | (7) | 2 |
| Accrued\tbenefit\tcost\tas\tof\tDecember\t31 | $(96) | $(466) | $(211) |

|  | U.S. | Foreign |  |
| :--- | :--- | :--- | :--- |
| Accrued\tbenefit\tliability | $(273) | $(1,089) | $(237) |
| Accumulated\tother\tcomprehensive\tloss | 177 | 623 | 26 |
| Net\tamount\trecognized | $(96) | $(466) | $(211) |

All	of	the	Company's	pension	plans	have	been	aggregated	in	the	table	above.	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	include	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	held	for	sale	or	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.

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<br>and<br>Amortization | Gross<br>Margin(2) | Pre-Tax<br>Equity	in<br>(Loss)<br>Earnings(3) | Total<br>Assets | Investment<br>in	and<br>Advances	to<br>Affiliates | Property<br>Additions |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Year\tEnded\tDecember\t31,\t2002 |  |  |  |  |  |  |  |
| Contract\tGeneration | $2,478 | $232 | $1,050 | $75 | $12,640 | $671 | $1,009 |
| Competitive\tSupply | 1,837 | 181 | 179 | (3) | 7,294 | 7 | 470 |
| Large\tUtilities | 3,137 | 286 | 685 | (275) | 7,967 | (484) | 300 |
| Growth\tDistribution | 1,180 | 96 | 5 | — | 3,040 | (20) | 102 |
| Discontinued\tBusinesses | — | — | — | — | 2,432 | — | 234 |
| Corporate | — | 2 | — | — | 403 | 20 | 1 |
| Total | $8,632 | $797 | $1,919 | $(203) $ | 33,776 | $194 | $2,116 |

|  | Revenues(1) | Depreciation<br>and<br>Amortization | Gross<br>Margin(2) | Pre-Tax<br>Equity	in<br>(Loss)<br>Earnings(3) | Total<br>Assets | Investment<br>in	and<br>Advances	to<br>Affiliates | Property<br>Additions |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Year\tEnded\tDecember\t31,\t2001 |  |  |  |  |  |  |  |
| Contract\tGeneration | $2,417 | $255 | $854 | $54 | $11,995 | $660 | $941 |
| Competitive\tSupply | 1,973 | 184 | 484 | (9) | 8,846 | 46 | 1,334 |
| Large\tUtilities | 1,642 | 203 | 618 | 144 | 7,444 | 2,292 | 378 |
| Growth\tDistribution | 1,613 | 111 | 221 | (13) | 4,316 | 12 | 89 |
| Discontinued\tBusinesses | — | — | — | — | 3,869 | — | 428 |
| Corporate | — | 3 | — | — | 342 | 21 | 3 |
| Total | $7,645 | $756 | $2,177 | $176 | $36,812 | $3,031 | $3,173 |

|  | Revenues(1) | Depreciation<br>and<br>Amortization | Gross<br>Margin(2) | Pre-Tax<br>Equity	in<br>(Loss)<br>Earnings(3) | Total<br>Assets | Investment<br>in	and<br>Advances	to<br>Affiliates | Property<br>Additions |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Year\tEnded\tDecember\t31,\t2000\nContract\tGeneration | $1,708 | $161 | $747 | $49 | $10,030 | $517 | $1,206 |
| Competitive\tSupply | 1,837 | 163 | 588 | — | 7,561 | 27 | 630 |

| Large	Utilities | 1,385 | 191 | 437 | 426 | 7,807 | 2,485 | 76 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Growth\tDistribution | 1,276 | 84 | 131 | — | 3,886 | 23 | 147 |
| Discontinued\tBusinesses | — | — | — | — | 3,474 | — | 167 |
| Corporate | — | 1 | — | — | 280 | 30 | — |
| Total | $6,206 | $600 | $1,903 | $475 | $33,038 | $3,082 | $2,226 |

(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):

|  | 2002 | 2001 | 2000 | 2002 | 2001 | 2000 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| United\tStates | $2,090 | $2,088 | $2,078 | $6,133 | $6,320 | $5,754 |
| Non-U.S: |  |  |  |  |  |  |
| United\tKingdom | 1,046 | 1,090 | 1,110 | 452 | 547 | 535 |
| Brazil | 2,193 | 844 | 695 | 2,797 | 1,744 | 2,034 |
| Argentina | 218 | 456 | 481 | 567 | 1,725 | 1,551 |
| Chile | 363 | 446 | — | 946 | 1,023 | — |
| Venezuela | 634 | 806 | 494 | 2,436 | 2,369 | 2,218 |
| Dominican\tRepublic | 301 | 391 | 333 | 547 | 424 | 225 |
| El\tSalvador | 312 | 321 | 139 | 300 | 250 | 153 |
| Pakistan | 226 | 230 | 233 | 309 | 301 | 319 |
| Colombia | 125 | 124 | — | 473 | 481 | 41 |
| Hungary | 197 | 175 | 177 | 125 | 97 | 91 |
| Ukraine | 152 | 85 | — | 94 | 120 | — |
| Other\tNon-U.S.(1) | 775 | 589 | 466 | 3,667 | 2,711 | 1,218 |
| Total\tNon-U.S | 6,542 | 5,557 | 4,128 | 12,713 | 11,792 | 8,385 |
| Total | $8,632 | $7,645 | $6,206 | $18,846 | $18,112 | $14,139 |

(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):

|  | Carrying<br>Amount | Fair<br>Value | Carrying<br>Amount | Fair<br>Value |
| :--- | :--- | :--- | :--- | :--- |
| Assets: |  |  |  |  |
| Foreign\tcurrency\tforwards\tand\tswaps,\tnet | $17 | $17 | $14 | $14 |
| Energy\tderivatives,\tnet | 201 | 201 | 7 | 7 |
| Liabilities:\nNon-recourse\tdebt | 17,658 | 20,447 | 16,857 | 17,064 |
| Recourse\tdebt | 5,804 | 3,895 | 5,401 | 4,730 |
| Tecons | 978 | 284 | 978 | 626 |
| Interest\trate\tswaps | 557 | 557 | 166 | 166 |

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	$3,415	million	and $4,994	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	$103	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.

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.

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.

# 22.		SUBSEQUENT	EVENT

On	March	21,	2003,	AES	reached	an	agreement	to	sell	100	percent	of	its	ownership	interest	in	both	AES	Haripur	and	AES	Meghnaghat,	both	generation	businesses	in Bangladesh,	to	CDC	Globeleq	for	approximately	$127	million	in	cash,	plus	assumption	of	debt	and	subject	to	certain	closing	adjustments.	The	total	AES	book	value	in AES	Haripur	and	AES	Meghnaghat,	including	other	comprehensive	loss,	is	approximately	$190	million	as	of	February	28,	2003	which	will	result	in	an	impairment	loss being	recorded	in	the	first	quarter	of	2003.	AES	Haripur	and	AES	Meghnaghat	are	included	in	the	contract	generation	segment	as	of	December	31,	2002	and	will	be reclassified	as	assets	held	for	sale	and	discontinued	operations	in	first	quarter	of	2003.

On	March	25,	2003,	AES	announced	an	agreement	to	sell	an	approximately	32%	ownership	interest	in	AES	Oasis	Limited	("AES	Oasis").	AES	Oasis	is	a	newly	created company	that	will	own	two	electric	generation	development	projects	and	desalination	plants	in	Oman	and	Qatar	(AES	Barka	and	AES	Ras	Laffan,	respectively),	the	oil- fired	generating	facilities,	AES	LalPir	and	AES	PakGen	in	Pakistan,	as	well	as	future	power	projects	in	the	Middle	East.	AES	expects	this	sale	to	close	in	the	second	or third	quarter	of	2003.	Completion	of	the	transaction	is	subject	to	certain	conditions,	including	government	and	lender	approvals.	At	the	time	of	closing,	AES	will	receive cash	proceeds	of	approximately	$150	million.

# 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).

|  | Mar	31 | Jun	30 | Sep	30 | Dec	31 |
| :--- | :--- | :--- | :--- | :--- |
| Revenues | $2,228 | $2,080 | $2,110 | $2,214 |
| Gross\tmargin | 681 | 437 | 587 | 214 |
| Income\t(loss)\tfrom\tcontinuing\toperations | 178 | (101) | (214) | (2,453) |
| Discontinued\toperations | (19) | (141) | (100) | (313) |
| Cumulative\teffect\tof\tchange\tin\taccounting\tprinciple | (473) | 127 | — | — |
| Net\tloss | (314) | (115) | (314) | (2,766) |
| Basic\tloss\tper\tshare:\t(1,2) |  |  |  |  |
| Income\t(loss)\tfrom\tcontinuing\toperations | $0.33 | $(0.19) | $(0.40) | $(4.50) |
| Discontinued\toperations | (0.03) | (0.26) | (0.18) | (0.58) |
| Cumulative\teffect\tof\taccounting\tchange | (0.88) | 0.23 | — | — |
| Basic\tloss\tper\tshare | $(0.58) | $(0.22) | $(0.58) | $(5.08) |
| Diluted\tloss\tper\tshare:\t(1,2) |  |  |  |  |
| Income\t(loss)\tfrom\tcontinuing\toperations | $0.33 | $(0.19) | $(0.40) | $(4.50) |
| Discontinued\toperations | (0.03) | (0.26) | (0.18) | (0.58) |
| Cumulative\teffect\tof\taccounting\tchange | (0.88) | 0.23 | — | — |
| Diluted\tloss\tper\tshare | $(0.58) | $(0.22) | $(0.58) | $(5.08) |

|  | Mar	31 | Jun	30 | Sep	30 | Dec	31 |
| :--- | :--- | :--- | :--- | :--- |
| Revenues | $2,035 | $1,856 | $1,828 | $1,926 |
| Gross\tmargin | 605 | 455 | 478 | 639 |
| Income\tfrom\tcontinuing\toperations | 112 | 143 | 4 | 187 |
| Discontinued\toperations | (1) | (28) | (1) | (143) |
| Net\tincome | 111 | 115 | 3 | 44 |
| Basic\tearnings\tper\tshare: |  |  |  |  |
| Income\tfrom\tcontinuing\toperations | $0.21 | $0.27 | $0.01 | $0.35 |
| Discontinued\toperations | (0.00) | (0.05) | (0.00) | (0.27) |
| Basic\tearnings\tper\tshare | $0.21 | $0.22 | $0.01 | $0.08 |
| Diluted\tearnings\tper\tshare:\t(1) |  |  |  |  |
| Income\tfrom\tcontinuing\toperations | $0.21 | $0.27 | $0.01 | $0.35 |
| Discontinued\toperations | (0.00) | (0.06) | (0.00) | (0.27) |
| Diluted\tearnings\tper\tshare | $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	December	31,	2002.	Results	of	operations	for	periods	prior to	the	fourth	quarter	2002	for	components	that	were	either	disposed	of	or	held	for	sale	and	treated	as	discontinued	operations	in

the	fourth	quarter	2002	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.

# 								Item	9—Changes	in	and	Disagreements	with	Accountants	on	Accounting	and	Financial	Disclosure

There	were	no	changes	in	or	disagreements	on	any	matters	of	accounting	principles	or	financial	disclosure	between	us	and	our	independent	auditors.

# Part	III

# 								Item	10—Directors	and	Executive	Officers	of	the	Registrant

See	the	information	with	respect	to	the	ages	of	the	Registrant's	directors	in	the	table	and	the	information	contained	under	the	caption	"Election	of	Directors"	on	pages	5 through	7,	inclusive,	of	the	Proxy	Statement	for	the	Annual	Meeting	of	Stock	holders	of	the	Registrant	to	be	held	on	May	1,	2003,	which	information	is	incorporated herein	by	reference.	See	also	the	information	with	respect	to	executive	officers	of	the	Registrant	under	the	caption	entitled	"Executive	Officers	and	Significant Employees	of	the	Registrant"	in	Item	1	of	Part	1	hereof,	which	information	is	incorporated	herein	by	reference.

# 								Item	11—Executive	Compensation

See	the	information	contained	under	the	captions	"Compensation	of	Executive	Officers"	and	"Compensation	of	Directors"	of	the	Proxy	Statement	for	the	Annual Meeting	of	Stockholders	of	the	Registrant	to	be	held	on	May	1,	2003	which	is	incorporated	herein	by	reference.

# 								Item	12—Security	Ownership	of	Certain	Beneficial	Owners	and	Management

# (a)	Security	Ownership	of	Certain	Beneficial	Owners.

See	the	information	contained	under	the	caption	"Security	Ownership	of	Certain	Beneficial	Owners,	Directors,	and	Executive	Officers"	of	the	Proxy	Statement	for	the Annual	Meeting	of	Stockholders	of	the	Registrant	to	be	held	on	May	1,	2003,	which	information	is	incorporated	herein	by	reference.

# (b)	Security	Ownership	of	Directors	and	Executive	Officers.

# (c)	Changes	in	Control.

# None.

# (d)	Recent	Sales	of	Unregistered	Securities.

During	the	fourth	quarter	of	2002,	AES	issued	an	aggregate	of	13.6	million	shares	of	its	common	stock	in	exchange	for	$63.3	million	aggregate	principal	amount	of	its senior	notes.	The	shares	were	issued	without	registration	in	reliance	upon	Section	3(a)(9)	under	the	Securities	Act	of	1933.

# 								Item	13—Certain	Relationships	and	Related	Transactions

See	the	information	contained	under	the	caption	"Related	Party	Transactions"	of	the	Proxy	Statement	for	the	Annual	Meeting	of	Stockholders	of	the	Registrant	to	be held	on	May	1,	2003,	which	information	in	incorporated	herein	by	reference.

# 								Item	14—Disclosure	Controls	and	Procedures

Evaluation	of	Disclosure	Controls	and	Procedures.				Our	chief	executive	officer	and	our	chief	financial	officer,	after	evaluating	the	effectiveness	of	the	Company's "disclosure	controls	and	procedures"	(as

defined	in	the	Securities	Exchange	Act	of	1934	Rules	13a-14c)	and	15-d-14(c)	as	of	a	date	(the	"Evaluation	Date")	within	90	days	before	the	filing	date	of	this	annual report,	have	concluded	that	as	of	the	Evaluation	Date,	our	disclosure	controls	and	procedures	were	effective	to	ensure	that	material	information	relating	to	the	Registrant and	its	consolidated	subsidiaries	is	recorded,	processed,	summarized,	and	reported	in	a	timely	manner.

Changes	in	Internal	Controls.				There	were	no	signficant	changes	in	our	internal	controls	or,	to	our	knowledge,	in	other	factors	that	could	significantly	affect	such controls	subsequent	to	the	Evaluation	Date.

# Part	IV

# 								Item	15—Exhibits,	Financial	Statement	Schedules	and	Reports	on	Form	8-K

(a)	1.	Financial	Statements.				The	following	Consolidated	Financial	Statements	of	The	AES	Corporation	are	filed	under	"Item	8.	Financial	Statements	and Supplementary	Data."

Consolidated	Balance	Sheets	as	of	December	31,	2002	and	2001

# Consolidated	Statements	of	Operations	for	the	years	ended	December	31,	2002,	2001	and	2000

# Consolidated	Statements	of	Cash	Flows	for	the	years	ended	December	31,	2002,	2001	and	2000

Consolidated	Statements	of	Changes	in	Stockholders'	Equity	(Deficit)	for	the	years	ended	December	31,	2002,	2001,	and	2000

2.	Financial	Statement	Schedules.	See	Index	to	Financial	Statement	Schedules	of	the	Registrant	and	subsidiaries	at	page	S-1	hereof,	which	index	is	incorporated herein	by	reference.

The	Company	filed	the	following	reports	on	Form	8-K	during	the	quarter	ended	December	31,	2002.	Information	regarding	the	items	reported	on	is	as	follows:

(c)	Exhibits.

		4.4 Security	Agreement	dated	as	of	December	12,	2002	made	by	The	AES	Corporation	to	Wilmington	Trust	Company,	as corporate	trustee	and	Bruce	L.	Bisson,	as	individual	trustee	is	herein	incorporated	by	reference	to	Exhibit	4.3	of	the Form	8-K	filed	on	December	17,	2002.

21.1 Subsidiaries	of	The	AES	Corporation.

Independent	Auditors'	Consent,	Deloitte	&	Touche	LLP.

99.3 Second	Amended	and	Restated	Pledge	Agreement	dated	as	of	December	12,	2002	between	AES	EDC	Funding	II, L.L.C.	and	Citicorp	USA,	Inc.,	as	Collateral	Agent	is	herein	incorporated	by	reference	to	Exhibit	99.3	of	the	Form	8-K filed	on	December	17,	2002.

# (d)	Schedules.

								Schedule	I	–	Condensed	Financial	Information	of	Registrant

# 								Schedule	II	–	Valuation	and	Qualifying	Accounts

# SIGNATURES

								Pursuant	to	the	requirements	of	Section	13	or	15	(d)	of	the	Securities	Exchange	Act	of	1934,	as	amended,	the	Company	has	duly	caused	this	report	to	be	signed	on its	behalf	by	the	undersigned,	thereunto	duly	authorized.

(Company)

/s/		PAUL	T.	HANRAHAN

Name:	Paul	T.	Hanrahan

President,	Chief	Executive	Officer

Pursuant	to	the	requirements	of	the	Securities	Exchange	Act	of	1934,	as	amended,	this	report	has	been	signed	below	by	the	following	persons	on	behalf	of	the	Company and	in	the	capacities	and	on	the	dates	indicated.

| * | President,	Chief	Executive	Officer	(Principal | March	25,	2003 |
| :--- | :--- | :--- |
|  | Executive\tOfficer)\tand\tDirector |  |
| Paul\tT.\tHanrahan |  |  |
| * |  |  |
| Dennis\tW.\tBakke | Director | March\t25,\t2003 |
| * |  |  |
| Richard\tDarman | Director | March\t25,\t2003 |
| * |  |  |
| Alice\tF.\tEmerson | Director | March\t25,\t2003 |
| * |  |  |
| Robert\tF.\tHemphill,\tJr. | Director | March\t25,\t2003 |
| * |  |  |
| Frank\tJungers | Director | March\t25,\t2003 |

# CERTIFICATIONS

I,	Paul	T.	Hanrahan,	certify	that:

1. I	have	reviewed	this	annual	report	on	Form	10-K	of	The	AES	Corporation;

2. Based	on	my	knowledge,	this	annual	report	does	not	contain	any	untrue	statement	of	a	material	fact	or	omit	to	state	a	material	fact	necessary	to	make	the statements	made,	in	light	of	the	circumstances	under	which	such	statements	were	made,	not	misleading	with	respect	to	the	period	covered	by	this	annual	report;

3. Based	on	my	knowledge,	the	financial	statements,	and	other	financial	information	included	in	this	annual	report,	fairly	present	in	all	material	respects	the financial	condition,	results	of	operations	and	cash	flows	of	the	registrant	as	of,	and	for,	the	periods	presented	in	the	annual	report;

4. The	registrant's	other	certifying	officer	and	I	are	responsible	for	establishing	and	maintaining	disclosure	controls	and	procedures	(as	defined	in	Exchange	Act Rules	13a-14	and	15d-14)	for	the	registrant	and	we	have:

a. designed	such	disclosure	controls	and	procedures	to	ensure	that	material	information	relating	to	the	registrant,	including	its	consolidated	subsidiaries,	is made	known	to	us	by	others	within	those	entities,	particularly	during	the	period	in	which	this	annual	report	is	being	prepared;

b. evaluated	the	effectiveness	of	the	registrant's	disclosure	controls	and	procedures	as	of	a	date	within	90	days	prior	to	the	filing	date	of	this	annual	report (the	"Evaluation	Date");	and

c. presented	in	this	annual	report	our	conclusions	about	the	effectiveness	of	the	disclosure	controls	and	procedures	based	on	our	evaluation	as	of	the Evaluation	Date;

5. The	registrant's	other	certifying	officer	and	I	have	disclosed,	based	on	our	most	recent	evaluation,	to	the	registrant's	auditors	and	the	audit	committee	of registrant's	board	of	directors	(or	persons	performing	the	equivalent	function):

a. all	significant	deficiencies	in	the	design	or	operation	of	internal	controls	which	could	adversely	affect	the	registrant's	ability	to	record,	process,	summarize and	report	financial	data	and	have	identified	for	the	registrant's	auditors	any	material	weaknesses	in	internal	controls;	and

b. any	fraud,	whether	or	not	material,	that	involves	management	or	other	employees	who	have	a	significant	role	in	the	registrant's	internal	controls;	and

6. The	registrant's	other	certifying	officer	and	I	have	indicated	in	this	annual	report	whether	there	were	significant	changes	in	internal	audit	controls	or	in	other factors	that	could	significantly	affect	internal	controls	subsequent	to	the	date	of	our	most	recent	evaluation,	including	any	corrective	actions	with	regard	to significant	deficiencies	and	material	weaknesses.

Name:	Paul	T.	Hanrahan Chief	Executive	Officer

# I,	Barry	J.	Sharp,	certify	that:

Name:	Barry	J.	Sharp

Chief	Financial	Officer

# THE	AES	CORPORATION	AND	SUBSIDIARIES

# INDEX	TO	CONSOLIDATED	FINANCIAL	STATEMENT	SCHEDULES

Schedules	other	than	those	listed	above	are	omitted	as	the	information	is	either	not	applicable,	not	required,	or	has	been	furnished	in	the	financial	statements	or	notes thereto	included	in	Item	8	hereof.

# STATEMENTS	OF	UNCONSOLIDATED	BALANCE	SHEETS	(IN	MILLIONS)

| ASSETS | 2002 | 2001 |
| :--- | :--- | :--- |
| Current\tAssets: |  |  |
| Cash\tand\tcash\tequivalents | $188 | $45 |
| Accounts\tand\tnotes\treceivable\tfrom\tsubsidiaries | 1,508 | 3,093 |
| Deferred\tincome\ttaxes | 42 | 12 |

| Prepaid	expenses	and	other	current	assets | 30 | 22 |
| :--- | :--- | :--- |
| Total\tcurrent\tassets | 1,768 | 3,172 |
| Investment\tin\tand\tadvances\tto\tsubsidiaries\tand\taffiliates | 4,586 | 8,697 |
| Office\tEquipment: |  |  |
| Cost | 10 | 9 |
| Accumulated\tdepreciation | (3) | (2) |
| Office\tequipment,\tnet | 7 | 7 |
| Other\tAssets: |  |  |
| Deferred\tfinancing\tcosts\t(less\taccumulated\tamortization:\t2002,\t$45;\t2001,\t$39) | 122 | 105 |
| Deferred\tincome\ttaxes | 128 | 60 |
| Total\tother\tassets | 250 | 165 |
| Total | $6,611 | $12,041 |
| LIABILITIES\tAND\tSTOCKHOLDERS'\tEQUITY\t(DEFICIT) |  |  |
| Current\tLiabilities: |  |  |
| Accounts\tpayable | $1 | $— |
| Accrued\tand\tother\tliabilities | 169 | 123 |
| Term\tbank\tloan\t—\tcurrent\tportion | — | 188 |
| Senior\tnotes\tpayable\t—\tcurrent\tportion | — | 300 |
| Redeemable\tor\tremarketable\tsecurities | 26 | — |
| Total\tcurrent\tliabilities | 196 | 611 |
| Long-term\tLiabilities: |  |  |
| Revolving\tBank\tLoan | 228 | 70 |
| Term\tloan | 1,187 | 425 |
| Senior\tnotes\tpayable | 3,211 | 2,996 |
| Senior\tsubordinated\tnotes\tand\tdebentures\tpayable | 1,002 | 1,072 |
| Junior\tsubordinated\tnotes\tand\tdebentures\tpayable | 1,128 | 1,128 |
| Redeemable\tor\tremarketable\tsecurities | — | 200 |
| Total\tlong-term\tliabilities | 6,756 | 5,891 |
| Stockholders'\tEquity\t(Deficit): |  |  |
| Common\tstock | 6 | 5 |
| Additional\tpaid-in\tcapital | 5,312 | 5,225 |
| (Accumulated\tloss)\tRetained\tearnings | (700) | 2,809 |
| Accumulated\tother\tcomprehensive\tloss | (4,959) | (2,500) |
| Total\tstockholders'\t(deficit)\tequity | (341) | 5,539 |
| Total | $6,611 | $12,041 |

# STATEMENTS	OF	UNCONSOLIDATED	OPERATIONS	(IN	MILLIONS)

|  | 2002 | 2001 | 2000 |
| :--- | :--- | :--- | :--- |
| Revenues\tfrom\tsubsidiaries\tand\taffiliates | $41 | $164 | $116 |
| Equity\tin\t(losses)\tearnings\tof\tsubsidiaries\tand\taffiliates | (3,280) | 340 | 884 |
| Interest\tincome | 84 | 127 | 122 |
| Selling,\tgeneral\tand\tadministrative\texpenses | (24) | (34) | (21) |
| Interest\texpense | (428) | (367) | (262) |
| (Loss)\tincome\tbefore\tincome\ttaxes | (3,607) | 230 | 839 |
| Income\ttax\t(benefit)\texpense | (98) | (43) | 44 |
| Net\t(loss)\tincome | $(3,509) | $273 | $795 |

See	notes	to	Schedule	I.

# STATEMENTS	OF	UNCONSOLIDATED	CASH	FLOWS	(IN	MILLIONS)

|  | 2002 | 2001 | 2000 |
| :--- | :--- | :--- | :--- |
| Net\tcash\tprovided\tby\t(used\tin)\toperating\tactivities | $1,011 | $1,038 | $(37) |
| Investing\tActivities: |  |  |  |
| Acquisitions | — | (1,448) | (2,584) |
| Project\tdevelopment\tcosts | — | — | (7) |
| Investment\tin\tand\tadvances\tto\tsubsidiaries | (1,081) | (1,283) | (127) |
| Escrow\tdeposits\tand\tother | — | — | 3 |
| (Disposals\tof)\tadditions\tto\tproperty,\tplant\tand\tequipment | (1) | (3) | 2 |
| Net\tcash\tused\tin\tinvesting\tactivities | (1,082) | (2,734) | (2,713) |
| Financing\tActivities: |  |  |  |
| Repayments\tunder\tthe\told\trevolver,\tnet | (70) | (70) | (195) |
| Borrowings\tunder\tthe\tnew\trevolver,\tnet | 228 | 0 | 0 |
| Issuance\tof\tnotes\tpayable\tand\tother\tcoupon\tbearing\tsecurities,\tnet | 95 | 1,754 | 1,610 |
| Proceeds\tfrom\tissuance\tof\tcommon\tstock,\tnet | — | 14 | 1,449 |
| Payments\tfor\tdeferred\tfinancing\tcosts | (39) | (30) | (50) |
| Net\tcash\tprovided\tby\tfinancing\tactivities | 214 | 1,668 | 2,814 |
| (Decrease)\tincrease\tin\tcash\tand\tcash\tequivalents | 143 | (28) | 64 |
| Cash\tand\tcash\tequivalents,\tbeginning | 45 | 73 | 9 |
| Cash\tand\tcash\tequivalents,\tending | $188 | $45 | $73 |
| Schedule\tof\tnon-cash\tinvesting\tand\tfinancing\tactivities: |  |  |  |
| Common\tstock\tissued\tfor\tdebt\tretirement | $73 | $— | $— |

# SCHEDULE	I

# NOTES	TO	SCHEDULE	I

# 1.				Application	of	Significant	Accounting	Principles

Accounting	for	Subsidiaries	and	Affiliates—The	AES	Corporation	(the	"Company")	has	accounted	for	the	earnings	of	its	subsidiaries	on	the	equity	method	in	the unconsolidated	condensed	financial	information.

Revenues—Construction	management	fees	earned	by	the	parent	from	its	consolidated	subsidiaries	are	eliminated.

Income	Taxes—The	unconsolidated	income	tax	expense	or	benefit	computed	for	the	Company	in	accordance	with	Statement	of	Financial	Accounting	Standards No.	109,	Accounting	for	Income	Taxes,	reflects	the	tax	assets	and	liabilities	of	the	Company	on	a	stand-alone	basis	and	the	effect	of	filing	a	consolidated	U.S.	income tax	return	with	certain	other	affiliated	companies.

Accounts	and	Notes	Receivable	from	Subsidiaries—Such	amounts	have	been	shown	in	current	or	long-term	assets	based	on	terms	in	agreements	with	subsidiaries,	but payment	is	dependent	upon	meeting	conditions	precedent	in	the	subsidiary	loan	agreements.

Reclassifications—Certain	reclassifications	have	been	made	to	conform	with	the	2002	presentation.

| Senior	notes | 10.00% | 2005 | — | 258 | — |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Remarketable\tor\tRedeemable\tSecurities | 7.38% | 2013 | 2003 | 26 | 200 |
| Senior\tsubordinated\tnotes | 10.25% | 2006 | 2001 | 231 | 250 |
| Senior\tsubordinated\tnotes | 8.38% | 2007 | 2002 | 316 | 325 |
| Senior\tsubordinated\tnotes | 8.50% | 2007 | 2002 | 349 | 375 |
| Senior\tsubordinated\tdebentures | 8.88% | 2027 | 2004 | 125 | 125 |
| Convertible\tjunior\tsubordinated\tdebentures | 4.50% | 2005 | 2001 | 150 | 150 |
| Convertible\tjunior\tsubordinated\tdebentures | 6.00% | 2008 | 2003 | 460 | 460 |
| Convertible\tjunior\tsubordinated\tdebentures | 6.75% | 2029 | 2002 | 518 | 518 |
| Unamortized\tdiscounts |  |  |  | (19) | (3) |
| SUBTOTAL |  |  |  | 6,782 | 6,379 |
| Less:\tCurrent\tmaturities |  |  |  | (26) | (488) |
| Total |  |  |  | $6,756 | $5,891 |

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

Future	maturities	of	debt—Scheduled	maturities	of	total	debt	at	December	31,	2002	are	(in	millions):

| 2003 | $26 |
| :--- | :--- |
| 2004 | 872 |
| 2005 | 938 |
| 2006 | 231 |
| 2007 | 664 |
| Thereafter | 4,051 |
| TOTAL | $6,782 |

# 3.				Dividends	from	Subsidiaries	and	Affiliates

Cash	dividends	received	from	consolidated	subsidiaries	and	from	affiliates	accounted	for	by	the	equity	method	were	as	follows	(in	millions):

|  | 2002 | 2001 | 2000 |
| :--- | :--- | :--- | :--- |
| Subsidiaries | $771 | $1,038 | $428 |
| Affiliates | 44 | 21 | 100 |

# 4.				Guarantees	and	Letters	of	Credit

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.

THE	AES	CORPORATION SCHEDULE	II VALUATION	AND	QUALIFYING	ACCOUNTS	(IN	MILLIONS)

|  | Balance	at<br>Beginning	of<br>Period | Charged	to<br>Costs	and<br>Expenses | Acquisitions<br>of	Business | Sale	of<br>Business | Translation<br>Adjustment |  | Amounts<br>Written<br>Off |  | Balance	at<br>End	of<br>Period |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Allowance\tfor\taccounts |  |  |  |  |  |  |  |  |  |
| receivables: |  |  |  |  |  |  |  |  |  |
| Year\tended\tDecember\t31,\t2000 | $99 | $72 | $57 | $(10) $ |  | (1) $ |  | (21) $ | 196 |

| Year	ended	December	31,	2001 | 196 | 123 | 16 | — | (5) | (91) | 239 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Year\tended\tDecember\t31,\t2002 | 239 | 182 | 161 | — | (112) | (46) | 424 |

# QuickLinks

AES	CORPORATION	FISCAL	YEAR	2002	FORM	10-K	TABLE	OF	CONTENTS Part	I

# Item	1—Business

Item	2—Properties Item	3—Legal	Proceedings Item	4—Submission	of	Matters	to	a	Vote	of	Security	Holders

Item	5—Market	for	Registrant's	Common	Equity	and	Related	Stockholder	Matters Item	6—Selected	Financial	Data Item	7—Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations

THE	AES	CORPORATION	CONSOLIDATED	BALANCE	SHEETS	DECEMBER	31,	2002	AND	2001 THE	AES	CORPORATION	CONSOLIDATED	STATEMENTS	OF	OPERATIONS	YEARS	ENDED	DECEMBER	31,	2002,	2001	AND	2000 THE	AES	CORPORATION	CONSOLIDATED	STATEMENTS	OF	CASH	FLOWS	YEARS	ENDED	DECEMBER	31,	2002,	2001	AND	2000 THE	AES	CORPORATION	CONSOLIDATED	STATEMENTS	OF	CHANGES	IN	STOCKHOLDERS'	EQUITY	(DEFICIT)	YEARS	ENDED	DECEMBER	31, 2002,	2001	AND	2000

THE	AES	CORPORATION	CONSOLIDATED	STATEMENTS	OF	CHANGES	IN	STOCKHOLDERS'	EQUITY	(DEFICIT)	YEARS	ENDED	DECEMBER	31, 2002,	2001	AND	2000

THE	AES	CORPORATION	NOTES	TO	CONSOLIDATED	FINANCIAL	STATEMENTS	DECEMBER	31,	2002,	2001	AND	2000 SELECTED	QUARTERLY	FINANCIAL	DATA	(UNAUDITED)

Item	12—Security	Ownership	of	Certain	Beneficial	Owners	and	Management Item	13—Certain	Relationships	and	Related	Transactions

THE	AES	CORPORATION	AND	SUBSIDIARIES	INDEX	TO	CONSOLIDATED	FINANCIAL	STATEMENT	SCHEDULES

THE	AES	CORPORATION	SCHEDULE	I	CONDENSED	FINANCIAL	INFORMATION	OF	REGISTRANT	STATEMENTS	OF	UNCONSOLIDATED	BALANCE

SHEETS	(IN	MILLIONS)

THE	AES	CORPORATION	SCHEDULE	I	CONDENSED	FINANCIAL	INFORMATION	OF	REGISTRANT	STATEMENTS	OF	UNCONSOLIDATED

OPERATIONS	(IN	MILLIONS)

THE	AES	CORPORATION	SCHEDULE	I	CONDENSED	FINANCIAL	INFORMATION	OF	REGISTRANT	STATEMENTS	OF	UNCONSOLIDATED	CASH

FLOWS	(IN	MILLIONS)

THE	AES	CORPORATION	SCHEDULE	I	NOTES	TO	SCHEDULE	I



Question: what was the average rental expense in millions for 2000 through 2002?
Calculation:    rent_2002 = 54
 rent_2001 = 58
 rent_2000 = 54
 total_rent = rent_2002 + rent_2001 + rent_2000
 average_rent = total_rent / 3
 answer = average_rent
Answer: 55.3