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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,	2001

COMMISSION	FILE	NUMBER	0-19281

# The	AES	Corporation

(Exact	name	of	registrant	as	specified	in	its	charter)

Delaware

(State	of	other	jurisdiction	of incorporation	or	organization)

1001	North	19th	Street 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

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

# DOCUMENTS	INCORPORATED	BY	REFERENCE

								The	Proxy	Statement	for	the	Annual	Meeting	of	Stockholders	of	the	Registrant	to	be	held	on	April	25,	2002	is	hereby	incorporated	by	reference.	Certain information	therein	is	incorporated	by	reference	into	Part	III	hereof.

# PART	I

# ITEM	1—BUSINESS

# (a)	General	Development	of	Business.

# Overview

								The	AES	Corporation	(including	all	its	subsidiaries	and	affiliates,	and	collectively	referred	to	herein	as	"AES"	or	the	"Company"	or	"we")	is	a	global	power company	committed	to	serving	the	world's	needs	for	electricity	in	a	socially	responsible	way.	AES's	total	megawatts	("MW")	in	the	179	power	plants	in	operation	or under	construction	is	approximately	62,852MW	and	net	equity	ownership	(total	MW	adjusted	for	the	Company's	ownership	percentage)	represents	approximately 50,764MW.	AES	participates	primarily	in	four	lines	of	business:	contract	generation,	competitive	supply,	large	utilities	and	growth	distribution.

								Contract	Generation.				AES's	contract	generation	line	of	business	is	made	up	of	multiple	power	generation	facilities	located	around	the	world	that	have contractually	limited	their	exposure	to	commodity	price	risks,	primarily	electricity	prices.	These	facilities	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	counter	party	directly	assumes	the	risks	associated	with	providing	the necessary	fuel	and	marketing	the	resulting	power	output	generated.	AES	currently	has	60	contract	generation	facilities	in	operation	totaling	21,590	Gross	MW	and	seven facilities	under	construction	for	an	additional	3,388MW	located	in	six	different	countries.	The	operating	facilities	have	an	average	of	13	years	remaining	on	their	power purchase	agreements	and	are	located	in	19	different	countries,	including	27%	(5,843MW)	in	North	America,	26%	(5,704MW)	in	South	America,	25%	(5,349MW)	in Asia,	16%	(3,413MW)	in	Europe/Africa,	and	6%	(1,281MW)	in	the	Caribbean.	Customer	types	include	private	utilities,	governments	and	commercial	electric	trading companies.	AES's	contract	generation	business	represented	approximately	30%	of	pre-tax	segment	income	and	27%	of	total	revenues	in	2001	compared	to	31%	and 23%,	respectively	in	2000.

								Competitive	Supply.				AES's	competitive	supply	line	of	business	is	oriented	around	the	customer	perspective	and	consists	of	generating	facilities	and	retail	supply businesses	that	sell	electricity	directly	to	wholesale	and	retail	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	can	be,	and	from time	to	time	have	been,	unpredictable	and	volatile.	The	results	of	operations	of	AES's	competitive	supply	business	is	also	more	sensitive	to	the	impact	of	market fluctuations	in	the	price	of	electricity,	natural	gas,	coal	and	other	raw	materials.	This	line	of	business	includes	generating	facilities	located	around	the	world	and	the	New Energy	group	of	companies,	which	market	electricity	to	commercial	and	industrial	customers	in	those	states	in	the	U.S.	that	have	introduced	a	competitive	market	for	the sale	of	electricity	to	end	users	and	in	the	U.K.	The	generating	facilities	included	in	this	line	of	business	represent	19,713	Gross	MW	in	8	different	countries,	including 42%	(8,414MW)	in	Asia,	28%	(5,476MW)	in	Europe/Africa,	14%	(2,730MW)	in	South	America,	9%	(1,721MW)	in	North	America	and	7%	(1,372MW)	in	the Caribbean.	In	addition,

AES	is	also	currently	in	the	process	of	adding	approximately	4,121MW	to	its	competitive	operating	supply	portfolio.	This	line	of	business	represented	approximately	9% of	pre-tax	segment	income	and	29%	of	total	revenues	in	2001	compared	to	21%	and	32%,	respectively	in	2000.

								Large	Utilities.				AES's	large	utility	business	is	comprised	of	five	integrated	utilities	located	in	the	U.S.	(IPALCO	and	CILCORP),	Brazil	(Eletropaulo Metropolitana	("Eletropaulo")	and	Companhia	Energetica	de	Minas	Gerias	("CEMIG"))	and	Venezuela	(C.A.	La	Electricidad	de	Caracas	("EDC")).	AES's	equity interest	in	each	of	these	utilities	is	over	70%	other	than	CEMIG	in	which	AES's	equity	interest	is	approximately	21%.	As	of	December	31,	2001,	AES	also	owned	a minority	interest	in	a	sixth	utility,	Light-Servicos	de	Electricidade	S.A.	("Light"),	which	was	exchanged	in	February	2002	for	an	additional	ownership	interest	in Eletropaulo.	All	of	these	utilities	are	of	significant	size,	and	all	but	CILCORP	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	tariff	or	concession	agreements	and	to	a	lesser	extent	from	contractual	agreements	of	varying	lengths	and	provisions.	AES's	large	utilities,	including	IPALCO (3,036MW),	CILCORP	(1,157MW),	Light	(793MW),	EDC	(2,265MW)	and	CEMIG	(5,668MW),	aggregate	12,919	Gross	MW	of	generation	capacity	and	serve	over thirteen	million	customers	with	annual	sales	of	nearly	120,000	gigawatt	hours.	AES's	large	utility	business	represented	approximately	51%	of	pre-tax	segment	income and	26%	of	total	revenues	in	2001	compared	to	46%	and	28%,	respectively	in	2000.

								Growth	Distribution.				AES's	growth	distribution	line	of	business	includes	distribution	facilities	that	offer	significant	potential	for	growth	because	they	are	located in	developing	countries	or	regions	where	the	demand	for	electricity	is	expected	to	grow	at	a	higher	rate	than	in	more	developed	areas.	However,	these	businesses	face particular	challenges	relating	to	operational	difficulties	such	as	outdated	equipment,	significant	non-technical	or	theft	related	losses,	cultural	problems	associated	with safety	and	non-payment,	emerging	economies	as	well	as	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.	AES's	growth	distribution	business	represented	approximately	10%	of	pre-tax	segment	income	and 18%	of	total	revenues	in	2001	compared	to	2%	and	17%,	respectively	in	2000.	The	facilities	currently	in	this	line	of	business	represent	800	Gross	MW	of	integrated generation	and	serve	approximately	5.4	million	customers	with	sales	exceeding	30,844	gigawatt	hours	in	Argentina,	Brazil,	Cameroon,	Dominican	Republic,	El Salvador,	Georgia,	Kazakhstan	and	Ukraine.

								Reorganization.				The	Company	has	recently	completed	a	reorganization	to	enhance	operating	performance,	including	further	reductions	of	operating	costs	and revenue	enhancements.	This	reorganization	has	included	the	creation	of	four	Chief	Operating	Officer	positions	who,	together	with	the	CEO,	constitute	the	Executive Office.	Each	COO	is	directly	responsible	for	managing	a	portion	of	the	Company's	geographically	dispersed	businesses	as	well	as	coordinating	Company	wide	efforts associated	with	one	of	the	Company's	business	segments.	In	addition,	two	special	offices,	the	Cost	Cutting	Office	and	the	Turnaround	Office,	have	been	created	to	bring improved	focus	and	coordination	to	the	management	of	expenses	across	the	Company	and	to	improve	or	dispose	of	businesses	that	AES	believes	to	be	under-performing businesses	from	a	return	on	capital	perspective,	respectively.	Each	of	these	offices	reports	to	the	Executive	Office.	Several	additional	efforts	are	being	undertaken	to respond	to	the	current	condition	of	the	electricity	and	capital	markets	and	their	impacts	on	AES	businesses,	however,	there	can	be	no	assurance	that	the	initiatives described	above	or	any	others	that	are	being,	or	may	be,	taken	will	have	the	anticipated	positive	effect.

								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.aesc.com.	The	Company	currently	employs	approximately 38,000	people	worldwide.

# 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	short-term	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.

•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	many	of	its	distribution	businesses;	changes	in	the historical	or	expected	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	redress	from regulatory	authorities.

•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,	in	an	economical manner,	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	arising	from	changes	in	the	underlying	foreign	currency	exchange	rates,	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,	state	or	federal	regulatory	provisions; 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	New	Energy	Trading	Arrangements	("NETA")	in	the	United	Kingdom	(see	also	the	description	of	the	AES	Drax	facility	under Regulatory	Outlook	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	Securities	and	Exchange	Commission, the	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	that	the	Company	is	conducting	or	is seeking	to	conduct	business.

•The	prolonged	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	or	(ii)	capital	improvements	to	existing	facilities.

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

•The	effects	of	a	strengthening	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),	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.

# (b)	Financial	Information	About	Industry	Segments	And	Geographic	Areas

								The	Company	operates	in	four	business	segments:	contract	generation,	competitive	supply,	large	utilities	and	growth	distribution.	See	Note	16	to	the	Consolidated Financial	Statements	included	in	Item	8	herein	for	financial	information	about	those	segments.

(c)	Narrative	Description	of	Business.

								AES	is	a	global	power	company	committed	to	serving	the	world's	needs	for	electricity	in	a	socially	responsible	way.	AES	is	comprised	of	four	lines	of	business:

contract	generation,	competitive	supply,	large	utilities,	and	growth	distribution.	The	contract	generation	segment	includes	generating	plants	that	have	entered	into contracts	with	initial	durations	of	5	years	or	greater	accounting	for	at	least	75%	of	their	estimated	revenue	stream.	The	competitive	supply	segment	includes	both wholesale	(through	generation	facilities	with	shorter-term	market-priced	contracts)	and	retail	sales	of	electricity	directly	to	end	users	such	as	commercial,	industrial, governmental	and	residential	customers.	The	large	utility	segment	is	characterized	by	distribution	businesses	of	significant	size	that	often	combine	generation,

transmission	and	distribution	capabilities	and	are	subject	to	extensive	local,	state	and	national	regulation.	The	growth	distribution	segment	includes	distribution	facilities facing	particular	challenges	relating	to	operational	difficulties	that	are	located	in	emerging	markets	and	offer	significant	potential	for	improved	financial	and	operational performance.

								Through	each	of	its	four	business	lines,	the	Company	attempts	to	participate	in	both	regulated	and	competitive	power	markets	through	either	greenfield development	or	by	acquiring	and	operating	existing	facilities	or	companies.	Elements	of	the	Company's	strategy	include:

•Supplying	energy	to	customers	at	the	lowest	cost	possible,	taking	into	account	factors	such	as	reliability	and	environmental	performance;

•Constructing,	acquiring	and	operating	projects	of	a	relatively	large	size	in	geographically	dispersed	markets;

•To	the	extent	available,	maximizing	the	amount	of	non-recourse	financing;

•When	available,	entering	into	longer-term	power	sales	contracts	or	other	arrangements	with	electric	utilities	or	other	customers	with	significant	credit strength;

•Where	possible,	participating	in	distribution	markets	that	grant	concessions	with	long-term	pricing	arrangements;	and

•When	available,	entering	into	hedging,	indexing	or	other	arrangements	to	protect	against	fluctuations	in	currency,	fuel	costs	and	electricity	prices.

								The	Company	also	strives	for	operating	excellence	as	a	key	element	of	its	strategy,	which	it	believes	it	accomplishes	by	minimizing	organizational	layers	and maximizing	company-wide	participation	in	decision	making.	AES	has	attempted	to	create	an	operating	environment	that	results	in	safe,	clean	and	reliable	electricity generation,	distribution	and	supply.	Because	of	this	emphasis,	the	Company	prefers	to	operate	all	facilities	and	businesses	which	it	develops	or	acquires;	however,	there can	be	no	assurance	that	the	Company	will	have	operating	control	of	all	of	its	facilities.

								The	Company	attempts	to	finance	each	domestic	and	foreign	project	primarily	under	loan	agreements	and	related	documents	which,	except	as	noted	below,	require the	loans	to	be	repaid	solely	from	the	project's	revenues	and	provide	that	the	repayment	of	the	loans	(and	interest	thereon)	is	secured	solely	by	the	capital	stock,	physical assets,	contracts	and	cash	flow	of	that	project	subsidiary	or	affiliate.	This	type	of	financing	is	usually	referred	to	as	non-recourse	debt	or	"project	financing."	The	lenders under	these	project	financing	structures	generally	do	not	have	recourse	to	AES,	the	parent	company,	or	its	other	projects	for	repayment,	unless	such	entity	explicitly agrees	to	undertake	liability.	AES	has	explicitly	agreed	to	undertake	certain	limited	obligations	and	contingent	liabilities,	most	of	which	by	their	terms	will	only	be effective	or	will	be	terminated	upon	the	occurrence	of	future	events.	These	obligations	and	liabilities	take	the	form	of	guarantees,	indemnities,	letter	of	credit reimbursement	agreements,	and	agreements	to	pay,	in	certain	circumstances,	to	project	lenders	or	other	parties.	To	the	extent	AES	becomes	liable	under	guarantees	and letter	of	credit	reimbursement	agreements,	distributions	received	by	AES	from	other	projects	are	subject	to	the	possibility	of	being	utilized	by	AES	to	satisfy	these obligations.	To	the	extent	of	these	obligations,	the	lenders	to	a	project	effectively	have	recourse	to	AES	and	to	the	distributions	to	AES	from	other	projects.	The aggregate	contractual	liability	of	AES	is,	in	each	case,	usually	a	small	portion	of	the	aggregate	project	debt,	and	thus	the	project	financing	structures	are	generally described	herein	as	being	"substantially	non-recourse"	to	AES	and	its	other	projects.

								AES	has	also	hedged	a	substantial	portion	of	its	projects	against	the	risk	of	fluctuations	in	interest	rates.	In	each	project	with	fixed	capacity	payments,	AES	has attempted	to	hedge	all	or	a	significant	portion	of	its	risk	of	interest	rate	fluctuations	by	arranging	for	fixed-rate	financing	or	variable-rate	financing	with	interest	rate swaps	or	other	hedging	mechanisms.

								Contract	Generation.				AES's	contract	generation	line	of	business	is	made	up	of	multiple	power	generation	facilities	located	around	the	world	that	have contractually	limited	their	exposure	to	commodity	price	risks,	primarily	electricity	prices.	These	facilities	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,	fuel oil	or	other	similar	fuel)	supply	requirements,	thereby	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	a	minimum	duration	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	counter-party	assumes	the	risks	associated	with	providing	the	necessary	fuel	and marketing	the	resulting	power	output	generated.	AES's	contract	generation	business	represented	approximately	30%	of	pre-tax	segment	income	and	27%	of	total revenues	in	2001	compared	to	31%	and	23%,	respectively	in	2000.

								AES	currently	has	60	contract	generation	facilities	in	operation	totaling	21,590	Gross	MW.	The	operating	facilities	have	an	average	of	13	years	remaining	on	their sales	contracts	and	are	located	in	19	different	countries,	including	27%	(5,843MW)	in	North	America,	26%	(5,704MW)	in	South	America,	25%	(5,349MW)	in	Asia, 16%	(3,413MW)	in	Europe/Africa,	and	6%	(1,281MW)	in	the	Caribbean.	Customer	types	include	private	utilities,	governments	and	commercial	electric	trading companies.	AES	is	also	currently	in	the	process	of	adding	approximately	3,388MW	in	six	different	countries	to	its	contract	generation	operating	portfolio	through	its greenfield	development.	These	include	a	832MW	natural	gas-fired	plant	in	the	United	States,	a	454MW	coal-fired	plant	in	Puerto	Rico,	a	310MW	natural	gas-fired	plant in	the	Dominican	Republic,	a	450MW	natural	gas-fired	plant	in	Bangladesh,	a	427MW	natural	gas-fired	plant	in	Oman,	a	750MW	natural	gas-fired	plant	in	Qatar	and	a 165MW	natural	gas-fired	plant	in	Sri	Lanka.

								Typically,	AES	enters	into	long-term	power	purchase	agreements	or	tolling	agreements	with	electric	utilities,	power	marketing	firms	and	state-owned	power companies.	Although	the	specific	terms	of	individual	sales	contracts	may	vary	significantly,	power	purchase	agreements	or	other	similar	arrangements	for	the	sale	of electricity	(including	tolling	agreements	or	financially	settled	hedging	agreements)	generally	contain	pricing	provisions	that	reflect	the	two	principal	products,	capacity and	energy,	produced	by	electric	generating	facilities.	Energy	refers	to	the	sale	of	the	actual	electricity	produced	by	the	generation	facility	and	capacity	refers	to	the amount	of	generation	reserved	for	a	particular	customer,	irrespective	of	the	amount	of	energy	actually	purchased.

								To	the	extent	possible,	the	Company	attempts	to	structure	its	power	generation	facilities'	fuel	supply	contracts	so	that	fuel	costs	are	indexed	in	a	manner	similar	to the	energy	payments	a	project	receives	under	its	power	purchase	agreement.	In	this	way,	project	revenues	are	partially	or	completely	hedged	against	fluctuations	in	fuel costs.	However,	there	can	be	no	guarantee	that	such	arrangements	will	be	available	or,	if	available,	will	be	an	effective	hedge.

								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	a	given power	generation	facility's	revenues.	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	the	most	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	maintains	flexibility	with	its	customers.	In	many instances,	AES	is	able	to	avoid	abrogation	by	creatively	restructuring	contracts	without	disadvantaging	itself.	Where	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	in	part	mitigating	a	portion	of	the	risks	imposed	by	operating	in	less	developed	countries.

								Because	the	stability	of	revenues	for	each	power	generation	facility	is	dependent	upon	the	predictability	and	containment	of	costs	of	operation,	utilization	of	low- cost	technology,	selection	of	favorable	sites	and	availability	of	quality	fuel	and	permits	contributes	to	the	success	of	the	contract	generation	business.	AES	seeks	to	enter into	"turnkey"	engineering	contracts	for	each	power	generation	facility	it	develops.	Turnkey	contracts	allow	AES	to	more	reliably	establish	the	total	cost	of	construction and	development	and	to	delegate	the	majority	of	the	construction	responsibilities	thereby

eliminating	a	significant	portion	of	the	cost	uncertainties	otherwise	inherent	in	new	power	plant	development.

								Competitive	Supply.				AES's	competitive	supply	line	of	business	is	oriented	around	the	customer	perspective	and	consists	of	generating	facilities	and	retail	supply businesses	that	sell	electricity	directly	to	wholesale	and	retail	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	generating	facilities	included	in	this	line	of	business	represent	19,713	Gross	MW	in	8	different countries,	including	42%	(8,414MW)	in	Asia,	28%	(5,476MW)	in	Europe/Africa,	14%	(2,730MW)	in	South	America,	9%	(1,721MW)	in	North	America	and	7% (1,372MW)	in	the	Caribbean.	In	addition,	AES	is	also	currently	in	the	process	of	adding	approximately	4,121MW	to	its	competitive	supply	operating	portfolio	through its	construction	of	new	plants.	These	include	a	210	MW	natural	gas-fired	plant,	a	450	MW	natural	gas-fired	plant,	two	720	MW	natural	gas-fired	plants,	a	500	MW natural	gas-fired	plant	and	a	1,056	MW	natural	gas-fired	plant	in	the	United	States,	a	123	MW	hydroelectric	facility	in	Argentina,	two	hydroelectric	facilities	totaling 230MW	in	Panama,	and	a	112	MW	natural	gas-fired	plant	in	Tanzania.	In	the	case	of	several	generating	facilities,	including	Drax,	only	a	portion	of	the	output	is	subject to	the	provisions	of	long	term	price	hedging	instruments.	This	line	of	business	represented	approximately	9%	of	pre-tax	segment	income	and	29%	of	total	revenues	in 2001	compared	to	21%	and	32%,	respectively	for	2000.

								The	retail	portion	of	AES's	competitive	supply	business	focuses	on	providing	electricity	and	energy	related	products	and	services	to	commercial	and	industrial	end users	through	the	New	Energy	group	of	companies	in	the	U.K.	and	in	those	states	in	the	U.S.	that	have	introduced	a	competitive	market	for	the	sale	of	electricity	to	end users,	including	California,	Delaware,	Illinois,	Maine,	Maryland,	Massachusetts,	New	Hampshire,	New	York,	Ohio,	Pennsylvania,	Rhode	Island	and	Texas.	The	New Energy	group	of	companies	has	approximately	2,700	customers.	In	these	markets,	AES	typically	enters	into	single	or	multi-year	electricity	supply	contracts	with	its customers.	These	contracts	may	be	structured	as	shared	savings	arrangements,	fixed	savings	arrangements	or	fixed	price	supply	contracts.	AES	also	engages	in	wholesale purchases	and	sales	of	electricity	to	support	its	retail	electricity	sales	to	consumers.	The	wholesale	purchases	or	sale	of	electricity	often	require	substantial	additional credit	support,	and	this	credit	support	currently	is	provided	to	New	Energy	through	(i)	Letters	of	Credit	backed	by	AES,	(ii)	third	parties	such	as	surety	companies	or (iii)	guarantees	by	AES.	AES	is	currently	evaluating	whether	continuing	to	provide	such	credit	support	for	New	Energy's	business	is	an	appropriate	use	of	its	capital resources,	and	is	exploring	alternative	credit	arrangements	for	New	Energy.	Such	arrangements	may	include	finding	a	third	party	credit	provider	for	all	of	New	Energy's credit	needs,	or	a	sale	of	part	or	all	of	AES's	interest	in	New	Energy.

								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	without	forcing	integration,	while	allowing	integration	to	occur	in	those	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	can	be,	and	from	time	to	time	have	been,	unpredictable	and	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.

								Large	Utilities.				AES's	large	utility	business	is	comprised	of	five	integrated	utilities	located	in	the	U.S.	(IPALCO	and	CILCORP),	Brazil	(Eletropaulo	and	CEMIG) and	Venezuela	(EDC).	AES's	equity	interest	in	each	of	these	utilities	is	over	70%	other	than	CEMIG	in	which	AES's	equity	interest	is	only	21%.	As	of	December	31, 2001,	AES	also	owned	a	minority	interest	in	a	sixth	utility,	Light,	which	was	exchanged	in	February	2002	for	an	additional	ownership	interest	in	Eletropaulo.	All	of these	utilities	are	of	significant	size,	and	all	but	CILCORP	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	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	customer	tariffs	and	to	a	lesser	extent	from	contractual	agreements of	varying	lengths	and	provisions.	AES's	large	utilities,	including	IPALCO	(3,036MW),	CILCORP	(1,157MW),	Light	(793MW),	EDC	(2,265MW)	and	CEMIG (5,668MW),	aggregate	12,919	Gross	MW	of	generation	capacity	and	serve	over	thirteen	million	customers	with	annual	sales	of	nearly	120,000	gigawatt	hours.	AES's large	utility	business	represented	approximately	51%	of	pre-tax	segment	income	and	26%	of	total	revenues	in	2001	compared	to	46%	and	28%,	respectively	in	2000. 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,	or	IPL.	IPL	is	engaged	primarily	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, primarily	in	and	around	Indianapolis.	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	capability	is	3,118MW,	net	winter	capability	is 3,129MW	and	net	summer	capability	is	3,036MW.

								CILCORP	is	a	holding	company	whose	principal	business	subsidiary	is	Central	Illinois	Light	Company	(CILCO).	CILCO	is	engaged	in	the	generation,

transmission,	distribution	and	sale	of	electric	energy	in	an	area	of	approximately	3,700	square	miles	in	central	and	east-central	Illinois,	and	the	purchase,	distribution, transportation	and	sale	of	natural	gas	in	an	area	of	approximately	4,500	square	miles	in	central	and	east-central	Illinois,	where	the	electricity	industry	has	undergone

deregulation.	As	part	of	its	regulatory	approval	to	acquire	IPALCO,	AES	is	required	to	divest	CILCORP,	which	divestiture	process	is	currently	underway.

								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	regulatory	agency	ANEEL	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	4.7	million customers	or	about	41%	of	the	population	in	the	State	of	São	Paulo.

								CEMIG	is	engaged	in	electricity	generation,	transmission	and	distribution	in	Minas	Gerais	State,	Brazil.	CEMIG	operates	a	distribution	network	that	extends	over 270,000	kilometers,	the	largest	in	Latin-America,	and	supplies	over	4.5	million	customers	throughout	Minas	Gerais	State,	Brazil.

								EDC	was	founded	in	1895	and	is	the	largest	private-sector	electric	utility	in	Venezuela	serving	approximately	1.1	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	2,265MW.

								AES	seeks	to	acquire	large	utilities	that	it	believes	it	can	successfully	restructure	by	focusing	on	improving	efficiencies	to	achieve	cost	savings	while	providing	high quality	services	to	its	customers.	Each	utility	employs	business	personnel	with	direct	contact	with	its	customers.

								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	require	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.

								Growth	Distribution.				AES's	growth	distribution	line	of	business	includes	distribution	facilities	that	offer	significant	potential	for	growth	because	they	are	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.	Additionally,	because	these facilities	face	challenges	relating	to	operational	difficulties	such	as	outdated	equipment,	significant	non-technical	losses,	cultural	problems,	emerging	economies, unstable	governments,	underdeveloped	regulatory	regimes	or	location	in	a	developing	nation	they	allow	for	operating	improvements	and	financial	performance improvements	greater	than	that	typically	seen	in	the	large	utility	segment.	Distribution	facilities	included	in	this	line	of	business	may	include	generation,	transmission, distribution	or	related	services	companies.

								AES's	growth	distribution	business	represented	approximately	10%	of	pre-tax	segment	income	and	18%	of	total	revenues	in	2001	compared	to	2%	and	17%, respectively	in	2000.	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	800	Gross	MW	of	generation	and	serve	over	5.4	million	customers	with	sales	exceeding	30,844	gigawatt	hours	in	Argentina,	Brazil,	Cameroon, Dominican	Republic,	El	Salvador,	Georgia	and	Ukraine.

								AES	believes	it	can	leverage	its	operating	expertise,	decentralized	approach	and	considerable	experience	in	developing	nations	to	improve	the	performance	of	these facilities.	There	is	currently	little	competition	in	the	growth	distribution	business.	As	deregulation	and	privatization	efforts	mature	and	more	developing	nations	seek competitive	power	providers,	the	potential	size	of	this	market	continues	to	grow	and,	depending	on	the	rate	of	progress,	may	evolve	into	either	a	contract	generation	or competitive	supply	business	or	a	large	utility.

# Principles,	Values	and	Practices

								A	core	part	of	AES's	corporate	culture	is	a	commitment	to	"shared	principles	or	values."	These	principles	describe	how	AES	people	endeavor	to	commit	themselves to	the	Company's	mission	of	serving	the	world	by	providing	safe,	clean,	reliable	and	low-cost	electricity.	The	principles	are:

								Integrity—AES	strives	to	act	with	integrity,	or	"wholeness."	AES	people	seek	to	keep	the	same	moral	code	at	work	as	at	home.

								Fairness—AES	wants	to	treat	fairly	its	people,	its	customers,	its	suppliers,	its	stockholders,	governments	and	the	communities	in	which	it	operates.

								Fun—AES	desires	that	people	employed	by	the	Company	and	those	people	with	whom	the	Company	interacts	have	fun	in	their	work.	The	Company	believes	that making	decisions	and	being	accountable	is	fun	and	has	structured	its	organization	to	maximize	the	opportunity	for	fun	for	as	many	people	as	possible.

								Social	Responsibility—Primarily,	the	Company	believes	that	doing	a	good	job	at	fulfilling	its	mission	is	socially	responsible.	But	the	Company	also	believes	that	it has	a	responsibility	to	be	involved	in	projects	that	provide	other	social	benefits,	and	consequently	has	instituted	programs	such	as	corporate	matching	of	individual charitable	gifts	in	addition	to	various	local	programs	conducted	by	AES	businesses.

								AES	recognizes	that	most	companies	have	standards	and	ethics	by	which	they	operate	and	that	business	decisions	are	based,	at	least	in	part,	on	such	principles.	The Company	believes	that	an	explicit	commitment	to	a	particular	set	of	standards	is	a	useful	way	to	encourage	ownership	of	those	values	among	its	people.	While	the people	at	AES	acknowledge	that	they	won't	always	live	up	to	these	standards,	they	believe	that	being	held	accountable	to	these	shared	values	will	help	them	behave more	consistently	with	such	principles.

								AES	makes	an	effort	to	support	these	principles	in	ways	that	acknowledge	a	strong	corporate	commitment	and	encourage	people	to	act	accordingly.	For	example, AES	conducts	annual	surveys,	both	company-wide	and	at	each	business	location,	designed	to	measure	how	well	its	people	are	doing	in	supporting	these	principles through	interactions	within	the	Company	and	with	people	outside	the	Company.	These	surveys	are	perhaps	most	useful	in	revealing	failures,	and	helping	to	deal	with those	failures.	AES's	principles	are	relevant	because	they	help	explain	how	AES	people	approach	the	Company's	business.	The	Company	seeks	to	adhere	to	these principles,	not	as	a	means	to	achieve	economic	success	but	because	adherence	is	a	worthwhile	goal	in	and	of	itself.

# AES	Facilities

								The	following	tables	set	forth	information	regarding	the	Company's	facilities	that	are	in	operation	or	under	construction	at	December	31,	2001.	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.

# Competitive	Supply

# North	America

| Light-Ilha	dos	Pombos* | Hydro |  | 1996 | Brazil | 169 |  | 24 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Light-Nilo\tPecanha* | \t Hydro |  | 1996 | Brazil | 380 |  | 24 |
| Light-Pereira\tPassos* | \t Hydro |  | 1996 | Brazil | 100 |  | 24 |
| CEMIG\t(35\tplants) | \t Hydro |  | 1997 | Brazil | 5,068 |  | 21 |
| CEMIG-Miranda | \t Hydro |  | 1997 | Brazil | 390 |  | 21 |
| CEMIG-Igarapava | \t Hydro |  | 1998 | Brazil | 210 |  | 21 |
| Caribbean |  |  |  |  |  |  |  |
| EDC-generation\t(4\tplants) | \t Gas |  | 2000 | Venezuela | 2,265 |  | 87 |
| Growth\tDistribution |  |  |  |  |  |  |  |
| Europe/\tAfrica |  |  |  |  |  |  |  |
| SONEL | \t Hydro |  | 2001 | Cameroon | 800 |  | 51 |
|  |  |  |  | Approximate |  |  |  |
|  |  |  |  | Number\tof |  | AES\tEquity |  |
|  | Year\tof | Geographic |  | Customers | Approximate | Interest |  |
| Distribution\tFacilities | acquisition | Location |  | served | Gigawatt\tHours | (percent) |  |
| Competitive\tSupply |  |  |  |  |  |  |  |
| Eastern\tKazakhstan\tREC | 1999 | Kazakhstan |  | 291,000 | 1,455 | 0 |  |
| Semipalatensk\tREC | 1999 | Kazakhstan |  | 178,513 | 1,117 | 0 |  |
| Large\tUtilities |  |  |  |  |  |  |  |
| North\tAmerica |  |  |  |  |  |  |  |
| IPALCO | 2000 | USA |  | 433,010 | 16,256 | 100 |  |
| Cilicorp-Electricity | 1999 | USA |  | 193,000 | 6,743 | 100 |  |
| South\tAmerica |  |  |  |  |  |  |  |
| Light* | 1996 | Brazil |  | 2,800,000 | 19,981 | 24 |  |
| CEMIG | 1997 | Brazil |  | 4,680,000 | 32,179 | 21 |  |
| Eletropaulo* | 1998 | Brazil |  | 4,657,306 | 34,789 | 50 |  |
| Caribbean |  |  |  |  |  |  |  |
| EDC-distribution | 2000 | Venezuela |  | 1,131,552 | 9,724 | 87 |  |
|  |  | 15 |  |  |  |  |  |
| Growth\tDistribution |  |  |  |  |  |  |  |
| South\tAmerica |  |  |  |  |  |  |  |
| Sul | 1997 | Brazil |  | 935,125 | 7,390 | 96 |  |
| Eden | 1997 | Argentina |  | 278,854 | 1,886 | 90 |  |
| Edes | 1997 | Argentina |  | 141,281 | 834 | 90 |  |
| Edelap | 1998 | Argentina |  | 279,568 | 2,102 | 90 |  |
| Europe\tand\tAfrica |  |  |  |  |  |  |  |
| SONEL | 2001 | Cameroon |  | 452,000 | 3,020 | 51 |  |
| 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 |  |
| Cesco | 1999 | India |  | 600,000 | 2,102 | 48 |  |
| Caribbean |  |  |  |  |  |  |  |
| CLESA | 1998 | El\tSalvador |  | 226,000 | 669 | 64 |  |
| EDE\tEste | 1999 | Dominican\tRepublic |  | 350,000 | 2,990 | 51 |  |
| CAESS | 2000 | El\tSalvador |  | 443,430 | 1,697 | 70 |  |
| DEUSEM | 2000 | El\tSalvador |  | 43,362 | 75 | 69 |  |
| EEO | 2000 | El\tSalvador |  | 162,496 | 339 | 83 |  |

* On	February	6,	2002,	AES	exchanged	its	interest	in	Light	for	an	additional	31%	equity	interest	in	Eletropaulo.

								Over	the	past	decade,	regulations	and	laws	affecting	U.S.	and	world	electricity	generation	and	distribution	businesses	have	moved	toward	more	competition	and less	government	control.	The	timing	of	this	transition	and	the	nature	of	the	new	regulatory	rules	vary	greatly	among	states	and	countries.

# Regulatory	Outlook

								Over	the	past	decade	the	United	States	and	other	countries,	mostly	advanced	industrial	economies,	implemented	a	series	of	regulatory	policies	that	encourage competition	in	wholesale	and	retail	electricity	markets.	In	the	United	States,	such	policies	have	been	implemented	both	at	the	federal	and	state	level,	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.

								Recently,	however,	primarily	as	a	result	of	events	in	California	(the	electricity	shortage	and	price	rise	in	the	summer	of	2000)	and	the	bankruptcy	of	Enron, previously	the	largest	U.S.	electricity	trading	company,	in	the	fall	of	2001,	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	towards	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,	while	in	2001	the	state	of	California	abandoned	the	framework for	deregulation	that	had	been	adopted	in	1996,	the	Federal	Energy	Regulatory	Commission	("FERC")	has	not	indicated	any	inclination	to	revisit	"Order	888",	the administrative	cornerstone	for	the	opening	of	the	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	Assembly	Bill	1890,	the	act	which restructured	California's	electricity	system	in	1996.	Under	this	legislation,	a	complex	competitive	wholesale	market	was	established,	the	utilities	agreed	to	sell	a	major portion	of	their	generation	assets	and	retail	prices	were	fixed	at	a	level	that	was	believed	to	give	utilities	a	fair	return,	assuming	the	market	behaved	as	expected	over	the next	few	years.	Unfortunately,	due	to	a	shortage	of

rainfall	and	other	factors	the	California	market	did	not	behave	as	expected,	and	electricity	shortages	statewide	resulted.	(See	below	"California	Businesses"	for	more information).

								The	new	market	structure	did	not	adequately	address	undersupply	issues	which	caused	extremely	volatile	wholesale	electricity	prices.	This,	coupled	with	fixed retail	prices,	caused	the	utilities	in	California	to	face	severe	economic	distress.	While	the	confluence	of	environmental	and	market	conditions	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,	the	problems	experienced	in	California	could	be	repeated	elsewhere.

								The	events	in	California	have	generally	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	Electric	Power	Supply	Association	shows	18	States	have	passed	restructuring	legislation,	6	States	have	delayed	or	suspended such	legislation,	and	26	States	have	no	restructuring	plans	for	2002.	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.

								The	federal	government,	through	regulations	promulgated	by	the	FERC,	has	primary	jurisdiction	over	wholesale	electricity	markets.	These	markets	have	been essentially	deregulated	since	1990	and	the	mix	of	market	players	has	shifted	dramatically	toward	unregulated,	non-utility	entities,	referred	to	as	independent	power producers	or	wholesale	generators.	The	Electric	Power	Supply	Association	reports	that	non-utility	generators	now	account	for	over	40	percent	of	U.S.	wholesale generation.

								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.	By	far	the	largest	such	marketer/trader	was	Enron,	accounting	for	over	80%	percent	by	volume of	the	wholesale	market	in	2001.	In	December	2001,	Enron	filed	for	bankruptcy.	While	the	Enron	bankruptcy	has	had	minimal	effect	on	AES	directly,	the	bankruptcy could	result	in	a	less	liquid	wholesale	market,	in	which	AES	participates	as	both	a	generator	and	a	retailer,	going	forward.	Due	to	the	size	and	credit	rating	of	Enron	prior to	the	bankruptcy,	stricter	trading	and	credit	requirements	are	likely	to	be	implemented,	which	could	make	future	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,	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	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,	2001	the	Company	had receivables	of	$13	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.	In	May,	2001,	the	U.S.	Department	of Justice	initiated	an	investigation	under	the	Sherman	Act	to	determine	whether	a	particular	section	of	the	Tolling	Agreement	relating	to	the	addition	of	new	capacity	in southern	California	is	anti-competitive.	(See	"Legal	Proceedings"	for	more	information).

								AES	owns	and	operates	approximately	4,450	megawatts	of	operational	generating	capacity	in	California,	another	1,500	MW	under	construction	and	refurbishment, and	also	sells	electricity	to	commercial	and	industrial	end	users	through	AES	NewEnergy.	Approximately	3,956	megawatts	of	the	operating	generation	(Alamitos, Huntington	Beach	and	Redondo	Beach)	are	subject	to	a	long-term	tolling	agreement.	Under	this	agreement,	AES's	subsidiaries	receive	predetermined	capacity, operating	and	maintenance	payments	in	return	for	operating	the	plant	for	the	benefit	of	the	third	party.	As	a	result,	the	revenues	of	these	subsidiaries	do	not	materially reflect	the	electricity	price	volatility	experienced	in	California	during	2001.	The	Company	also	owns	120	MW	of	combined	cycle	gas-fired	capacity	at	its	Placerita facility,	as	well	as	a	total	of	355	MW	at	four	plants	that	it	acquired	in	2001	through	its	purchase	of	all	common	shares	of	Thermo	Ecotek,	including	two	gas-fired	plants —Mountainview	(126	MW)	and	Riverside	Canal	(154	MW)—and	two	wood-fired	plants—Delano	(50	MW)	and	Mendota	(25	MW).

# Argentina

								Argentina	is	experiencing	a	significant	political,	social	and	economic	crisis	that	has	resulted	in	important	changes	in	general	economic	policies	and	regulations	as well	as	specific	changes	in	the	energy	sector.	During	January	and	February	2002,	many	new	economic	measures	have	been	adopted	by	the	Argentine	government, including	abandoning	the	country's	fixed	U.S.	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	has	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	until	June	30,	2002.	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	the	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.	This	new regime	is	to	be	in	place	at	least	until	June	30,	2002.	During	the	period	until	June	30,	the	government	and	the	distribution	companies	are	to	negotiate	a	new	regulatory framework	applicable	to	the	electricity	distribution	sector.

								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	flows,	due	primarily	to	the	non-recourse	financing	structure	in place	at	most	of	AES's	Argentine	businesses.	The	effects	of	the	current	circumstances	on	net	income	beginning	in	2002	are	much	more	uncertain	and	difficult	to	predict. AES's	total	contributed	cash	investment	and	retained	earnings	in	the	competitive	supply	business	in	Argentina	is	approximately	$575	million	and	the	total	similar investment	in	the	growth	distribution	business	is	approximately	$465	million.

								Depending	on	the	ultimate	resolution	of	these	uncertainties,	AES	may	be	required	in	2002	to	record	a	material	impairment	loss	or	write-off	associated	with	the recorded	carrying	values	of	its	investments,	including	goodwill,	although	no	such	loss	has	been	recorded	to	date.	Additionally,	under	current	conditions,	the	Argentine businesses	may	also	incur	operating	losses	during	2002.

								AES	is	currently	investigating	and	pursuing	several	potential	alternatives	to	minimize	ongoing	impacts	on	net	income.	It	is	possible,	as	AES	pursues	these alternatives,	that	future	Argentine	business	results	may	be	reported	as	discontinued	operations.

# Brazil

								The	Brazilian	electricity	industry	is	regulated	by	the	National	Electric	Power	Agency	(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)	oversight	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	Wholesale	Energy	Market	(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	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	until	such	losses	are	recovered	(expected	to	be	three	to	four	years)

•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.

								In	addition,	the	agreement	provided	a	resolution	to	a	long	standing	regulatory	issue	related	to	a	portion	of	the	distribution	tariffs	known	as	Parcel	A.	Parcel	A	is	the portion	of	a	tariff	calculation	formula	which	provides	for	the	recovery	of	certain	costs	that	are	not	within	the	control	of	the	distribution	company.	A	tracking-account	was established	in	order	to	compensate	for	monthly	variances	in	these	non-manageable	costs,	which	occur	between	tariff	adjustment	dates.	These	cost	variances	will	also have	retroactive	interest	rate	compensation	starting	from	January	1,	2001.	The	following	non-manageable	costs	are	included	in	the	tracking-account:	power	purchases from	the	Itaipu	hydro-electric	facility	(including	exchange	rate	variations	between	the	U.S.	Dollar	and	the	Brazilian	Real),	fuel	costs,	system	charges,	and	financial compensation	for	hydro	resources	and	transmission	charges.

								The	agreement,	which	includes	all	of	the	provisions	discussed	above,	is	contained	in	Provisional	Measure	#14,	dated	December	21,	2001.	The	Provisional	Measure has	the	status	of	law	but	needs	to	be	approved	by	the	Congress	within	120	days	of	its	publication.

								In	addition,	every	three	years	the	tariffs	applicable	to	distribution	companies	are	adjusted	based	on	a	formula,	which	contains	an	"X"	factor.	The	X	factor	is intended	to	permit	the	regulator	to	adjust	the	tariffs	so	that	consumers	may	share	in	the	distribution	company's	realization	of	increased	operating	efficiencies.	The revision,	however,	is	entirely	within	the	regulators	discretion.	The	next	adjustment	is	scheduled	for	2003.

# 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 inefficient	unit	required	by	the	system	at	the	time.	The	regulation	of	prices	charged	by	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	based	on	the	marginal	cost	of production.	Chile	has	two	interconnected	electricity	systems,	the	SIC	and	the	SING.

								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	between	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	required	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	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	48	months	in	the	case	of	the	SIC	and	over	the	next	24	months	in the	case	of	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	industrial customers	and	other	generation	companies	purchasing	on	a	contractual	basis	are	unregulated	and	are	generally	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	48	months,	in	the	case	of	the	SIC,	or 24	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.

# 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.

								In	anticipation	of	the	implementation	of	NETA	and	the	changes	to	the	wholesale	electricity	trading	arrangements	in	England	and	Wales,	AES	Drax	and	TXU

Europe	Energy	Trading	Limited

(TXU),	the	successor	entity	to	Eastern	Power	and	Energy	Trading	Limited,	agreed	to	amend	the	15-year	hedging	contract	to	preserve	the	original	commercial	intent	of the	parties.	The	principal	modification	involved	the	conversion	of	the	arrangement	from	financial	to	physical	settlement.	The	amendment	of	the	TXU	contract	required the	consent	of	a	majority	of	the	lenders	under	the	AES	Drax	bank	facility	and	senior	bonds.	AES	Drax	obtained	required	approval	on	May	23,	2001.

								Due	to	lower	long-term	projections	of	electricity	prices	in	the	U.K	market,	and	resulting	lower	debt	service	coverage	ratios	on	AES	Drax's	Senior	Secured	Bonds and	Senior	Secured	Bank	Debt,	as	well	as	a	recent	increase	in	the	property	damage	and	business	interruption	insurance	deductible,	AES	Drax's	Senior	Secured	Bonds and	Senior	Secured	Bank	Facility	were	downgraded	by	Fitch	and	Moody's	from	BBB-/Baa3	to	BB+/Ba1	on	November	30,	2001	and	December	7,	2001,	respectively. AES	Drax's	Senior	Notes	(subordinated	debt)	were	also	downgraded	from	BB/Ba2	to	B+/B1	by	Fitch	and	Moody's,	respectively.	Subsequent	to	year	end,	AES	Drax	had an	event	of	default	under	its	Senior	Secured	Bonds	and	Senior	Secured	Bank	Debt	as	a	result	of	its	inability	to	obtain	specified	minimum	amounts	of	insurance	coverage. This	is	more	fully	discussed	in	the	"Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations"	section.

								AES	Drax	has	maintained	its	ratings	with	Standard	&	Poors	although	they	have	placed	both	the	senior	debt	and	subordinated	debt	on	negative	watch.	The	direct effect	of	the	downgrades	has	been	increased	borrowing	costs	and	increased	the	credit	support	required	for	certain	of	the	bilateral	contracts	entered	into	by	AES	Drax since	the	introduction	of	NETA.	AES	Drax	has	taken	steps	designed	to	address	the	concerns	expressed	by	the	rating	agencies,	but	there	can	be	no	assurance	that	these steps	will	be	sufficient.	In	the	event	Standard	&	Poors	were	to	downgrade	the	rating	on	AES	Drax's	senior	secured	debt,	which	is	AES	Drax's	sole	remaining	investment grade	rating,	it	is	likely	AES	Drax	would	experience	significantly	increased	demands	for	credit	support	and	even	greater	borrowing	costs.

# 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.	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	is	currently	considering	amending	the	tariff	Joint	Resolution	for	the	year	2002	in	order	to	introduce	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	construction	and	operation	of	power	projects	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	discharge	of	effluents	into	the	water,	emissions	into	the	air	and	the	use	of	water,	but	can	also	include	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	8	of	the	consolidated	financial	statements	for more	detail.	AES	is	committed	to	operating	its	businesses	cleanly,	safely	and	reliably	and	strives	to	comply	with	all	environmental	laws,	regulations,	permits	and licenses.	Despite	such	efforts,	the	Company	has	at	times	been	in	non-compliance	with	such	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	NOx	SIP	call,	the	Section	126	petitions	and	other	air	emissions	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	will	likely	be	required	to	make	significant	capital	or	other	expenditures	in connection	with	such	changes	in	environmental	laws	or	regulations,	although	AES's	businesses	generally	take	into	account	capital	expenditures	for	future	environmental compliance.	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	(in	particular,	sulfur	dioxides	("SO 2")	and	nitrogen	oxides	("NOx"))	from	newly	built	sources.	Among	other	things,	the	1990	Amendments	attempt	to	reduce acid	rain	precursor	emissions	(SO 2	and	NOx)	from	existing	sources,	particularly	large,	older	power	plants	that	were	exempted	from	certain	regulations	under	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.	In	May	1999,	the	EPA	issued	its	final	guidelines	for	the	revised	ground	level	ozone	and	particulate matter,	which	further	delineate	the	so-called	"non	attainment	regions"	and	other	non-attainment	classifications.	In	October	1999,	a	federal	appeals	court	overturned	the new	standards.	In	February	2001,	the	U.S.	Supreme	Court	upheld	the	new	standards,	but	held	that

the	EPA's	policy	of	implementing	these	standards	in	non-attainment	regions	was	unlawful	and	remanded	the	case	to	a	federal	appeals	court	for	review.	In December	2001,	the	federal	appeals	court	heard	oral	arguments	regarding	EPA's	implementation	of	these	standards	in	non-attainment	regions.	The	federal	appeals	court's ruling	is	expected	in	the	Spring	of	2002.	If	the	EPA	develops	a	reasonable	interpretation	of	these	standards	as	they	may	be	applied	in	non-attainment	regions,	consistent with	the	court	decisions,	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.

								NOx	SIP	Call.				In	October	1998,	the	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	(a	precursor	to	ozone	formation)	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.	In	March	2000,	a	federal	appeals	court	upheld	the	NOx	SIP Call,	but	remanded	minor	aspects	of	the	rule	to	the	EPA	for	further	rulemaking	action.	In	February	2002,	the	EPA	issued	its	proposed	rule.	The	EPA	final	rule	is expected	by	April	2003.	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	and	incur estimated	capital	expenditures	of	approximately	$380-540	million	in	connection	therewith.

								Section	126	Petitions.				In	a	related	action,	the	EPA	in	December	1999	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	significantly	contribute	to	non-attainment	of	the	NAAQS	for	ozone	in	the	northeastern	downwind	states.	Although	the	original	deadline	for compliance	under	the	Section	126	Rule	is	May	1,	2003,	in	a	memorandum	dated	January	18,	2002,	the	EPA	stated	its	intention	to	establish	a	May	31,	2004	compliance date	for	all	affected	sources,	subject	to	the	completion	of	its	response	to	a	related	court	decision.	The	EPA's	intention,	if	implemented,	would	align	the	compliance	dates for	the	Section	126	Rule	and	the	NOx	SIP	Call	described	above.	As	a	result	of	the	Section	126	Rule,	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,	the	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")	permitting	requirements.	In	May	2001,	the	Bush	Administration	directed	the EPA	to	review	the	NSR	permitting	requirements	and	the	U.S.	Department	of	Justice	to	review	its	existing	NSR	enforcement	actions,	with	the	goal	of	ensuring	the	NSR requirements	and	enforcement	thereof	are	consistent	with	the	Clean	Air	Act	and	its	regulations.	In	January	2002,	the	U.S.	Department	of	Justice	concluded	that	EPA's pending	enforcement	actions	are	a	reasonable	interpretation	of	the	Clean	Air	Act.	The	EPA's	report,	which	was	originally	due	in	August	2001,	has	not	been	issued	to date.	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	established	planning	and	emission	reduction	timelines	for	states	to	use	to improve	visibility	in	national	parks	throughout	the	U.S.	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	new	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	rules	are	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").	Although	the	HAP	provisions	of	the	1990 Amendments	presently	do	not	apply	to	electric	and	steam	generating	facilities	such	as	AES's	U.S.	plants,	the	1990	Amendments	directed	the	EPA	to	prepare	a	study	on HAP	emissions	from	power	plants.	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.

								Global	Warming.				Global	warming	continues	to	be	a	concern.	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.	While	it	seems	unlikely the	Kyoto	Protocol	will	be	ratified	by	the	requisite	number	of	signatory	countries	any	time	soon,	global	warming	remains	a	policy	issue	that	is	regularly	considered	for possible	government	regulation.	Indeed,	several	European	countries	(including	the	U.K.)	have	some	regulations	concerning	greenhouse	gases.	Although	AES	believes that	U.S.	government	legislation	requiring	reductions	in	greenhouse	gases	(other	than	voluntary	reductions)	is	unlikely,	such	legislation	could	substantially	affect	both	the costs	and	the	operating	characteristics	of	AES's	fossil-fuel	(coal,	oil,	gas)	fired	businesses.	See	"Recent	Legislative	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,	the	"Clean	Power	Act"	sponsored	by	Senator	Jeffords	of	the	State	of	Vermont	and	Senator Lieberman	of	the	State	of	Connecticut	would	require	significant	reductions	in	emissions	of	four	major	power	plant	pollutants—CO 2,	NOx,	SO 2	and	mercury.	In addition,	in	February	2002,	President	Bush	announced	a	climate	change	and	multi-emissions	control	strategy	which	is	likely	to	result	in	legislation	similar	to	the	Clean Power	Act,	but	would	require	reductions	in	only	three	pollutants	(NOx,	SO 2	and	mercury),	with	voluntary	reductions	of	CO 2.	Finally,	in	February	2002,	the	New	York Department	of	Environmental	Conservation	("DEC")	issued	proposed	regulations	requiring	electric	generators	to	reduce	SO 2	emissions	by	50%	below	current	Clean	Air Act	standards.	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	summertime	ozone	season:	May	through	the	end of	September	of	each	year.	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.

								On	February	28,	2002,	the	EPA,	pursuant	to	Section	316	of	the	United	States	Federal	Water	Pollution	Control	Act,,	approved	a	proposed	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	28,	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	also	subject	to	other	laws	and	regulations	including	EU	directives	and	national	legislation	implementing	those directives.	In	particular,	the	EU	Directive	on	Integrated	Pollution	Prevention	and	Control	could	impose	onerous	permitting,	air	emissions	reduction	and	other environmental	requirements	on	AES's	EU	facilities	during	this	decade.	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.	If	the	governments	of	each	of	those	Member	Nations,	in	particular,	the	United	Kingdom,	Germany	and	The Netherlands,	ratify	the	Kyoto	Protocol,	costs	and	the	operating	characteristics	of	AES's	plants	in	the	EU	may	be	affected.	These	costs	could	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	and	more	stringent	environmental	and land	use	laws	and	regulations.	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

								Contract	generation.				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.

								Competitive	supply.				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.

								Large	Utilities.				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.

								Growth	distribution.				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,	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	2001	net	sales.

# Employees

# Executive	Officers	and	Significant	Employees	of	the	Registrant

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

								Dennis	W.	Bakke,	56	years	old,	co-founded	the	Registrant	with	Roger	Sant	in	1981	and	has	been	a	director	of	the	Registrant	since	1986.	He	has	been	President	of the	Registrant	since	1987	and	Chief	Executive	Officer	since	January	1994.	From	1987	to	1993,	he	served	as	Chief	Operating	Officer	of	the	Registrant;	from	1982	to 1986,	he	served	as	Executive	Vice	President	of	the	Registrant;	and	from	1985	to	1986	he	also	served	as	Treasurer	of	the	Registrant.	He	served	with	Mr.	Sant	as	Deputy Assistant	Administrator	of	the	Federal	Energy	Agency	("FEA")	from	1974	to	1976	and	as	Deputy	Director	of	the

Energy	Productivity	Center,	an	energy	research	organization	affiliated	with	The	Mellon	Institute	at	Carnegie	Mellon	University,	from	1978	to	1981.	He	is	a	trustee	of Rivendell	School	and	a	member	of	the	Board	of	Directors	of	MacroSonix	Corporation.

								Paul	T.	Hanrahan,	43	years	old,	was	appointed	one	of	four	Chief	Operating	Officers	in	February	2002.	His	responsibilities	include	overseeing	the	growth distribution	business	segment.	He	was	appointed	Executive	Vice	President	in	February	2000,	has	been	a	Senior	Vice	President	since	1997,	and	was	appointed	Vice President	of	the	Registrant	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	Registrant, from	1990	to	1993.

								William	R.	Luraschi,	38	years	old,	was	appointed	Senior	Vice	President	in	February	2002	and	has	been	Vice	President	of	the	Registrant	since	January	1998, Secretary	since	February	1996	and	General	Counsel	of	the	Registrant	since	January	1994.	Prior	to	that,	Mr.	Luraschi	was	an	attorney	with	the	law	firm	of	Chadbourne	& Parke	L.L.P.

								Dr.	Roger	F.	Naill,	55	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	form	Dartmouth	College	and	a	MSM	Degree	from	the	A.P.	Sloan	School	of	Business	(MIT).

								John	Ruggirello,	51	years	old,	was	appointed	one	of	four	Chief	Operating	Officers	in	February	2002.	His	responsibilities	include	overseeing	the	contract	generation business	segment.	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	lead	the	AES	Enterprise	group,	with	responsibility	for	project	development,	construction	and	plant	operations	in	the	Mid- Atlantic	region	of	the	United	States.	He	served	as	President	of	AES	Beaver	Valley	from	1990	to	1996.

								J.	Stuart	Ryan,	43	years	old,	was	appointed	one	of	four	Chief	Operating	Officers	in	February	2002.	His	responsibilities	include	overseeing	the	competitive	supply business	segment.	He	was	appointed	Executive	Vice	President	of	the	Registrant	in	February	2000,	was	Senior	Vice	President	until	February	2000	and	was	President	of the	AES	Pacific	group,	which	is	responsible	for	the	Company's	business	in	Western	North	America.	Between	1994	and	1998,	Mr.	Ryan	lead	the	AES	Transpower	group responsible	for	AES's	activities	in	Asia	(excluding	China).	From	1994	through	1997,	he	served	as	Vice	President	of	the	Registrant.	Prior	to	1994,	Mr.	Ryan	served	as general	manager	of	a	group	within	AES.	Mr.	Ryan	also	serves	on	Lehigh	University's	Global	Advancement	Council	and	The	Alumni	Association	Board	of	Directors.	He is	also	on	the	Board	of	Directors	of	C.A.	La	Electricidad	de	Caracas.

								Roger	W.	Sant,	70	years	old,	co-founded	the	Company	with	Dennis	Bakke	in	1981.	He	has	been	Chairman	of	the	Board	and	a	director	of	the	Registrant	since	its inception,	and	he	held	the	office	of	Chief	Executive	Officer	through	December	31,	1993.	He	currently	is	Chairman	of	the	Board	of	Directors	of	The	Summit	Foundation, is	a	Regent	of	the	Smithsonian	Institution,	and	serves	on	the	Boards	of	Directors	of	The	World	Wildlife	Fund	US	and	Marriot	International,	Inc.	He	was	Assistant Administrator	for	Energy	Conservation	and	the	Environment	of	the	Federal	Energy	Agency	("FEA")

from	1974	to	1976	and	the	Director	of	the	Energy	Productivity	Center,	an	energy	research	organization	affiliated	with	The	Mellon	Institute	at	Carnegie-Mellon University,	from	1977	to	1981.

								Barry	J.	Sharp,	42	years	old,	was	appointed	one	of	four	Chief	Operating	Officers	in	February	2002	and	continues	to	hold	the	position	of	Chief	Financial	Officer.	His responsibilities	include	overseeing	the	finance	function	as	well	as	the	large	utilities	business	segment.	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 Registrant	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,	58	years	old,	has	been	Senior	Vice	President	of	the	Registrant	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.

(d)	Financial	Information	About	Foreign	and	Domestic	Operations	and	Export	Sales.

								See	the	information	contained	under	the	caption	"Segments"	in	Note	16	to	the	Consolidated	Financial	Statements	included	in	Item	8	herein.

# ITEM	2—PROPERTIES

								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.

# ITEM	3—LEGAL	PROCEEDINGS

								In	September	1999,	an	appellate	judge	in	the	Minas	Gerais,	Brazil	state	court	system	granted	a	temporary	injunction	that	suspends	the	effectiveness	of	a shareholders'	agreement	for	CEMIG.	This	appellate	ruling	suspends	the	shareholders'	agreement	while	the	action	to	determine	the	validity	of	the	shareholders'	agreement is	litigated	in	the	lower	court.	In	early	November	1999,	the	same	appellate	court	judge	reversed	this	decision	and	reinstated	the	effectiveness	of	the	shareholders' agreement,	but	did	not	restore	the	super	majority	voting	rights	that	benefited	the	Company.	In	March	2000,	a	state	court	in	Minas	Gerais	again	ruled	that	the shareholders'	agreement	was	invalid.	In	April	2000,	the	appellate	court	denied	the	appeal	of	that	second	state	court	decision.	In	August	2001,	the	appellate	court	denied another	appeal,	confirming	the	decision	that	the	shareholders'	agreement	was	null	and	void.	In	November	2001,	a	special	procedure	was	initiated	whereby	CEMIG requested	that	the	case	be	transferred	from	state	court	to	superior	federal	court	in	Brasilia.	The	Company	intends	to	vigorously	pursue	its	legal	rights	in	this	matter	and	to restore	all	of	its	rights	regarding	CEMIG.	Failure	to	prevail	in	this	matter	would	limit	the	Company's	influence	on	the	daily	operations	of	CEMIG.	However,	the Company	would	still	own	approximately	21.6%	of	the	voting	common	stock	of	CEMIG.

								In	December	2000,	several	class	action	lawsuits	were	filed	in	California	against	multiple	wholesale	power	generators	and	marketers	in	California,	including	one class	action	that	named	AES.	The	complaint	naming	AES	alleges	violations	of	the	state	anti-competitive	behavior	act	as	well	as	antitrust

violations,	and	seeks	compensatory	and	punitive	damages.	AES	has	been	participating	in	a	joint	defense	arrangement	with	the	other	named	defendants.	The	AES	lawsuit

violations,	and	seeks	compensatory	and	punitive	damages.	AES	has	been	participating	in	a	joint	defense	arrangement	with	the	other	named	defendants.	The	AES	lawsuit has	been	consolidated	with	five	other	lawsuits	before	a	single	judge	in	San	Diego.	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.	The	Company	believes	it	has	meritorious	defenses	to	this	action	and	will	defend	itself	vigorously	against	the	allegations.

								The	crisis	in	the	California	wholesale	power	market	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	Southland,	AES	Placerita	and	AES	New	Energy)	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	responded	to	multiple	requests	for	the	production	of	documents and	data	surrounding	the	operation	of	the	plants.

								In	addition,	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.	In	connection	with	this	investigation,	the	FERC	also	commenced	a formal	administrative	investigation	into	the	maintenance	and	outage	practices	and	schedules	at	the	AES	Alamitos	and	AES	Huntington	Beach	plants	in	2000	and	2001. The	formal	investigation	also	focuses	on	the	activities	of	the	AES	plants	contractual	partner,	Williams	Energy	Services	Company	in	marketing	power	acquired	from	the plants.	The	AES	plants	have	supplied	documents	and	other	information	to	the	FERC	in	connection	with	its	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	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,	and	depositions	of	AES	and	Williams	personnel	are	ongoing.

								In	July	2001,	a	petition	was	filed	against	CESCO	by	the	Grid	Corporation	of	Orissa,	India	("Gridco"),	with	the	Orissa	Electricity	Regulatory	Commission ("OERC"),	alleging	that	CESCO	had	defaulted	on	its	obligations	as	a	government	licensed	distribution	company	and	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.	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	May	2000,	the	New	York	State	Department	of	Environmental	Conservation	("DEC")	issued	a	Notice	of	Violation	("NOV")	to	the	New	York	State	Electric	& Gas	Corporation	("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	at	those	plants	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	financial	and	operational	effect	of	this	NOV	is	still	being	discussed	with	the	DEC.	On	January	24,	2002,	DEC informed	AES	Eastern	Energy	that	it	would	be	included	as	a	responsible	party	under	the	NOV.	The	EPA	also	indicated	the	NOV	could	include	alleged	violations	of similar	rules	at	the	Hickling	and	Jennison	plants.	The	NOV	is	expected	to	be	issued	in	early	2002.	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.	The	fines	proposed	against	NYSEG	could	be	significant.	NYSEG	has	asserted	a	claim	against	AES	for	indemnification	against	all	penalties	and	other related	costs	arising	out	of	DEC's	allegations.	AES	believes	it	has	meritorious	defenses	to	NYSEG's	claims,	and	intends	to	vigorously	defend	itself	against	them.	The NOV	and	DEC's	allegations	of	opacity	exceedences	and	any	additional	enforcement	actions	that	might	be	brought	by	the	New	York	State	Attorney	General,	the	DEC	or the	EPA,	against	any	of	AES's	New	York	plants,	may	ultimately	result	in	the	imposition	of	penalties	and	may	require	further	emission	reductions	at	those	plants.

								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	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.	AES	Beaver	Valley	and	the	EPA	continue	to	discuss	potential	remedies	and	settlement	of	the	EPA's allegations.	A	settlement,	if	reached,	could	include	the	addition	of	pollution	control	technology	and	the	payment	of	potential	fines	and	penalties.	The	Company	believes it	has	meritorious	defenses	against	EPA's	allegations	and	intends	to	vigorously	defend	itself	against	them.

								The	Company	is	involved	in	certain	other	legal	proceedings	in	the	normal	course	of	business.	It	is	the	opinion	of	the	Company	that	none	of	the	pending	litigation will	have	a	material	adverse	effect	on	its	financial	position	or	cash	flows.

# 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	2001.

# PART	II

# ITEM	5—MARKET	FOR	REGISTRANT'S	COMMON	EQUITY	AND	RELATED	STOCKHOLDER	MATTERS

# (a)	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

| 2001 | High | Low | 2000 | High | Low |
| :--- | :--- | :--- | :--- | :--- | :--- |
| First\tQuarter | $60.15 | $41.30 | First\tQuarter | $44.72 | $34.25 |
| Second\tQuarter | 52.25 | 39.95 | Second\tQuarter | 49.63 | 35.56 |
| Third\tQuarter | 44.50 | 12.00 | Third\tQuarter | 70.25 | 45.13 |
| Fourth\tQuarter | 17.80 | 11.60 | Fourth\tQuarter | 72.81 | 45.00 |

# (b)	Holders.

# (c)	Dividends.

								Under	the	terms	of	the	Company's	corporate	revolving	loan	and	letters	of	credit	facility	of	$850	million	entered	into	with	a	commercial	bank	syndicate	and	other bank	agreements,	the	Company	is	currently	limited	in	the	amount	of	cash	dividends	it	is	allowed	to	pay.	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	Company	has	met	these	tests	at	all	times	since	making	the	guaranty.

								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.	Such	limitations	permit	the	payment	of	cash	dividends	out	of	current	cash	flow for	quarterly,	semiannual	or	annual	periods	only	at	the	end	of	such	periods	and	only	after	payment	of	principal	and	interest	on	project	loans	due	at	the	end	of	such periods,	and	in	certain	cases	after	providing	for	debt	service	reserves.

# ITEM	6—SELECTED	FINANCIAL	DATA

| Revenues | $9,327 | $7,534 | $4,117 | $3,257 | $2,227 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Income\tfrom\tcontinuing\toperations | 467 | 827 | 377 | 437 | 284 |
| Discontinued\toperations | (194) | (21) | (3) | — | — |
| Extraordinary\titems,\tnet\tof\tapplicable\tincome\ttaxes | — | (11) | (17) | 4 | (3) |
| Cumulative\teffect\tof\tchange\tin\taccounting\tprinciple | — | — | — | — | 18 |
| Net\tincome | 273 | 795 | 357 | 441 | 299 |
| Basic\tearnings\tper\tshare: |  |  |  |  |  |
| From\tcontinuing\toperations | $0.88 | $1.72 | $0.89 | $1.10 | $0.75 |
| Discontinued\toperations | (0.36) | (0.04) | (0.01) | — | — |
| Extraordinary\titems | — | (0.02) | (0.04) | 0.01 | (0.01) |
| Cumulative\teffect\tof\tchange\tin\taccounting\tprinciple | — | — | — | — | 0.05 |
| Basic\tearnings\tper\tshare | $0.52 | $1.66 | $0.84 | $1.11 | $0.79 |
| Diluted\tearnings\tper\tshare: |  |  |  |  |  |
| From\tcontinuing\toperations | $0.87 | $1.65 | $0.87 | $1.06 | $0.75 |
| Discontinued\toperations | (0.36) | (0.04) | (0.01) | — | — |
| Extraordinary\titems | — | (0.02) | (0.04) | 0.01 | (0.01) |
| Cumulative\teffect\tof\tchange\tin\taccounting\tprinciple | — | — | — | — | 0.05 |
| Diluted\tearnings\tper\tshare | $0.51 | $1.59 | $0.82 | $1.07 | $0.79 |

|  | 2001 | 2000 | 1999 | 1998 | 1997 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (in\tmillions) |  |  |
| Balance\tSheet\tData: |  |  |  |  |  |
| Total\tassets | $36,736 | $33,038 | $23,222 | $12,900 | $11,065 |
| Non-recourse\tdebt\t(long-term) | 14,673 | 12,696 | 9,521 | 4,505 | 4,522 |
| Recourse\tdebt\t(long-term) | 4,913 | 3,458 | 2,167 | 1,644 | 1,096 |
| Mandatorily\tredeemable\tpreferred\tstock\tof\tsubsidiary | 22 | 22 | 22 | — | — |
| Company\tobligated\tconvertible\tmandatorily\tredeemable\tpreferred\tsecurities\tof |  |  |  |  |  |
| subsidiary\ttrust\tholding\tsolely\tjunior\tsubordinated\tdebentures\tof\tAES | 978 | 1,228 | 1,318 | 550 | 550 |
| Stockholders'\tequity | 5,539 | 5,542 | 3,315 | 2,368 | 2,006 |

# ITEM	7—DISCUSSION	AND	ANALYSIS	OF	FINANCIAL	CONDITION	AND	RESULTS	OF	OPERATIONS

# Recent	Strategic	Initiatives

								AES	has	recently	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,	enhance	its	profitability,	reduce	its	earnings	volatility	and	improve	short-term	liquidity.

# Strategic	Repositioning

								After	evaluating	changes	in	the	electricity	industry,	the	capital	markets	generally	and	circumstances	applicable	to	certain	of	the	Company's	businesses,	the	Company has	decided	that	additional	financial	strength	and	flexibility	at	the	parent	level	will	enhance	the	Company's	competitive	advantage	in	the

future.	To	accomplish	this	goal,	the	Company	will	seek	to	reduce	leverage,	particularly	at	the	parent	level,	through	some	combination	of	dividends	from	operating subsidiaries,	equity	issuances	and	the	strategic	sale	of	certain	businesses.	These	initiatives,	particularly	asset	dispositions,	will	be	conducted	after	extensive	evaluation and	are	likely	to	take	several	years	to	complete.	In	addition,	in	an	effort	to	reduce	earnings	and	cash	flow	volatility,	the	Company	may	seek	to	reduce	its	concentration	of businesses	in	certain	geographic	markets	like	Latin	America	as	well	as	its	exposure	to	fluctuations	in	wholesale	electricity	prices,	particularly	in	its	merchant	generation businesses.

# Decreasing	Dependence	on	Capital	Markets

								In	response	to	recent	declines	in	the	trading	prices	for	AES's	equity	and	debt	securities	which	have	created	significant	uncertainty	regarding	AES's	ability	to	access the	capital	markets	on	acceptable	terms,	AES	has	undertaken	a	number	of	steps	designed	to	minimize	the	need	for	the	parent	company	to	access	the	capital	markets during	2002	by	increasing	its	near	term	liquidity.	These	steps	include:

•Reducing	planned	capital	expenditures	for	2002,	primarily	for	new	facilities	under	construction,	to	approximately	$710	million	from	$1.2	billion

•Significantly	reducing	planned	business	development	spending

•Proceeding	with	selective	near	term	assets	sales,	including	the	sale	of	all	of	CILCORP,	a	wholly	owned	subsidiary,	and	the	sale	of	Itabo,	an	equity method	investment,	and	certain	project	financings	and	refinancings.

								AES	is	continuing	to	evaluate	the	impacts	of	further	reducing	planned	capital	expenditures.	In	addition,	in	some	instances	the	Company	may	sell	development projects.	There	can	be	no	guarantee	that	the	proceeds	from	such	transactions	would	cover	the	entire	investment	in	such	projects.	Also,	the	Company	may	incur	additional expenses	related	to	the	reduction	of	planned	capital	expenditures.

# Cost	Cutting	Office

								In	early	2002,	the	Company	created	the	Cost	Cutting	Office	(which	assumed	many	of	the	responsibilities	of	the	cost	cutting	task	force	which	was	created	in	late 2001).	The	Cost	Cutting	Office's	mission	is	to:

•Better	capture	the	benefits	of	scale	in	the	procurement	of	services	and	supplies

•Take	advantage	of	cross	business	opportunities

•Systematically	audit	progress

								Although	there	can	be	no	assurance	that	such	efforts	will	be	successful,	AES's	goal	is	to	achieve	aggregate	cost	savings	of	approximately	$50	million	in	2002.

# Turnaround	Office

								In	early	2002,	AES	established	a	Turnaround	Office	(which	assumed	many	of	the	responsibilities	of	the	task	force	on	under-performing	businesses	which	was created	in	late	2001).	The	Turnaround	Office's	mission	is	to:

•Identify	underperforming	businesses	and

•Fix,	sell	or	abandon	these	underperforming	businesses.

The	Turnaround	Office	identified	six	businesses	that	were	underperforming:	Drax,	Sul,	Uruguaiana,	Chivor,	TermoAndes	and	Telasi.	All	of	these	businesses	are	either merchant	generating	plants	or	are	located	in	Latin	America,	except	for	Telasi	which	is	in	growth	distribution	in	Asia.	AES	is	in	the

process	of	identifying	whether	the	profitability	of	such	businesses	can	be	sufficiently	improved	to	remain	part	of	AES's	portfolio,	or	whether	such	businesses	should	be sold	or	abandoned.

# New	Reporting	Segments

								In	late	2001,	the	Company	completed	a	strategic	review	of	its	operations	that	resulted	in	a	reorganization	of	the	Company	into	four	business	units.

•Contract	generation

•Large	utilities

•Growth	distribution

The	table	set	forth	below	shows	the	percentage	of	revenues,	gross	margin	and	total	assets	represented	by	each	of	these	units	for	the	year	ended	December	31,	2001.

%	of	Revenues %	of	Gross	Margin %	of	Total	Assets

| Contract	generation | 27% | 36% | 35% |
| :--- | :--- | :--- | :--- |
| Competitive\tsupply | 29% | 19% | 28% |
| Large\tutilities | 26% | 32% | 25% |
| Growth\tdistribution | 18% | 13% | 12% |

								Statement	of	Financial	Accounting	Standards	("SFAS")	No.	131	requires	companies	to	disclose	certain	information	about	their	operating	segments	where	operating segments	are	defined	as	"components	of	an	enterprise	about	which	separate	financial	information	is	available	that	is	evaluated	regularly	by	the	chief	operating	decision maker	in	deciding	how	to	allocate	resources	and	in	assessing	performance".	Generally,	financial	information	is	required	to	be	reported	on	the	basis	that	it	is	used internally	for	evaluating	segment	performance	and	deciding	how	to	allocate	resources	to	segments.	The	Company	has	determined	that	its	four	business	units	constitute reportable	"segments"	for	purposes	of	SFAS	No.	131	and	accordingly,	has	presented	the	required	financial	information	in	Note	16	to	the	consolidated	financial statements.

# Additional	Developments

# 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	severance	and	employee	benefits,	asset	write-downs	and	impairments	and	otherwise.	The	Company	is	currently	assessing	the	impact such	dispositions	will	have	on	the	pooling-of-interests	accounting	used	for	the	IPALCO	acquisition.	Such	dispositions	may	require	the	acquisition	to	be	restated	as	a purchase.

								Argentina	is	experiencing	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	have	been	adopted	by	the	Argentine	government,	including abandoning	the	country's	fixed	dollar-to-peso	exchange	rate,	converting	dollar	denominated	loans	into	pesos	and	placing	restrictions	on	the	convertibility	of	the Argentine	peso.	The	government	has	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	until	June	30,	2002.	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.	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,	2001,	AES's	total	contributed	cash	investment	and	retained earnings	in	the	competitive	supply	business	in	Argentina	is	approximately	$575	million	and	the	total	investment	in	the	growth	distribution	business	is	approximately $465	million.	Depending	on	the	ultimate	resolution	of	these	uncertainties,	AES	may	be	required	in	2002	to	record	a	material	impairment	loss	or	write-off	associated	with the	recorded	carrying	values	of	its	investments,	including	goodwill,	although	no	such	loss	has	been	recorded	to	date.	Additionally,	under	current	conditions,	the Argentine	businesses	may	also	incur	operating	losses	during	2002.	AES	is	currently	investigating	and	pursuing	several	potential	alternatives	to	minimize	the	impacts	on future	earnings.	It	is	possible,	as	AES	pursues	these	alternatives,	that	future	Argentine	business	results	may	be	reported	as	discontinued	operations.

								During	2001,	the	Brazilian	Real	experienced	a	significant	devaluation	relative	to	the	U.S.	Dollar,	declining	from	1.96	Reais	to	the	Dollar	at	December	31,	2000	to 2.41	Reais	at	December	31,	2001.	Also,	during	1999,	the	Brazilian	Real	experienced	a	significant	devaluation	relative	to	the	U.S.	Dollar	declining	from	1.21	Reais	to	the U.S.	Dollar	at	December	31,	1998	to	1.81	Reais	to	the	U.S.	Dollar	at	December	31,	1999.	This	continued	devaluation	resulted	in	significant	foreign	currency	translation and	transaction	losses	particularly	during	2001	and	1999.	The	Company	recorded	$210	million,	$64	million	and	$203	million	before	income	taxes	of	non-cash	foreign currency	transaction	losses	on	the	U.S.	dollar	denominated	debt	at	its	investments	in	Brazilian	equity-method	affiliates	during	2001,	2000	and	1999,	respectively.	These amounts	are	recorded	in	equity	in	pre-tax	earnings	of	affiliates	in	the	accompanying	consolidated	income	statements.	Further	devaluation	of	the	Brazilian	Real	will continue	to	have	a	negative	impact	on	the	Company's	results	of	operations.

								In	December	2001,	the	Company's	Brazilian	subsidiaries	and	equity	affiliates	reached	an	agreement	(the	"agreement")	with	the	Brazilian	government	that	provided resolution	to	all	rationing	related	issues	as	well	as	to	certain	other	issues.	There	were	three	parts	to	the	agreement.	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	until	all recoverable	amounts	are	collected	which	the	Company	estimates	to	be	approximately	three	years.	The	agreement	also	establishes	that	BNDES,	the	National Development	Bank	of	Brazil,	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,	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.

								The	third	part	of	the	agreement	relates	to	the	sales	price	that	Sul,	the	Company's	distribution	subsidiary	in	Porto	Alegre,	would	receive	for	its	sales	of	excess	energy. As	a	result	of	the	agreement,	Sul	recorded	approximately	$100	million	of	additional	revenue	and	a	corresponding	receivable	from	the	spot	market	in	the	fourth	quarter. Sul	had	elected	early	in	2001,	as	permitted	under	its	concession	contract,	to	expose	itself	to	gains	or	losses	based	on	the	difference	between	the	market	price	of	energy	in the	South	where	they	normally	sell	electricity	and	the	Southeast	where	they	take	delivery.	Drought	conditions	in	the	Southeast,	even	with	rationing,	created	a	large imbalance	between	prices	in	the	Southeast	and	the	South	resulting	in	the	substantial	gain.	Sul	had	not	recorded	the	revenue	prior	to	the	fourth	quarter	because	rationing had	made	the	spot	market	illiquid	and	the	negotiations	on-going	with	the	government,	distributors	and	generators	created	an	environment	where	collection	of	the receivable	was	not	assured.	The	BNDES	pre-funding	of	the	tariff	increase	through	loans	to	the	distributors	and	generators	added	the	needed	liquidity	to	the	spot	market	to

# assure	collection.

								Eletropaulo.				AES	has	owned	an	interest	in	Eletropaulo	Metropolitana	Electricidade	de	Sao	Paulo	S.A.	("Eletropaulo")	since	May	1999	and	has	gradually increased	its	ownership	interest	in	Eletropaulo	through	a	series	of	transactions	since	then.	Historically,	AES	has	accounted	for	this	investment	using	the	equity-method	of accounting.	On	February	6,	2002,	AES	acquired	a	controlling	interest	in	Eletropaulo	and	consequently	will	begin	consolidating	the	subsidiary	in	2002.	As	of	December 31,	2001,	Eletropaulo	had	$1.6	billion	of	outstanding	indebtedness,	approximately	$868	million	of	which	is	scheduled	to	mature	during	2002	and	the	remaining	maturing thereafter.	AES's	total	investment	including	retained	earnings	associated	with	Eletropaulo	as	of	December	31,	2001,	was	approximately	$1.3	billion.	In	addition,	AES financed	certain	of	its	purchases	in	Eletropaulo	through	deferred	purchase	price	financing	arrangements	provided	by	BNDES	to	subsidiaries	of	the	Company,	which aggregates	approximately	$1.2	billion.	The	payment	schedule	varies	from	April	2002	through	January	2004.	BNDES	maintains	as	collateral	shares	that	represent substantially	all	of	the	Company's	ownership	interest	in	Eletropaulo.	As	a	result	of	the	volatility	of	the	Brazilian	Real	and	the	difficult	economic	conditions	in	Brazil,	the Company	is	evaluating	whether	to	contribute	equity	sufficient	to	allow	such	subsidiaries	to	make	the	payments.	If	AES	does	not	contribute	sufficient	equity	or	other consideration,	or	if	there	is	not	a	successful	renegotiation	of	the	debt	with	BNDES,	there	can	be	no	assurance	that	such	subsidiaries	will	be	able	to	pay	such	amounts,	or refinance	or	extend	the	maturities	of	any	or	all	of	the	payment	amounts.	In	such	event,	BNDES	may	choose	to	seize	the	shares	held	as	collateral,	and	this	may	result	in	a loss	and	resulting	write-off	of	a	portion	or	all	of	the	Company's	investment.

								Due	to	the	slowing	economy,	falling	oil	revenues,	capital	flight	and	a	decline	in	foreign	reserves,	the	Venezuelan	government	began	floating	its	currency	on February	12,	2002.	For	the	past	five	years,	the	Venezuelan	currency	had	been	traded	within	a	fixed	band,	which	only	allowed	it	to	trade	at	7.5%	above	or	below	a	central point,	a	daily	rate	set	by	the	Banco	Central	de	Venezuela.	As	a	result	of	the	change	the	U.S.	Dollar	to	Venezuelan	exchange	rate	had	floated	as	high	as	1,110.60	before declining	to	895.01	at	March	21,	2002	as	compared	to	757.50	at	December	31,	2001.	Our	tariffs	at	EDC	in

Venezuela	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.

# Accounting	for	Derivatives

								On	January	1,	2001,	the	Company	adopted	SFAS	No.	133,	"Accounting	for	Derivative	Instruments	and	Hedging	Activities,"	which,	as	amended,	established	new accounting	and	reporting	standards	for	derivative	instruments	and	hedging	activities.	SFAS	No.	133	requires	that	all	derivatives	(including	derivatives	embedded	in	other contracts)	be	recorded	as	either	assets	or	liabilities	at	fair	value	on	the	balance	sheet.	Changes	in	the	derivative's	fair	value	are	to	be	recognized	in	earnings	in	the	period of	change,	unless	hedge	accounting	criteria	are	met.	Hedge	accounting	allows	the	derivative's	gains	or	losses	in	fair	value	to	offset	the	related	results	of	the	hedged	item. 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	will	result	in	more	variation,	positive	or	negative,	to	the	Company's results	of	operations	from	changes	in	interest	rates,	foreign	exchange	rates	and	commodity	prices.	For	the	year	ended	December	31,	2001,	the	Company	recognized	$36 million	of	losses	pursuant	to	SFAS	No.	133	related	to	derivatives	which	did	not	qualify	for	hedge	accounting.	See	Note	7	to	the	consolidated	financial	statements	which provides	a	more	complete	discussion	of	the	accounting	for	derivatives	under	SFAS	No.	133.

# 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,	2001,	capitalized	costs	for	projects	under	development	and	in	early	stage construction	were	approximately	$68	million.	The	Company	believes	that	these	costs	are	recoverable;	however,	no	assurance	can	be	given	that	individual	projects	will	be completed	and	reach	commercial	operation.

# Enron

								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.	Other	Enron	subsidiaries	were	also	under	contract	to	provide	engineering,	procurement	and	construction	("EPC")	services	on	three	of	the	Company's greenfield	development	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.	With	respect	to	AES	Wolf	Hollow,	AES	has	contracted	with	Stone	&	Webster,	Inc.	for	EPC	services.	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.

# Energy	Trading	Activities

								The	Company	does	not	engage	in	significant	energy	trading	activities	associated	with	its	retail	and	wholesale	supply	businesses.	For	the	years	ended	December	31, 1999,	2000	and	2001,	the	Company	recorded	net	gains	from	energy	trading	activities	of	$3	million,	$21	million	and	$5	million,	respectively.

# 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.	See	Note	8	to	the	consolidated	financial	statements	for	a	more	complete	discussion	of	this transaction.

								The	Company	has	investments	in	several	equity	method	affiliates,	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	4	to	the	consolidated	financial	statements	for summarized	financial	information	from	our	equity	method	affiliates.

# Related	Party	Transactions

								The	Company	did	not	enter	into	any	material	related	party	transactions	during	the	years	ended	December	31,	1999,	2000	and	2001.

# Significant	Accounting	Policies

# General

								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	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	or	equipment	could	have	a	material	adverse impact	on	our	operating	results	in	the	period	in	which	the	estimate	is	revised	and	subsequent	periods.

# 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.	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.

# 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	assets	are	recovered	when	AES	collects	the	related	costs	through billings	to	customers.	AES	has	recorded	deferred	regulatory	assets	of	$390	million	and	$401	million	at	December	31,	2001,	and	2000,	respectively,	that	it	expects	to pass	through	to	its	customers	in	accordance	with	and	subject	to	regulatory	provisions.	The	regulatory	assets	include	$134	million	and	$110	million	at	December	31, 2001,	and	2000,	respectively,	which	are	AES's	share	of	regulatory	assets	recorded	by	AES's	equity	method	affiliates	in	Brazil,	which	are	included	in	the	investments	and advances	to	affiliates	balance	on	the	accompanying	consolidated	balance	sheets.	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.	AES	is	subject	to	various	environmental	regulations,	and	is	involved	in certain	legal	proceedings.	If	AES'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

								In	June	2001,	the	FASB	issued	SFAS	No.	142,	"Goodwill	and	Other	Intangible	Assets."	The	provisions	of	this	statement	are	required	to	be	applied	starting	with fiscal	years	beginning	after	December	15,	2001.	This	statement	is	required	to	be	applied	at	the	beginning	of	an	entity's	fiscal	year	and	to	be	applied	to	all	goodwill	and other	intangible	assets	recognized	in	its	financial	statements	at	that	date.	SFAS	No.	142	addresses	how	intangible	assets	(but	not	those	acquired	in	a	business combination)	should	be	accounted	for	in	financial	statements	upon	their	acquisition.	This	statement	also	addresses	how	goodwill	and	other	intangible	assets	should	be accounted	for	after	they	have	been	initially	recognized	in	the	financial	statements.	The	statement	requires	that	goodwill	and	certain	other	intangibles	would	have	to	be assessed	each	year	to	determine	whether	an	impairment	loss	has	occurred.	Any	impairments	recognized	upon	adoption	would	be	recorded	as	a	change	in	accounting principle.

Future	impairments	would	be	recorded	in	income	from	continuing	operations.	The	statement	provides	specific	guidance	for	testing	goodwill	for	impairment.	The Company	had	$3.2	billion	of	goodwill	at	December	31,	2001.	Goodwill	amortization	was	$62	million	for	the	year	ended	December	31,	2001.	The	Company	is	currently assessing	the	impact	of	SFAS	No.	142	on	its	financial	position	and	results	of	operations.

								In	June	2001,	the	FASB	issued	SFAS	No.	143,	"Accounting	for	Asset	Retirement	Obligations,"	which	addresses	financial	accounting	and	reporting	for	obligations associated	with	the	retirement	of	tangible	long-lived	assets	and	the	associated	asset	retirement	costs.	This	statement	is	effective	for	financial	statements	issued	for	fiscal years	beginning	after	June	15,	2002.	The	statement	requires	recognition	of	legal	obligations	associated	with	the	retirement	of	a	long-lived	asset,	except	for	certain obligations	of	lessees.	The	Company	is	currently	assessing	the	impact	of	SFAS	No.	143	on	its	financial	position	and	results	of	operations.

								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	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	is	effective	beginning	April	1,	2002.	The	Company	is	currently	assessing	the	impact	of	revised	DIG	Issue	C-15	on	its	financial condition	and	results	of	operations.

# Revenues

								Revenues	increased	$1.8	billion,	or	24%	to	$9.3	billion	in	2001	from	$7.5	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	5%	to	$7.1	billion	in	2001.	The	following	table	shows	the	revenue	of	each	segment:

|  | 2001 | 2000 | %	Change |
| :--- | :--- | :--- | :--- |
| Contract\tgeneration | $2.5\tbillion | $1.7\tbillion | 47% |
| Competitive\tsupply | $2.7\tbillion | $2.4\tbillion | 13% |
| Large\tutilities | $2.4\tbillion | $2.1\tbillion | 14% |
| Growth\tdistribution | $1.7\tbillion | $1.3\tbillion | 31% |

								Contract	generation	revenues	increased	$800	million,	or	47%	to	$2.5	billion	in	2001	from	$1.7	billion	in	2000,	principally	resulting	from	the	addition	of	revenues attributable	to	businesses	acquired	during	2001	or	2000.	Excluding	businesses	acquired	or	that	commenced	commercial	operations	in	2001	or	2000,	contract	generation revenues	increased	2%	to	$1.7	billion	in	2001.	The	increase	in	contract	generation	segment	revenues	was	due	primarily	to	increases	in	South	America,	Europe/Africa and	Asia.	In	South	America,	contract	generation	segment	revenues	increased	$472	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	$88	million, and	the	acquisition	of	a	controlling	interest	in	Kilroot	during	2000	was	the	largest	contributor	to	the	increase.	In	Asia,	contract	generation	segment	revenues	increased $96	million,	and	increased	operations	from	our	Ecogen	peaking	plant	was	the	most	significant	contributor	to	the

increase.	In	North	America,	contract	generation	segment	revenues	increased	$46	million.	In	the	Caribbean	(which	includes	Venezuela	and	Colombia),	contract generation	segment	revenues	increased	$11	million,	and	this	was	due	to	a	full	year	of	operations	at	Merida	III	offset	by	a	lower	capacity	factor	at	Los	Mina.

								Competitive	supply	revenues	increased	$300	million	or	13%	to	$2.7	billion	in	2001	from	$2.4	billion	in	2000.	Excluding	businesses	acquired	or	that	commenced commercial	operations	in	2001	or	2000,	competitive	supply	revenues	increased	3%	to	$2.4	billion	in	2001.	The	most	significant	increases	occurred	within	North America	and	the	Caribbean.	Slight	increases	were	recorded	within	South	America	and	Asia.	Europe/Africa	reported	a	slight	decrease	due	to	lower	pool	prices	in	the U.K.	offset	by	the	start	of	commercial	operations	at	Fifoots	and	the	acquisition	of	Ottana.	In	North	America,	competitive	supply	segment	revenues	increased	$184 million	due	primarily	to	an	expanded	customer	base	at	New	Energy	as	well	as	increased	operations	at	Placerita.	These	increases	in	North	America	were	offset	by	lower market	prices	at	our	New	York	businesses.	In	the	Caribbean,	competitive	supply	segment	revenues	increased	$123	million	due	primarily	to	the	acquisition	of	Chivor.

								Large	utility	revenues	increased	$300	million,	or	14%	to	$2.4	billion	in	2001	from	$2.1	billion	in	2000,	principally	resulting	from	the	addition	of	revenues attributable	to	businesses	acquired	during	2001	or	2000.	Excluding	businesses	acquired	in	2001	and	2000,	large	utility	revenues	increased	1%	to	$1.6	billion	in	2001. The	majority	of	the	increase	occurred	within	the	Caribbean,	and	there	was	a	slight	increase	in	North	America.	In	the	Caribbean,	revenues	increased	$312	million	due	to	a full	year	of	revenues	from	EDC,	which	was	acquired	in	June	2000.

								Growth	distribution	revenues	increased	$400	million,	or	31%	to	$1.7	billion	in	2001	from	$1.3	billion	in	2000.	Excluding	businesses	acquired	in	2001	or	2000, growth	distribution	revenues	increased	20%	to	$1.3	billion	in	2001.	Revenues	increased	most	significantly	in	the	Caribbean	and	to	a	lesser	extent	in	South	America	and Europe/Africa.	Revenues	decreased	slightly	in	Asia.	In	the	Caribbean,	growth	distribution	segment	revenues	increased	$296	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	$89	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.	In	Europe/Africa,	growth	distribution	segment	revenues	increased	$59	million	from	the	acquisition	of	SONEL.	In	Asia,	growth	distribution	segment revenues	decreased	$33	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	the	Ukraine.

								AES	is	a	global	power	company	which	operates	in	29	countries	around	the	world.	The	breakdown	of	AES's	revenues	for	the	years	ended	December	31,	2001	and 2000,	based	on	the	geographic	region	in	which	they	were	earned,	is	set	forth	below.	A	more	detailed	breakdown	by	country	can	be	found	in	Note	16	of	the	consolidated financial	statements.

|  | 2001 | 2000 | %	change |
| :--- | :--- | :--- | :--- |
| North\tAmerica | $\t3.6\tbillion | $\t3.4\tbillion | 6% |
| South\tAmerica | $\t1.7\tbillion | $\t1.1\tbillion | 55% |
| Caribbean* | $\t1.9\tbillion | $\t1.1\tbillion | 73% |
| Europe/Africa | $\t1.4\tbillion | $\t1.3\tbillion | 8% |
| Asia | $693\tmillion | $615\tmillion | 13% |

* Includes	Venezuela	and	Colombia.

# Gross	margin

								Gross	margin	increased	$307	million,	or	15%,	to	$2.3	billion	in	2001	from	$2.0	billion	in	2000.	Gross	margin	as	a	percentage	of	revenues	decreased	to	25%	in	2000 from	26%	in	2001.	The	increase	in	gross	margin	is	due	to	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	competitive	supply	and	contract	generation	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	2%	to	$1.8	billion	in	2001.

|  | 2001 | 2000 | %	Change |
| :--- | :--- | :--- | :--- |
| Contract\tgeneration | $827\tmillion | $767\tmillion | 8% |
| Competitive\tsupply | $440\tmillion | $559\tmillion | (21%) |
| Large\tutilities | $739\tmillion | $538\tmillion | 37% |
| Growth\tdistribution | $296\tmillion | $131\tmillion | 126% |

								Contract	generation	gross	margin	increased	$60	million,	or	8%,	to	$827	million	in	2001	from	$767	million	in	2000.	Excluding	businesses	acquired	or	that

commenced	commercial	operations	during	2001	and	2000,	contract	generation	gross	margin	decreased	6%	to	$710	million	in	2001.	Contract	generation	gross	margin increased	in	all	geographic	regions	except	for	Asia.	The	contract	generation	gross	margin	as	a	percentage	of	revenues	decreased	to	33%	in	2001	from	44%	in	2000.	In South	America,	contract	generation	gross	margin	increased	$17	million	and	was	27%	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	Southland	and	Beaver	Valley	partially	offset	by	a	decrease	at	Thames	from	the	contract	buydown	(see	footnote	13	to	the	Company's	consolidated financial	statements).	In	Europe/Africa,	contract	generation	gross	margin	increased	$44	million	and	was	30%	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	$22	million	and	was	29%	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, which	are	lower	than	the	overall	portfolio	of	generation	businesses.	As	a	percentage	of	sales,	contract	generation	gross	margin	declined	in	South	America	and	Asia,	was relatively	flat	in	North	America	and	increased	in	Europe/Africa	and	the	Caribbean.

								The	competitive	supply	gross	margin	decreased	$119	million,	or	21%,	to	$440	million	in	2001	from	$559	million	in	2000.	Excluding	businesses	acquired	or	that commenced	commercial	operations	during	2001	and	2000,	competitive	supply	gross	margin	decreased	26%	to	$408	million	in	2001.	The	overall	decrease	is	due	to declines	in	Europe/Africa	and	South	America	that	were	partially	offset	by	slight	increases	in	North	America,	the	Caribbean	and	Asia.	The	competitive	supply	gross margin	as	a	percentage	of	revenues	decreased	to	16%	in	2001	from	23%	in	2000.	In	South	America,	competitive	supply	segment	gross	margin	decreased	$61	million and	was	1%	of	revenues	due	to	declines	at	our	businesses	in	Argentina.	In	Europe/Africa,	competitive	supply	segment	gross	margin	decreased	$95	million	and	was	22% of	revenues.	The	decrease	is	due	primarily	to	declines	at	Drax,	Barry	and	Fifoots	from	the	lower	market	prices	in	the	U.K.	In	North	America,	competitive	supply segment	gross	margin	increased	$14	million	and	was	11%	of	revenues.	The	increase	was	due	to	an	expanded	customer	base	at	New	Energy	and	was	partially	offset	by decreases	at	Somerset	in	New	York	and	Deepwater	in	Texas.	In	the	Caribbean	(which	includes	Colombia),	the	competitive	supply	gross	margin	increased	$15	million and	was	29%	of	revenues.	The	increase	is	due	primarily	to	the	acquisition	of	Chivor.	As	a	percentage

of	sales,	competitive	supply	gross	margin	declined	in	South	America,	Europe/Africa	and	the	Caribbean	and	remained	relatively	flat	in	North	America	and	Asia.

								Large	utilities	gross	margin	increased	$201	million,	or	37%,	to	$739	million	in	2001	from	$538	million	in	2000.	Excluding	businesses	acquired	or	that	commenced commercial	operations	during	2001	and	2000,	large	utilities	gross	margin	increased	10%	to	$396	million	in	2001.	Large	utilities	gross	margin	as	a	percentage	of revenues	increased	to	30%	in	2001	from	25%	in	2000.	In	the	Caribbean	(which	includes	Venezuela),	large	utility	gross	margin	increased	$166	million	and	was	due	to	a full	year	of	contribution	from	EDC	which	was	acquired	in	June	2000.	Also,	in	North	America,	the	gross	margin	contributions	from	both	IPALCO	and	CILCORP increased.

								Growth	distribution	gross	margin	increased	$165	million,	or	126%	to	$296	million	in	2001	from	$131	million	in	2000.	Excluding	businesses	acquired	during	2001 and	2000,	growth	distribution	gross	margin	increased	93%	to	$268	million	in	2001.	Growth	distribution	gross	margin	as	a	percentage	of	revenue	increased	to	18%	in 2001	from	10%	in	2000.	Growth	distribution	business	gross	margin,	as	well	as	gross	margin	as	a	percentage	of	sales,	increased	in	South	America	and	the	Caribbean,	but decreased	in	Europe/Africa	and	Asia.	In	South	America,	growth	distribution	margin	increased	$157	million	and	was	38%	of	revenues.	The	increase	is	due	primarily	to Sul's	sales	of	excess	energy	into	the	southeast	market	where	rationing	was	taking	place.	In	the	Caribbean,	growth	distribution	margin	increased	$39	million	and	was	5% of	revenues.	The	increase	is	due	mainly	to	lower	losses	at	Ede	Este	and	an	increase	in	contribution	from	CAESS.	In	Europe/Africa,	growth	distribution	margin	decreased $10	million	and	was	negative	due	to	losses	at	SONEL.	In	Asia,	growth	distribution	margin	decreased	$18	million	and	was	negative	due	primarily	to	an	increase	in	losses at	Telasi.

								The	breakdown	of	AES's	gross	margin	for	the	years	ended	December	31,	2001	and	2000,	based	on	the	geographic	region	in	which	they	were	earned,	is	set	forth below.

|  | 2001 | %	of	Revenue | 2000 | %	of	Revenue | %	change |
| :--- | :--- | :--- | :--- | :--- | :--- |
| North\tAmerica | $912\tmillion | 25% | $844\tmillion | 25% | 8% |
| South\tAmerica | $522\tmillion | 30% | $416\tmillion | 36% | 25% |
| Caribbean* | $457\tmillion | 25% | $226\tmillion | 21% | 102% |
| Europe/Africa | $310\tmillion | 22% | $371\tmillion | 29% | (16%) |
| Asia | $101\tmillion | 15% | $138\tmillion | 22% | (27%) |

# 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	remained	constant	at	1%	in	2001	and	2000.	The	overall	increase	in	selling,	general	and	administrative	expenses	is	due	to	increased development	activities.

# Interest	expense,	net

								Net	interest	expense	increased	$327	million,	or	29%,	to	$1.5	billion	in	2001	from	$1.1	billion	in	2000.	Net	interest	expense	as	a	percentage	of	revenues	increased	to 16%	in	2001	from	15%	in	2000.	Net	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.

# Other	income,	net

								Other	income	decreased	$8	million,	or	26%,	to	$23	million	in	2001	from	$31	million	in	2000.	Other	income	includes	foreign	currency	transaction	gains	and	losses at	consolidated	subsidiaries	and	mark-to-market	adjustments	on	certain	derivative	financial	instruments	and	other	non-operating	income.

# Gain	on	sale	of	assets

								During	2000,	IPALCO	sold	certain	assets	("Thermal	Assets")	for	approximately	$162	million.	The	transaction	resulted	in	a	gain	to	the	company	of	approximately $31	million.	Of	the	net	proceeds,	$88	million	was	used	to	retire	debt	specifically	assignable	to	the	Thermal	Assets.

Gain	on	available	for	sale	securities

								During	2001,	a	subsidiary	of	the	Company	sold	approximately	14	million	shares	of	Compania	Anonima	Nacional	Telefonos	de	Venezuela	resulting	in	a	realized gain	of	approximately	$18	million.	During	2000,	a	subsidiary	of	the	Company	sold	approximately	one	million	shares	of	Internet	Capital	Group,	Inc.	resulting	in	a realized	gain	of	approximately	$112	million.

# Environmental	fine

								The	Company	recorded	a	$17	million	environmental	fine	in	2000	related	to	excess	nitrogen	oxide	air	emissions	at	certain	of	its	generating	facilities	in	California.

# Equity	in	pre-tax	earnings	of	affiliates

								Equity	in	pre-tax	earnings	of	affiliates	decreased	$300	million,	to	$175	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	resulted	from	the	devaluation	of	the	Brazilian	Real,	as	well	as	the	rationing	of electricity	in	Brazil.

								Equity	in	earnings	of	competitive	supply	affiliates	decreased	to	($5)	million	in	2001	from	$0	million	in	2000.	The	decrease	is	due	to	losses	incurred	at	Infovias,	a Brazilian	company.

								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	large	utilities	decreased	$286	million	to	$140	million	in	2001	from	$426	million	in	2000.	The	decrease	is	primarily	due	to	the	devaluation	of the	Brazilian	Real,	as	well	as	the	impact	of	electricity	rationing	in	Brazil.	Equity	in	earnings	of	large	utilities	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	($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.

# Income	taxes

								Income	taxes	(including	income	taxes	on	equity	in	earnings	and	minority	interests)	decreased	$147	million	to	$230	million	in	2001	from	$377	million	in	2000.	The Company's	effective	tax	rate	increased	to	33%	in	2001	from	31%	in	2000,	due	to	increased	dividends	from	foreign	businesses.

# 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.

# Minority	interest

								Minority	interest	(before	income	taxes)	decreased	$19	million,	or	15%,	to	$105	million	in	2001	from	$124	million	in	2000.	The	decreases	in	contract	generation, competitive	supply	and	growth	distribution	minority	interest	were	offset	slightly	by	an	increase	in	the	large	utilities	minority	interest.

								Contract	generation	minority	interest	decreased	$15	million	to	$22	million	in	2001	from	$36	million	in	2000.	The	decrease	in	contract	generation	minority	interest is	due	primarily	to	lower	contributions	from	Tiete.

								Competitive	supply	minority	interest	decreased	$26	million	to	$11	million	in	2001	from	$37	million	in	2000.	The	decrease	in	competitive	supply	minority	interest is	due	primarily	to	lower	contributions	from	Panama	and	CTSN.

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

								Growth	distribution	minority	interest	increased	$19	million	to	($16)	million	in	2001	from	($31)	million	in	2000.	The	increases	were	due	to	the	acquisition	of CAESS	and	increased	contributions	from	EDE	Este.

# 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.	As	a	result,	the	Company	recorded	$194	million	and	$21	million	in	2001	and	2000,	respectively,	net	of tax,	of	net	losses	from	these	businesses.	All	of	the	operations	for	these	businesses	and	the	related	write-offs	from	disposition	are	reported	in	this	line	item.	Results	of operations	in	2001	were	a	loss	of	approximately	$47	million	and	the	write-off	from	dispositions	was	a	loss	of	approximately	$147	million,	net	of	tax.	All	amounts	in	2000 represent	results	from	operations.

# Extraordinary	item

								On	March	31,	2000,	the	Company	replaced	its	corporate	revolving	bank	loan	with	a	new	facility	that	incorporated	the	letter	of	credit	facility.	As	a	result,	the Company	wrote-off	the	unamortized	deferred	financing	costs	related	to	the	refinanced	revolver	resulting	in	an	extraordinary	item	for	the	early	extinguishment	of	debt	of $7	million,	net	in	tax.	In	November	2000,	a	subsidiary	of	the	Company	sold	its	Thermal	Assets	to	Citizen	Gas	&	Coke	Utility.	A	portion	of	the	proceeds	was	used	to retire	debt	specifically	assignable	to	the	assets.	In	connection	with	the	retirement	of	the	debt,	the	subsidiary

wrote-off	debt	issuance	costs	of	$4	million,	which	resulted	in	an	extraordinary	loss	for	the	early	retirement	of	debt.

# 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	net	income	from competitive	supply	and	large	utility	businesses	offset	slightly	by	increases	in	the	contract	generation	and	growth	distribution	businesses.	The	decreases	are	primarily	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	$194	million.	Our	10	largest	contributors	to	net	income	in	2001	were	as	follows:	Lal	Pir/Pak	Gen,	Shady	Point	and	Thames	from	contract	generation; Somerset	from	competitive	supply;	EDC,	Eletropaulo,	IPALCO,	CILCORP	and	CEMIG	from	large	utilities;	and	Sul	from	growth	distribution.

								Revenues	increased	$3.4	billion,	or	83%,	to	$7.5	billion	in	2000	from	$4.1	billion	in	1999.	The	increase	in	revenues	is	due	primarily	to	the	acquisition	of	new businesses.	Excluding	businesses	acquired	or	that	commenced	commercial	operations	during	2000	or	1999,	revenues	increased	6%	to	$3.6	billion.

|  | 2000 | 1999 | %	Change |
| :--- | :--- | :--- | :--- |
| Contract\tgeneration | $1.7\tbillion | $\t1.3\tbillion | 31% |
| Competitive\tsupply | $2.4\tbillion | $873\tmillion | 175% |
| Large\tutilities | $2.1\tbillion | $992\tmillion | 112% |
| Growth\tdistribution | $1.3\tbillion | $948\tmillion | 37% |

								Contract	generation	revenues	increased	$400	million,	or	31%,	to	$1.7	billion	in	2000	from	$1.3	billion	in	1999.	Excluding	businesses	acquired	or	that	commenced commercial	operations	in	2000	or	1999,	contract	generation	revenues	increased	4%	to	$1.3	billion	in	2000.	The	increase	in	contract	generation	segment	revenues	was	due primarily	to	increases	in	South	America,	North	America,	Caribbean	and	Asia,	offset	by	a	slight	decline	in	Europe/Africa.	In	South	America,	contract	generation	segment revenue	increased	$245	million,	and	this	is	due	mainly	to	the	acquisition	of	Tiete.	In	North	America,	contract	generation	segment	revenues	increased	$76	million	due primarily	to	the	start	of	commercial	operations	at	Warrior	Run	in	January	2000.	In	the	Caribbean,	contract	generation	segment	revenues	increased	$92	million	due primarily	to	the	start	of	commercial	operations	at	Merida	III	in	June	2000	and	increased	revenues	from	Los	Mina.	In	Asia,	contract	generation	segment	revenue	increased $41	million	due	primarily	to	increased	operations	at	the	Ecogen	peaking	plant	and	Lal	Pir	and	Pak	Gen	in	Pakistan.	In	Europe/Africa,	contract	generation	segment revenues	remained	fairly	constant	with	decreases	at	Tisza	II	in	Hungary	being	offset	by	the	acquisition	of	a	controlling	interest	at	Kilroot.

								Competitive	supply	revenues	increased	$1.5	billion,	or	175%,	to	$2.4	billion	in	2000	from	$873	million	in	1999.	Excluding	businesses	acquired	or	that	commenced commercial	operations	in	2000	or	1999,	competitive	supply	revenues	increased	25%	to	$477	million	in	2000.	The	most	significant	increases	occurred	within	North America	and	Europe/Africa.	Slight	increases	occurred	in	South	America	and	the	Caribbean.	Asia	reported	a	slight	decrease.	In	North	America,	competitive	supply segment	revenues	increased	$610	million	due	primarily	to	the	New	York	plants	and	New	Energy

contributing	a	full	year	of	revenues	in	2000.	In	Europe/Asia,	competitive	supply	segment	revenues	increased	$875	million	due	primarily	to	Drax	contributing	a	full	year of	revenues	during	2000.

								Large	utilities	revenues	increased	$1.1	billion,	or	112%,	to	$2.1	billion	in	2000	from	$992	million	in	1999.	Excluding	businesses	acquired	in	2000	or	1999,	large utilities	revenues	increased	2%	to	$892	million	in	2000.	The	increase	in	large	utility	segment	revenues	occurred	in	North	America	and	the	Caribbean.	North	America large	utility	segment	revenues	increased	$628	million	due	to	CILCORP	contributing	a	full	year	of	revenues	in	2000.	The	acquisition	of	EDC	in	Venezuela	contributed entirely	to	the	$494	million	increase	in	Caribbean	revenues.

								Growth	distribution	revenues	increased	$352	million,	or	37%,	to	$1.3	billion	in	2000	from	$948	million	in	1999.	Excluding	businesses	acquired	in	2000	or	1999, growth	distribution	revenues	increased	5%	to	$889	million	in	2000.	The	increase	in	growth	distribution	segment	revenues	occurred	within	South	America,	the	Caribbean and	Asia.	In	South	America,	growth	distribution	revenues	increased	$51	million	due	primarily	to	increased	revenues	from	Sul	caused	by	improved	economic	conditions in	Brazil.	In	the	Caribbean,	growth	distribution	revenues	increased	$189	million	due	primarily	to	the	acquisition	of	EDE	Este	and	CESCO	in	1999	and	CAESS	in	2000.

								The	breakdown	of	AES's	revenues	for	the	years	ended	December	31,	2000	and	1999,	based	on	the	geographic	region	in	which	they	were	earned,	is	set	forth	below.

|  | 2000 | 1999 | %	change |
| :--- | :--- | :--- | :--- |
| North\tAmerica | $\t3.4\tbillion | $\t2.1\tbillion | 62% |
| South\tAmerica | $\t1.1\tbillion | $827\tmillion | 33% |
| Caribbean* | $\t1.1\tbillion | $312\tmillion | 253% |
| Europe/Africa | $\t1.3\tbillion | $421\tmillion | 209% |
| Asia | $615\tmillion | $499\tmillion | 23% |

								Gross	margin,	which	represents	total	revenues	reduced	by	cost	of	sales,	increased	$700	million,	or	54%,	to	$2.0	billion	in	2000	from	$1.3	billion	in	1999.	Gross margin	as	a	percentage	of	revenues	decreased	to	26%	in	2000	from	31%	in	1999.	The	decrease	in	gross	margin	as	a	percentage	of	revenues	is	primarily	due	to	the decrease	in	the	competitive	supply	and	growth	distribution	gross	margin.	Excluding	businesses	acquired	or	that	commenced	commercial	operations	in	2000	or	1999, gross	margin	decreased	2%	to	$1.1	billion	in	2000.

|  | 2000 | 1999 | %	Change |
| :--- | :--- | :--- | :--- |
| Contract\tgeneration | $767\tmillion | $552\tmillion | 39% |
| Competitive\tsupply | $559\tmillion | $244\tmillion | 129% |
| Large\tutilities | $538\tmillion | $282\tmillion | 91% |
| Growth\tdistribution | $131\tmillion | $185\tmillion | (29%) |

								The	contract	generation	gross	margin	increased	$215	million,	or	39%,	to	$767	million	in	2000	from	$552	million	in	1999.	Excluding	businesses	acquired	or	that commenced	commercial	operations	in	2000	or	1999,	contract	generation	gross	margin	decreased	3%	to	$509	million	in	2000.	The	increase	in	contract	generation	gross margin	was	primarily	due	to	increases	in	South	America	and	North	America.	Slight	increases	in	the	Caribbean	and	Asia	were	offset	by	slight	decreases	in	Europe/Africa. The	contract	generation	gross	margin	as	a	percentage	of	revenues	increased	to	44%	in	2000	from	42%	in	1999.	In	South	America,	contract	generation	gross	margin increased	$168	million	and	was	66%	of	revenues.	The	increase	is	primarily	due	to	the	acquisition	of	Tiete.	In	North	America,	contract

generation	increased	$47	million	and	was	52%	of	revenues.	The	increase	is	due	primarily	to	the	start	of	commercial	operations	at	Warrior	Run.	The	overall	increase	in gross	margin	as	a	percentage	of	revenues	is	due	primarily	to	slightly	better	gross	margin	percentages	from	businesses	acquired	than	the	core	portfolio	of	businesses.	As	a percentage	of	revenues,	contract	generation	gross	margin	increased	in	South	America,	remained	relatively	flat	in	North	America	and	Europe/Africa	and	decreased slightly	in	Asia.

								The	competitive	supply	gross	margin	increased	$315	million,	or	129%,	to	$559	million	in	2000	from	$244	million	in	1999.	Excluding	businesses	acquired	or	that commenced	commercial	operations	in	2000	or	1999,	competitive	supply	gross	margin	increased	14%	to	$177	million	in	2000.	The	increase	in	competitive	supply	gross margin	was	due	primarily	to	increases	in	North	America	and	Europe/Africa.	Slight	increases	in	South	America	and	the	Caribbean	were	offset	by	slight	declines	in	Asia. The	competitive	supply	gross	margin	as	a	percentage	of	revenues	decreased	to	23%	in	2000	from	28%	in	1999.	In	North	America,	competitive	supply	gross	margin increased	$71	million	and	was	12%	of	revenues.	The	increase	is	due	to	a	full	year	of	contribution	by	the	New	York	plants.	In	Europe/Africa,	competitive	supply	gross margin	increased	$243	million	and	was	30%	of	revenues.	The	increase	was	due	primarily	to	the	contribution	of	a	full	year	by	Drax.	The	overall	increase	in	gross	margin is	due	primarily	to	businesses	acquired	during	1999,	which	contributed	a	full	year	of	operations	in	2000.	The	overall	decline	in	gross	margin	as	a	percentage	of	revenues is	due	to	lower	gross	margins	experienced	at	Drax,	Panama,	Ekibastuz	and	Altai.	As	a	percentage	of	revenues,	competitive	supply	gross	margin	increased	in	South America,	remained	flat	in	North	America	and	decreased	in	Europe/Africa,	the	Caribbean	and	Asia.

								Large	utilities	gross	margin	increased	$256	million,	or	91%,	to	$538	million	in	2000	from	$282	million	in	1999.	Excluding	businesses	acquired	in	2000	or	1999, large	utilities	gross	margin	decreased	2%	to	$262	million	in	2000.	The	increase	in	large	utilities	gross	margin	was	due	to	increases	in	North	America	and	the	Caribbean. The	large	utilities	gross	margin	as	a	percentage	of	revenues	decreased	to	25%	in	2000	from	28%	in	1999.	In	North	America,	large	utilities	gross	margin	increased	$78 million	and	was	22%	of	revenues.	The	increase	is	due	to	a	full	year	of	contribution	from	CILCORP.	As	a	percentage	of	revenues,	large	utilities	gross	margin	decreased in	North	America.	The	acquisition	of	EDC	in	the	Caribbean	contributed	entirely	to	the	$177	million	increase,	which	was	36%	of	revenues.

								Growth	distribution	gross	margin	decreased	$54	million,	or	29%,	to	$131	million	in	2000	from	$185	million	in	1999.	Excluding	businesses	acquired	in	2000	or 1999,	growth	distribution	gross	margin	decreased	10%	to	$172	million	in	2000.	The	decrease	in	growth	distribution	gross	margin	was	due	to	decreases	in	South	America, the	Caribbean	and	Asia.	The	growth	distribution	gross	margin	as	a	percentage	of	revenues	decreased	to	10%	in	2000	from	20%	in	1999.	In	South	America,	growth distribution	gross	margin	decreased	$10	million	and	was	22%	of	revenues.	Increases	from	Sul	were	offset	by	declines	from	Eden/Edes	and	Edelap	in	Argentina.	In	the Caribbean,	growth	distribution	gross	margin	decreased	$31	million	and	was	(2%)	of	revenues.	The	decrease	was	due	to	the	inclusion	of	a	full	year	of	losses	from	EDE Este.	As	a	percentage	of	revenues,	growth	distribution	gross	margin	decreased	in	South	America	and	the	Caribbean	and	remained	flat	in	Asia.

								The	breakdown	of	AES's	gross	margin	for	the	years	ended	December	31,	2000	and	1999,	based	on	the	geographic	region	in	which	they	were	earned,	is	set	forth below.

|  | 2000 | %	of	Revenue | 1999 | %	of	Revenue | %	change |
| :--- | :--- | :--- | :--- | :--- | :--- |
| North\tAmerica | $844\tmillion | 25% | $649\tmillion | 32% | 30% |
| South\tAmerica | $416\tmillion | 36% | $232\tmillion | 28% | 79% |
| Caribbean* | $226\tmillion | 21% | $75\tmillion | 24% | 201% |
| Europe/Africa | $371\tmillion | 29% | $124\tmillion | 29% | 199% |
| Asia | $138\tmillion | 22% | $183\tmillion | 37% | (26%) |

								Selling,	general	and	administrative	expenses	increased	$11	million,	or	15%,	to	$82	million	in	2000	from	$71	million	in	1999.	Selling,	general	and	administrative expenses	as	a	percentage	of	revenues	remained	constant	at	1%	in	both	2000	and	1999.	The	increase	is	due	to	an	increase	in	business	development	activities.

								Net	interest	expense	increased	$506	million,	or	80%,	to	$1.1	billion	in	2000	from	$632	million	in	1999.	Interest	expense	as	a	percentage	of	revenues	remained constant	at	15%	in	both	2000	and	1999.	Interest	expense	increased	primarily	due	to	the	interest	at	new	businesses,	including	Drax,	Tiete,	CILCORP	and	EDC,	as	well	as additional	corporate	interest	costs	resulting	from	the	senior	debt	and	convertible	securities	issued	within	the	past	two	years.

								Other	income	increased	$16	million,	or	107%,	to	$31	million	in	2000	from	$15	million	in	1999.	Other	income	includes	foreign	currency	transaction	gains	and losses	as	well	as	other	non-operating	income.	The	increase	in	other	income	is	due	primarily	to	a	favorable	legal	judgment	and	the	sale	of	development	projects.

								During	the	fourth	quarter	of	2000,	the	Company	incurred	approximately	$79	million	of	transaction	and	contractual	severance	costs	related	to	the	acquisition	of IPALCO.

								During	2000,	IPALCO	sold	certain	assets	("Thermal	Assets")	for	approximately	$162	million.	The	transaction	resulted	in	a	gain	to	the	Company	of	approximately $31	million.	Of	the	net	proceeds,	$88	million	was	used	to	retire	debt	specifically	assignable	to	the	Thermal	Assets.	During	1999,	the	Company	recorded	a	$29	million gain	(before	extraordinary	loss)	from	the	buyout	of	its	long-term	power	sales	agreement	at	Placerita.	The	Company	received	gross	proceeds	of	$110	million	which	were offset	by	transaction	related	costs	of	$19	million	and	an	impairment	loss	of	$62	million	to	reduce	the	carrying	value	of	the	electric	generation	assets	to	their	estimated fair	value	after	termination	of	the	contract.	The	estimated	fair	value	was	determined	by	an	independent	appraisal.	Concurrent	with	the	buyout	of	the	power	sales

agreement,	the	Company	repaid	the	related	non-recourse	debt	prior	to	its	scheduled	maturity	and	recorded	an	extraordinary	loss	of	$11	million,	net	of	income	taxes.

								During	2000,	a	subsidiary	of	the	Company	sold	approximately	one	million	shares	of	Internet	Capital	Group,	Inc.	resulting	in	a	realized	gain	of	approximately	$112 million.	There	were	no	similar	transactions	during	1999.

								The	Company	recorded	a	$17	million	environmental	fine	in	2000	related	to	excess	nitrogen	oxide	in	air	emissions	at	certain	of	its	generating	facilities	in	California. As	a	result	of	the	shortage	of	electricity	in	California	in	2000,	our	generating	facilities	in	California	operated	at	higher	than	expected	capacity	factors.	The	Company	does not	intend	to	operate	its	facilities	in	California	unless	it	has	sufficient	nitrogen	oxide	air	emission	credits	or	allocations.

								Equity	in	pre-tax	earnings	of	affiliates	(before	income	taxes)	increased	$446	million	to	$475	million	in	2000	from	$29	million	in	1999.	Equity	in	earnings	of affiliates	includes	foreign	currency	transaction	losses	of	$64	million	and	$203	million	in	2000	and	1999,	respectively.	The	increase	in	equity	in	earnings	of	affiliates resulted	from	the	increase	in	equity	in	earnings	of	large	utility	investments	offset	by	a	slight	decrease	in	equity	in	earnings	of	competitive	generation	investments.

								The	Company	did	not	have	any	equity	in	earnings	from	competitive	supply	or	growth	distribution	investments	during	2000	or	1999.

								Equity	in	earnings	of	contract	generation	affiliates	decreased	$11	million,	or	18%,	to	$49	million	in	2000	from	$60	million	in	1999.	The	decrease	in	equity	in earnings	is	due	to	the	acquisition	of	a	controlling	interest	in	Kilroot	during	2000	thereby	causing	it	to	become	consolidated	during	the	year	and	declining	its	equity	in earnings	contribution.

								Equity	in	earnings	of	large	utilities	increased	$457	million	to	$426	million	in	2000	from	($31)	million	in	1999.	The	significant	increase	in	equity	in	earnings	is	due to	an	additional	ownership	interest	in	Eletropaulo,	as	well	as	improved	economic	conditions	in	Brazil,	which	resulted	in	much	greater	contribution	from	Eletropaulo	and CEMIG.	Foreign	currency	transaction	losses	decreased	$139	million	to	$64	million	in	2000	at	our	large	utility	affiliates	in	Brazil.

								Income	taxes	(including	income	taxes	on	equity	in	earnings	and	minority	interest)	increased	$186	million	to	$377	million	in	2000	from	$191	million	in	1999.	The Company's	effective	tax	rate	decreased	to	31%	in	2000	from	34%	in	1999	due	to	an	increase	in	earnings	of	certain	foreign	businesses	which	are	taxed	at	a	lower	rate than	the	U.S.	income	tax	rate.

								Minority	interest	(before	income	taxes)	increased	$59	million,	or	92%,	to	$124	million	in	2000	from	$64	million	in	1999.	The	increase	in	minority	interest	is	due	to increases	in	all	segments	except	growth	distribution,	which	had	a	decline	from	1999.

								Contract	generation	minority	interest	increased	$20	million,	or	125%,	to	$36	million	in	2000	from	$16	million	in	1999.	The	increase	in	minority	interest	is	due	to increased	contributions	from	Tiete.

								Competitive	supply	minority	interest	increased	$11	million,	or	42%,	to	$37	million	in	2000	from	$26	million	in	1999.	The	increase	in	minority	interest	is	due	to increased	contributions	from	generation	businesses	in	South	America.

								Large	utilities	minority	interest	increased	$88	million	to	$85	million	in	2000	from	a	loss	of	$3	million	in	1999.	The	overall	increase	is	due	to	increased	contributions from	EDC	and	CEMIG.

								Growth	distribution	minority	interest	decreased	$60	million	to	a	loss	of	$31	million	in	2000	from	$25	million	in	1999.	The	overall	decrease	is	due	to	lower contributions	from	EDE	Este	and	CESCO.

								During	2001,	the	Company	discontinued	certain	of	its	operations,	including	Power	Direct,	Power	Northern,	Geoutilities	and	several	telecommunications	businesses in	the	United	States	and	Brazil.	Therefore,	the	results	of	operations	from	these	businesses	have	been	reclassified	to	discontinued	operations.	The	Company	recorded $21	million	and	$3	million	in	2000	and	1999,	respectively,	net	of	tax,	of	net	losses	from	these	businesses.

								On	March	31,	2000,	the	Company	replaced	its	corporate	revolving	bank	loan	with	a	new	facility	that	would	incorporate	the	letter	of	credit	facility.	As	a	result,	the Company	wrote-off	the	unamortized	deferred	financing	costs	related	to	the	refinanced	revolver	resulting	in	an	extraordinary	item	for	the	early	extinguishment	of	debt	of $7	million	net	in	tax.	In	November	2000,	a	subsidiary	of	the	Company	sold	its	Thermal	Assets	to	Citizen	Gas	&	Coke	Utility.	A	portion	of	the	proceeds	was	used	to retire	debt	specifically	assignable	to	the	assets.	In	connection	with	the	retirement	of	the	debt,	the	subsidiary	wrote-off	debt	issuance	costs	of	$4	million,	which	resulted	in an	extraordinary	loss	for	the	early	retirement	of	debt.	In	1999,	the	Company	recorded	a	$17	million	loss,	net	of	income	taxes	from	the	early	extinguishment	of	recourse debt	and	non-recourse	debt	at	Placerita.

								Net	income	increased	$438	million,	or	123%,	to	$795	million	in	2000	from	$357	million	in	1999.	The	increase	in	net	income	is	due	to	increases	in	all	segments except	growth	distribution.	The	businesses	contributing	the	most	include	the	New	York	plants,	Drax,	Tiete,	EDC,	Eletropaulo	and	CEMIG.	Net	income	was	also positively	impacted	by	non-recurring	gains	from	the	sale	of	assets	and	investments	of	$143	million	offset	by	expenses	from	severance	and	transaction	costs	of	$79 million	from	the	IPALCO	pooling-of-interests	transaction	and	an	environmental	fine	of	$17	million.

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,	2001,	AES	had	$5.4	billion	of	recourse	debt	and	$16.9	billion	of	non- recourse	debt	outstanding.	For	more	information	on	AES's	long	term	debt	see	Note	6	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.

								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.	For	example,	AES	has	provided	an	aggregate	of	approximately	$260	million	of guarantees	to	entities	that	supply	power	to	AES	New	Energy.	AES	cannot	provide	assurance	that	it	will	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,	2001,	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	$775	million	(excluding	those	collateralized	by	letter-of-credit 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	$50	million	as	of	December	31,	2001.	In	addition,	the	Company	has	commitments	to	fund	its equity	in	projects	currently	under	development	or	in	construction.	At	December	31,	2001,	such	commitments	to	invest	amounted	to	approximately	$207	million (excluding	those	collateralized	by	letter-of-credit	obligations).

								At	December	31,	2001,	the	Company	had	$453	million	in	letters	of	credit	outstanding,	which	operate	to	guarantee	performance	relating	to	certain	project development	activities	and	subsidiary	operations.	The	Company	pays	a	letter-of-credit	fee	ranging	from	0.50%	to	2.0%	per	annum	on	the	outstanding	amounts.	In addition,	the	Company	had	$76	million	and	a	subsidiary	of	the	Company	had	$271	million	in	surety	bonds	outstanding	at	December	31,	2001.

# Project	level	defaults

								While	the	lenders	under	AES's	non-recourse	project	financings	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	and	trust	preferred	instruments.	For	example,	the	parent's	revolving	credit	agreement	and	outstanding senior	notes,	senior	subordinated	notes,	junior	subordinated	notes	and	trust	preferred	securities	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,	2001,	a	number	of	the	Company's	subsidiaries	were	in	default	under	their	outstanding	project	indebtedness	as	of	December	31,	2001,	including Chivor	in	Colombia	and	Edelap,	Eden/Edes	and	Parana	in	Argentina.	Because	none	of	these	businesses	are	material	subsidiaries,	none	of	these	defaults	are	expected	to have	a	material	adverse	effect	on	the	Company's	results	of	operations	or	financial	condition.	All	of	the	related	loans	have	been	recorded	in	current	non-recourse	debt	in the	accompanying	consolidated	balance	sheets.	Because	of	the	current	political,	social	and	economic	crisis	in	Argentina,	the	Company's	Argentine	businesses	are experiencing	significant	cash	flow	shortfalls.	AES	may	be	required	to	record	a	material	impairment	or	loss	or	write-off	associated	with	the	recorded	carrying	values	of its	Argentine	businesses	in	2002.

								In	addition,	subsequent	to	year	end,	AES	Drax	had	an	event	of	default	under	its	1.3	billion	pound	sterling	bank	facility	as	a	result	of	its	inability	to	obtain	specified minimum	amounts	of	insurance	coverage.	While	the	lenders	under	this	facility	have	not	exercised	their	right	to	accelerate	the	maturity	of	the	loans	thereunder,	they	have refused	to	waive	the	prohibition	on	the	payment	of	any	dividends	by	AES	Drax	and	its	subsidiaries	during	the	pendancy	of	the	default.	Accordingly,	AES	Drax	has	had to	use	its	debt	service	reserve	accounts	to	service	a	portion	of	its	outstanding	subordinated	public	debt	at	the	holding	company	and	has	been	unable,	and	will	for	at	least the	next	six	months	be	unable,	to	pay	dividends	to	AES.

								On	March	21,	2002,	Fifoots	was	placed	in	administrative	receivership	by	its	lenders.	Fifoots	defaulted	on	its	debt	after	electricity	prices	in	the	U.K.	fell	below	its marginal	costs.	AES	expects	to	write-off	its	investment	of	approximately	$36	million	in	Fifoots	during	the	first	quarter	of	2002.

# Parent	company	liquidity

								Because	of	the	non-recourse	nature	of	most	of	AES's	indebtedness,	AES	believes	that	unconsolidated	parent	company	liquidity	is	more	important	than	the	liquidity position	of	AES	and	its	consolidated	subsidiaries	as	presented	on	a	consolidated	basis.

								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	2002	are	primarily	to	fund:

•Construction	commitments

•Other	equity	commitments

•Interest	and	preferred	dividends

•Principal	repayments	of	long-term	debt

•Taxes,	and

•Parent	company	overhead.

								While	AES	believes	that	its	sources	of	liquidity	will	be	adequate	to	meet	its	needs	through	the	end	of	2002,	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) | $488\tmillion | $845\tmillion | $\t4.1\tbillion | $\t5.4\tbillion |
| Trust\tpreferred\tsecurities\t(excluding\tdividends) | — | — | $978\tmillion | $978\tmillion |
| Construction\tcommitments | $156\tmillion | $\t\t41\tmillion | $\t\t\t\t7\tmillion | $204\tmillion |
| Other\tequity\tcommitments | $\t\t.5\tmillion | $\t\t\t\t1\tmillion | $\t1.5\tmillion | $\t\t\t\t3\tmillion |
| Total | $645\tmillion | $887\tmillion | $\t5.1\tbillion | $\t6.6\tbillion |

								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 | On	Balance<br>Sheet | Off	Balance<br>Sheet |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Guarantees | $775 | 68 | &lt;$1–$100 | $249 | $526 |
| Letters\tof\tcredit\t–\tunder\tthe\tRevolver | $285 | 24 | &lt;$1–$104 | $155 | $130 |
| Letters\tof\tcredit\t–\toutside\tthe\tRevolver | $168 | 12 | &lt;$1–$107 | $107 | $61 |
| Surety\tbonds | $76 | 15 | &lt;$1–$42 | — | $76 |

								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	2002,	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	AES's	revolving	credit	facility	(the "Revolver").	The	Company	currently	maintains	an	$850	million	credit	line	under	the	Revolver.	The	Revolver	and	other	borrowings	contain	certain	restrictive	covenants. The	covenants	provide	for,	among	other	items,	maintenance	of	certain	reserves,	and	require	that	minimum	levels	of	working	capital,	net	worth,	and	certain	financial ratio	tests	are	met.	The	most	restrictive	of	these	covenants	include	limitations	on	incurring	additional	debt	and	on	the	payment	of	dividends	to	stockholders.	At December	31,	2001,	cash	borrowings	and	letters	of	credit	outstanding	under	the	Revolver	amounted	to	$70	million	and	$285	million,	respectively.	Letters	of	credit outstanding	outside	the	Revolver	amounted	to	$168	million.	The	Company	may	also	seek,	from	time	to	time,	to	meet	some	of	its	short-term	and	interim	funding	needs with	additional	commitments	from	banks	and	other	financial	institutions	at	the	parent	or	subsidiary	level.

								The	Company	has	secured	equity-linked	loans	("SELLS")	of	$350	million	due	in	2003	and	$300	million	due	in	2004.	The	Company	is	required	to	maintain	as collateral	2.25	times	the	amount	of	the	SELLS	in	the	form	of	unregistered	shares.	Registration	of	the	shares	can	only	occur	in	the	event	of

nonpayment	or	failure	to	maintain	adequate	collateral	levels.	As	of	December	31,	2001	and	2000,	approximately	111	million	and	81	million	shares	of	the	Company's common	stock,	respectively,	had	been	issued	to	the	consolidated	subsidiaries.	These	shares	are	not	considered	outstanding	and	therefore	have	been	excluded	from	the calculation	of	earnings	per	share.

FINANCIAL	POSITION	AND	CASH	FLOWS

# Consolidated	cash	flows

								At	December	31,	2001,	AES	had	a	consolidated	net	working	capital	deficit	of	($388)	million	as	compared	to	positive	working	capital	of	$745	million	at	the	end	of 2000.	Cash	and	short-term	investments	were	$1.4	billion	at	December	31,	2001.	Included	in	the	net	working	capital	is	approximately	$2.7	billion	from	the	current portion	of	long-term	debt.	The	Company	intends	to	repay	approximately	$1.0	billion	of	the	current	debt	during	2002,	which	includes	$488	million	of	recourse	debt,	and the	remainder	is	expected	to	be	refinanced.	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.	The	decrease	in	net	working capital	was	due	primarily	to	an	increase	in	the	current	portion	of	debt	and	a	decline	in	short-term	investments.	Short-term	investments	decreased	due	to	the	payment	in 2001	of	$848	million	for	the	Gener	acquisition	that	was	classified	as	short-term	investments	at	December	31,	2000.

								Property,	plant	and	equipment,	net	of	accumulated	depreciation,	accounts	for	64%	of	the	Company's	total	assets	and	was	$23.4	billion	at	December	31,	2001.	Net property,	plant	and	equipment	increased	$4.2	billion,	or	22%,	during	2001.	The	increase	was	due	primarily	to	construction	activities	at	the	Company's	greenfield projects.	Acquisitions	of	new	businesses	contributed	to	a	lesser	extent.

								In	total,	the	Company's	consolidated	debt	increased	$3.6	billion,	or	20%,	to	$22.3	billion	at	December	31,	2001.	The	increase	is	due	primarily	to	borrowings	used	to fund	the	construction	of	the	Company's	greenfield	projects	and	borrowings	used	to	refinance	the	redeemable	preferred	trust,	commonly	called	RHINOS.	Borrowings used	to	fund	acquisitions	contributed	to	a	lesser	extent.

								At	December	31,	2001,	the	Company	had	$922	million	of	cash	and	cash	equivalents.	Cash	and	cash	equivalents	decreased	$28	million.	The	$1.7	billion	provided	by operating	activities	and	the	$1.6	billion	of	cash	raised	by	financing	activities	was	used	to	fund	the	$3.3	billion	of	investing	activities.

								Cash	flows	provided	by	operating	activities	totaled	$1.7	billion	during	2001.	The	increase	in	cash	provided	by	operating	activities	during	2001	is	due	to	the collection	of	the	Thames	contract	prepayment	and	enhanced	collections	of	accounts	receivable	at	Los	Mina,	Ekibastuz,	Altai	and	Telasi.	Net	cash	used	in	investing activities	totaled	$3.3	billion	during	2001.	The	cash	used	in	investing	activities	includes	$1.4	billion	for	acquisitions	and	$3.2	billion	for	property	additions,	primarily new	greenfield	construction	efforts.	Net	cash	provided	by	financing	activities	was	$1.6	billion	during	2001.	The	cash	provided	by	financing	activities	includes	$1.7 billion	provided	by	net	borrowings.

# Parent	operating	cash	flow

								The	following	discussion	of	"parent	operating	cash	flow",	formerly	described	by	AES	as	"parent	EBITDA",	has	been	included	because	AES	believes	it	is	a	useful measure	of	the	cash	flow	available	to	the	parent	company	to	meet	its	liquidity	needs.	Parent	operating	cash	flow	is	not	a	measure	under	generally	accepted	accounting principles	("GAAP")	and	should	not	be	construed	as	an	alternative	to	net	income	or	cash	flows	from	operating	activities,	which	are	determined	in	accordance	with GAAP,	as	an	indicator	of	operating	performance	or	as	a	measure	of	liquidity.	Parent	operating	cash	flow	may	differ	from	that,	or	similarly	titled	measures,	used	by	other companies.

								Parent	operating	cash	flow	includes	the	following	amounts	received	in	cash	by	the	parent	and	qualifying	holding	companies	from	operating	subsidiaries	and affiliates	less	parent	operating	expenses:

•Dividends

•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.

								Parent	operating	cash	flow	does	not	include	the	following	additional	cash	payments	made	to	the	parent	company	by	its	subsidiaries	and	affiliates:

•Returns	of	invested	capital

•Repayments	of	debt	principal

•Payments	released	from	debt	service	reserve	accounts	upon	the	issuance	of	letters	of	credit	for	the	benefit	of	subsidiaries	or	affiliates.

								Parent	interest	charges	include	all	interest	payments	incurred	by	the	parent,	whether	or	not	they	are	expensed	or	capitalized.	Such	charges	exclude	the	distributions on	convertible	trust	preferred	securities.

								Parent	operating	cash	flows	for	2001	amounted	to	approximately	$1.2	billion.	This	compares	to	$871	million	for	2000.	Cash	payments	for	parent	interest	charges,	as defined,	rose	to	$391	million	in	2001	from	$216	million	in	2000.	Resultant	parent	interest	coverage	ratios	for	the	same	periods	were	2.97x	and	4.03x,	respectively.

								The	2001	increase	of	approximately	$292	million	in	parent	operating	cash	flows	was	a	33%	increase	from	2000.	The	increase	was	driven	primarily	by	the contributions	from	new	businesses	added	through	both	acquisitions	and	newly	operational	greenfield	projects.	This	included	increased	contributions	from	IPALCO; Eastern	Energy,	our	coal-fired	base	load	plants	in	New	York;	and	Gener,	purchased	at	the	beginning	of	2001.	These	increases	were	offset	in	part	by	reduced	cash	flows from	some	of	our	existing	businesses,	primarily	decreases	in	contributions	from	Brazil,	caused	by	rationing.

								Approximately	72%	of	2001	parent	operating	cash	flows	were	from	investment	grade	countries	compared	with	approximately	56%	in	2000	and	80%	in	1999.

								The	reconciliation	between	parent	operating	cash	flow	and	the	net	cash	provided	by	operating	activities	on	the	unconsolidated	cash	flows	included	in	Schedule	I	is presented	below	(in	millions).

| Parent	operating	cash	flow | $1,163 |
| :--- | :--- |
| Less: |  |
| Cash\theld\tat\tqualifying\tholding\tcompanies | (125) |
| Net\tcash\tprovided\tby\toperating\tcash\tflows | $1,038 |

								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.

								At	year	end	we	had	approximately	$70	million	of	cash,	$496	million	of	availability	under	our	$850	million	revolver,	and	approximately	$900	million	of	additional debt	capacity	at	the	parent	company	under	the	revolver	loan	covenants.

# 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,	2001,	our	average	daily	VaR	for	interest	rate-sensitive	instruments	was	$73.1	million.	The	daily	VaR	for	interest	rate-sensitive instruments	was	highest	at	year-end,	and	equaled	$97.5	million.	The	daily	VaR	for	interest	rate-sensitive	instruments	was	lowest	at	the	end	of	the	first	quarter,	and equaled	$59.8	million.	The	daily	VaR	for	interest	rate-sensitive	instruments	as	of	December	31,	2000	was	$40.3	million.	These	amounts	include	the	financial	instruments that	serve	as	hedges	and	the	underlying	hedged	items.	VaR	for	interest	rate-sensitive	instruments	increased	in	2001	as	compared	with	2000	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,	2001,	our	average	daily	VaR	for	foreign	exchange	rate-sensitive	instruments	was	$3.4	million.	The	daily	VaR	for foreign	exchange	rate-sensitive	instruments	was	highest	at	the	end	of	the	third	quarter,	and	equaled	$6.0	million.	The	daily	VaR	for	foreign	exchange	rate-sensitive instruments	was	lowest	at	the	end	of	the	first	quarter,	and	equaled	$0.7	million.	The	daily	VaR	for	foreign	exchange	rate-sensitive	instruments	as	of	December	31,	2000 was	$4.9	million.	These	amounts	include	the	financial	instruments	that	serve	as	hedges	and	the	underlying	hedged	items.	During	the	year	ended	December	31,	2001,	our average	daily	VaR	for	commodity	price-sensitive	instruments	was	$6.2	million.	The	daily	VaR	for	commodity	price-sensitive	instruments	was	highest	at	the	end	of	the second	quarter,	and	equaled	$7.1	million.	The	daily	VaR	for	commodity	price-sensitive	instruments	was	lowest	at	year-end,	and	equaled	$5.5	million.	The	daily	VaR	for commodity	price-sensitive	instruments	as	of	December	31,	2000	was	$5.5	million.	These	amounts	include	the	financial	instruments	that	serve	as	hedges	and	do	not include	the	underlying	physical	assets.

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,	2001	and	2000,	and	the related	consolidated	statements	of	operations,	changes	in	stockholders'	equity,	and	cash	flows	for	each	of	the	three	years	in	the	period	ended	December	31,	2001.	Our audits	also	included	the	financial	statement	schedules	listed	in	the	index	on	page	S-1.	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.	The consolidated	financial	statements	and	financial	statement	schedules	give	retroactive	effect	to	the	merger	of	The	AES	Corporation	and	IPALCO	Enterprises,	Inc.,	which has	been	accounted	for	as	a	pooling	of	interests	as	described	in	Note	2	to	the	consolidated	financial	statements.	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,	which	statements	reflect	total	assets	constituting	9% and	10%	of	consolidated	total	assets	as	of	December	31,	2001	and	2000,	total	revenues	constituting	9%	and	7%	of	consolidated	total	revenues	and	total	income	from continuing	operations	constituting	47%	and	14%	of	consolidated	income	from	continuing	operations	for	2001	and	2000.	Those	statements	were	audited	by	other	auditors 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,	2001	and	2000,	and	the	results	of	their	operations	and	their	cash	flows	for	each	of	the	three	years in	the	period	ended	December	31,	2001	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	3	to	the	financial	statements,	the	Company	changed	its	method	of	accounting	for	the	impairment	or	disposal	of	long-lived	assets	effective	January 1,	2001	to	conform	with	Statement	of	Financial	Accounting	Standards	No.	144.	Also,	as	discussed	in	Note	7	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.

# Deloitte	&	Touche	LLP

# McLean,	VA

# 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,	2001	AND	2000

| Cash	and	cash	equivalents | $922 | $950 |
| :--- | :--- | :--- |
| Short-term\tinvestments-including\trestricted\tcash\tof\t$357-2001;\t$1,189-2000 | 588 | 1,297 |
| Accounts\treceivable\t–\tnet\tof\treserves\tof\t$251-2001;\t$203\t-2000 | 1,588 | 1,539 |
| Inventory | 626 | 569 |
| Receivable\tfrom\taffiliates | 10 | 27 |
| Deferred\tincome\ttaxes | 260 | 167 |
| Prepaid\texpenses\tand\tother\tcurrent\tassets | 607 | 1,193 |
| Current\tassets\tof\tdiscontinued\toperations | 52 | 42 |
| Total\tcurrent\tassets | 4,653 | 5,784 |
| Property,\tPlant\tand\tEquipment: |  |  |
| Land | 599 | 656 |
| Electric\tgeneration\tand\tdistribution\tassets | 21,406 | 18,357 |
| Accumulated\tdepreciation\tand\tamortization | (3,314) | (2,632) |
| Construction\tin\tprogress | 4,743 | 2,861 |
| Property,\tplant,\tand\tequipment\t–\tnet | 23,434 | 19,242 |
| Other\tAssets: |  |  |
| Deferred\tfinancing\tcosts\t–\tnet | 482 | 381 |
| Project\tdevelopment\tcosts | 68 | 67 |
| Investments\tin\tand\tadvances\tto\taffiliates | 3,100 | 3,122 |
| Debt\tservice\treserves\tand\tother\tdeposits | 474 | 509 |
| Goodwill\t–\tnet | 3,208 | 2,181 |
| Long-term\tassets\tof\tdiscontinued\toperations | 249 | 457 |
| Other\tassets | 1,068 | 1,295 |
| Total\tother\tassets | 8,649 | 8,012 |
| Total | $36,736 | $33,038 |
| LIABILITIES\tAND\tSTOCKHOLDERS'\tEQUITY |  |  |
| Current\tLiabilities: |  |  |
| Accounts\tpayable | $819 | $743 |
| Accrued\tinterest | 283 | 409 |
| Accrued\tand\tother\tliabilities | 1,185 | 1,293 |
| Current\tliabilities\tof\tdiscontinued\toperations | 82 | 132 |
| Recourse\tdebt\t–\tcurrent\tportion | 488 | — |
| Non-recourse\tdebt\t–\tcurrent\tportion | 2,184 | 2,462 |
| Total\tcurrent\tliabilities | 5,041 | 5,039 |
| Long-Term\tLiabilities: |  |  |
| Non-recourse\tdebt | 14,673 | 12,696 |
| Recourse\tdebt | 4,913 | 3,458 |
| Deferred\tincome\ttaxes | 1,904 | 1,863 |
| Long-term\tliabilities\tof\tdiscontinued\toperations | 154 | 184 |
| Other\tlong-term\tliabilities | 2,004 | 1,586 |
| Total\tlong-term\tliabilities | 23,648 | 19,787 |
| Minority\tInterest | 1,530 | 1,442 |
| Commitments\tand\tContingencies\t(Note\t8) | — | — |
| Company-Obligated\tConvertible\tMandatorily\tRedeemable\tPreferred\tSecurities\tof\tSubsidiary\tTrusts\tHolding\tSolely\tJunior |  |  |
| Subordinated\tDebentures\tof\tAES | 978 | 1,228 |
| Stockholders'\tEquity: |  |  |
| Preferred\tstock,\tno\tpar\tvalue\t–\t50\tmillion\tshares\tauthorized;\tnone\tissued | — | — |
| million\toutstanding\tin\t2001,\t603\tmillion\tissued\tand\t522\tmillion\toutstanding\tin\t2000 | 5 | 5 |
| Additional\tpaid-in\tcapital | 5,225 | 5,172 |
| Retained\tearnings | 2,809 | 2,551 |
| Accumulated\tother\tcomprehensive\tloss | (2,500) | (1,679) |
| Treasury\tStock,\tat\tcost:\t2000\t-13\tmillion\tshares | — | (507) |
| Total\tstockholders'\tequity | 5,539 | 5,542 |
| Total | $36,736 | $33,038 |

See	notes	to	consolidated	financial	statements.

# CONSOLIDATED	STATEMENTS	OF	OPERATIONS

| Revenues | $9,327 | $7,534 | $4,117 |
| :--- | :--- | :--- | :--- |
| Cost\tof\tSales | (7,025) | (5,539) | (2,854) |
| Selling,\tGeneral\tand\tAdministrative\tExpenses | (120) | (82) | (71) |
| Severance\tand\tTransaction\tCosts | (131) | (79) | — |
| Interest\tExpense,\tnet | (1,465) | (1,138) | (632) |
| Other\tIncome,\tnet | 23 | 31 | 15 |
| Gain\ton\tSale\tof\tAssets | — | 31 | 91 |
| Gain\ton\tSale\tof\tAvailable\tfor\tSale\tSecurities | 18 | 112 | — |
| Impairment\tLoss | — | — | (62) |
| Environmental\tFine | — | (17) | — |
| Equity\tin\tPre-tax\tEarnings\tof\tAffiliates | 175 | 475 | 29 |
| INCOME\tBEFORE\tINCOME\tTAXES\tAND\tMINORITY\nINTEREST | 802 | 1,328 | 633 |
| Income\tTaxes | 230 | 377 | 191 |
| Minority\tInterest | 105 | 124 | 65 |
| INCOME\tFROM\tCONTINUING\tOPERATIONS | 467 | 827 | 377 |
| Loss\tfrom\toperations\tof\tdiscontinued\tbusinesses\t(net\tof\tincome\ntaxes\tof\t$35,\t$11\tand\t$1,\trespectively) | (194) | (21) | (3) |
| INCOME\tBEFORE\tEXTRAORDINARY\tITEMS | 273 | 806 | 374 |
| Extraordinary\tItems\t–\tearly\textinguishment\tof\tdebt\t–\tnet\tof\napplicable\tincome\ttax | — | (11) | (17) |
| NET\tINCOME | $273 | $795 | $357 |
| BASIC\tEARNINGS\tPER\tSHARE: |  |  |  |
| Income\tfrom\tcontinuing\toperations | $0.88 | $1.72 | $0.89 |
| Discontinued\toperations | (0.36) | (0.04) | (0.01) |
| Extraordinary\titems | — | (0.02) | (0.04) |
| BASIC\tEARNINGS\tPER\tSHARE | $0.52 | $1.66 | $0.84 |
| DILUTED\tEARNINGS\tPER\tSHARE: |  |  |  |
| Income\tfrom\tcontinuing\toperations | $0.87 | $1.65 | $0.87 |
| Discontinued\toperations | (0.36) | (0.04) | (0.01) |
| Extraordinary\titems | — | (0.02) | (0.04) |
| DILUTED\tEARNINGS\tPER\tSHARE | $0.51 | $1.59 | $0.82 |

# CONSOLIDATED	STATEMENTS	OF	CASH	FLOWS

| Net	income | $273 | $795 | $357 |
| :--- | :--- | :--- | :--- |
| Adjustments\tto\tnet\tincome: |  |  |  |
| Depreciation\tand\tamortization | 859 | 697 | 388 |
| Gain\tfrom\tsale\tof\tavailable-for-sale\tsecurities | (18) | (112) | — |
| Gain\tfrom\tsale\tof\tassets | — | (31) | (91) |
| Impairment\tloss | — | — | 62 |
| Loss\ton\tdiscontinued\toperations | 229 | 32 | 4 |
| Provision\tfor\tdeferred\ttaxes | 47 | (2) | 12 |
| Minority\tinterest\tearnings | 105 | 124 | 64 |

# CONSOLIDATED	STATEMENTS	OF	CHANGES	IN	STOCKHOLDERS'	EQUITY

# 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	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	2.

								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.	Short-term investments	also	includes	restricted	cash.	Debt	service	reserves	and	other	deposits,	which	might	otherwise	be	considered	cash	and	cash	equivalents,	are	treated	as	non- current	assets	(see	Note	5).

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

|  | 2001 | 2000 |
| :--- | :--- | :--- |
| Coal,\tfuel\toil,\tand\tother\traw\tmaterials | $334 | $298 |
| Spare\tparts\tand\tsupplies | 292 | 271 |
| Total | $626 | $569 |

								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, 3.57%,	3.68%	and	3.73%	for	the	years	ended	December	31,	2001,	2000	and	1999,	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–\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% | 2\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	$295	million,	$225	million,	and	$105	million	in	2001, 2000,	and	1999,	respectively.

								GOODWILL—Goodwill	is	amortized	on	a	straight-line	basis	over	the	estimated	benefit	period,	which	ranges	from	10	to	40	years.	Goodwill	at	December	31,	2001 and	2000	is	shown	net	of	accumulated	amortization	of	$190	million	and	$128	million,	respectively.	The	Company	evaluates	the	impairment	of	goodwill	whenever	events or	changes	in	circumstances	indicate	that	the	carrying	amount	may	not	be	recoverable	using	the	projection	of	undiscounted	cash	flows.	In	the	event	such	cash	flows	are not	expected	to	be	sufficient	to	recover	the	recorded	value	of	goodwill,	the	goodwill	will	be	written	down	to	the	estimated	fair	value	based	on	discounted	cash	flow analysis.

								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	3)	based	on	discounted	cash	flow	analysis.

								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	$154 million	and	$105	million	as	of	December	31,	2001	and	2000,	respectively.

								PROJECT	DEVELOPMENT	COSTS—The	Company	capitalizes	the	costs	of	developing	new	construction	projects	after	achieving	certain	project-related milestones	that	indicate	that	the	project	is	probable	of	completion.	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	gains	or	losses	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	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	at	December	31,	2001.	Also,	during	1999,	the	Brazilian	Real	experienced	a	significant	devaluation	relative	to	the	U.S.	Dollar	declining	from	1.21 Reais	to	the	U.S.	Dollar	at	December	31,	1998	to	1.81	Reais	to	the	Dollar	at	December	31,	1999.	This	continued	devaluation	resulted	in	significant	foreign	currency translation	and	transaction	losses	particularly	during	2001	and	1999.	The	Company	recorded	$210	million,	$64	million	and	$203	million	before	income	taxes	of	non- cash	foreign	currency	transaction	losses	on	U.S.	dollar	denominated	debt	from	its	investments	in	Brazilian	equity-method	affiliates	during	2001,	2000	and	1999, respectively.	These	amounts	are	recorded	in	equity	in	pre-tax	earnings	of	affiliates	in	the	accompanying	consolidated	statements	of	operations.	The	cash	flow	impacts	of these	losses	will	be	realized	when	the	principal	balance	of	the	related	debt	is	paid	or	subsequent	refinancings	of	such	principal	are	paid.

								During	2001,	Argentina	began	experiencing	a	significant	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	have	been	adopted	by	the	Argentine government,	including	abandoning	the	country's	fixed	dollar-to-peso	exchange	rate,	converting	dollar	denominated	loans	into	pesos	and	placing	restrictions	on	the convertibility	of	the	Argentine	peso.	The	government	has	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	until	June	30,	2002.	In response	to	the	changes,	the	Company	recorded	foreign	currency	transaction	losses	in	2001	of	approximately	$31	million	using	an	exchange	rate	of	1.65	Argentine	Pesos to	U.S.	Dollar	based	on	the	exchange	rate	upon	reopening	of	the	local	currency	markets	in	mid-January	2002.	These	losses	are	recorded	in	other	income,	net	in	the accompanying	consolidated	statements	of	operations.	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.

								REVENUE	RECOGNITION	AND	CONCENTRATION—Revenues	from	the	sale	of	electricity	and	steam	generation	are	recorded	based	upon	output	delivered and	capacity	provided	at	rates	as	specified	under	contract	terms	or	prevailing	market	rates.	Electricity	distribution	revenues	are	recognized	when	power	is	provided. 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	8).	No	single	customer	accounted	for	10%	or	more	of	revenues	in	2001,	2000	or	1999.	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.

								REGULATION—The	Company	has	investments	in	growth	distribution	and	large	utilities	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. 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	$390	million	and	$401	million	at	December	31,	2001,	and	2000,	respectively,	that	it	expects	to	pass	through	to	its	customers	in	accordance with	and	subject	to	regulatory	provisions.	The	regulatory	assets	include	$134	million	and	$110	million	at	December	31,	2001,	and	2000,	respectively,	which	are	AES's share	of	regulatory	assets	recorded	by	the	Company's	equity	method	affiliates	in	Brazil,	which	are	included	in	the	investments	and	advances	to	affiliates	balance	on	the accompanying	consolidated	balance	sheets.	The	deferred	regulatory	assets	at	entities,	which	are	controlled	and	consolidated	by	the	Company,	are	recorded	in	other assets	on	the	consolidated	balance	sheets.

								During	2001,	the	electricity	markets	in	significant	portions	of	Brazil	experienced	rationing,	or	reduced	availability	of	electricity	to	customers,	due	to	low	rainfall, reduced	reservoir	levels	and	that	country's	significant	dependence	on	electricity	generated	from	hydrological	resources.	These	factors	resulted	in	higher	costs	and	lower sales	for	AES's	Brazilian	subsidiaries	and	equity	affiliates.	In	December	2001,	the	Company's	Brazilian	subsidiaries	and	equity	affiliates	reached	an	industry-wide agreement	(the	"agreement")	with	the	Brazilian	government	that	provided	resolution	to	all	rationing	related	issues	as	well	as	to	certain	other	electricity	tariff	related issues.	There	were	three	parts	to	the	agreement.	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	for	end-use	consumers	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	income	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	the	provisions	of	Annex	V. Accordingly,	the	only	impact	of	this	portion	of	the	agreement	was	the	balance	sheet	reclassification	of	the	receivable	to	a	regulatory	asset.	The	tariff	increase	will	remain in	effect	until	all	recoverable	amounts	are	collected	which	the	Company	estimates	will	take	approximately	three	years.	The	agreement	also	establishes	that	BNDES,	the National	Development	Bank	of	Brazil,	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,	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.

								The	third	part	of	the	agreement	relates	to	the	sales	price	that	Sul,	the	Company's	distribution	subsidiary	in	Porto	Alegre,	would	receive	for	its	sales	of	excess	energy. As	a	result	of	the	agreement,	Sul,	recorded	approximately	$100	million	of	additional	revenue	and	a	corresponding	receivable	from	the	spot	market	in	the	fourth	quarter. Sul	had	elected	early	in	2001,	as	permitted	under	its	concession	contract,	to	expose	itself	to	gains	or	losses	based	on	the	difference	between	the	market	price	of	energy	in the	South	where	they	normally	sell	electricity	and	the	Southeast	where	they	take	delivery.	Drought	conditions	in	the	Southeast,	even	with	rationing,	created	a	large imbalance	between	prices	in	the	Southeast	and	the	South	resulting	in	a	substantial	gain.	Sul	had	not	recorded	the	revenue	prior	to	the	fourth	quarter	because	rationing had	made	the	Brazilian	spot	market	illiquid	and	the	negotiations	on-going	with	the	government,	distributors	and	generators	created	an	environment	where	collection	of the	receivable	was	not	assured.	The	BNDES	pre-funding	of	the	tariff	increase	through	loans	to	the	distributors	and	generators	added	the	needed	liquidity	to	the	spot market	to	assure	collection.

								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	classified	as	other	than	trading	were	accounted	for	using	settlement	accounting	(i.e.	gains	and	losses 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.	The	majority	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.	If	a	derivative	financial	instrument	is	entered	into	for	trading	purposes,	it	is	marked-to-market	with	net	gains	reported within	revenues	or	net	losses	reported	within	cost	of	sales.

								Derivative	fair	values	are	reflected	at	quoted	or	estimated	market	value.	The	values	are	adjusted	to	reflect	the	potential	impact	of	liquidating	our	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.

								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	12).	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	goodwill	and	long-lived	assets;	valuation	allowances for	receivables	and	deferred	tax	assets,	the	recoverability	of	deferred	regulatory	assets	and	the	valuation	of	certain	financial	instruments,	environmental	liabilities	and potential	litigation	claims	and	settlements	(see	Note	8).

								RECLASSIFICATIONS—Certain	reclassifications	have	been	made	to	prior-period	amounts	to	conform	to	the	2001	presentation.

2.	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	3,000	MW	of	generation	and	433,000	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	and	$79	million	in	2001	and	2000,	respectively,	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	tables	below	sets	forth	revenues,	extraordinary	items,	net	income	and	comprehensive	income	for	AES	and	IPALCO	for	the	years	ended	December	31,	2001, 2000	and	1999.

| AES | $8,491 | $6,643 | $3,246 |
| :--- | :--- | :--- | :--- |
| IPALCO | 836 | 891 | 871 |
|  | $9,327 | $7,534 | $4,117 |
| Extraordinary\titems:\nAES | $— | $(7) | $(17) |
| IPALCO | — | (4) | — |
|  | $— | $(11) | $(17) |
| Net\tIncome: |  |  |  |
| AES | $204 | $640 | $228 |
| IPALCO | 69 | 155 | 129 |
|  | $273 | $795 | $357 |

|  | AES | IPALCO | Combined |
| :--- | :--- | :--- | :--- |
| Comprehensive\tIncome: |  |  |  |
| Year\tended\tDecember\t31,\t1999 |  |  |  |
| Net\tIncome | $228 | $129 | $357 |
| Foreign\tcurrency\ttranslation\tadjustment | (759) | — | (759) |
| Unrealized\tgains\ton\tmarketable\tsecurities | — | 107 | 107 |
| Comprehensive\tincome | $(531) | $236 | $(295) |
| Year\tended\tDecember\t31,\t2000 |  |  |  |
| Net\tIncome | $640 | $155 | $795 |
| Foreign\tcurrency\ttranslation\tadjustment | (575) | — | (575) |
| Realized\tgains\ton\tmarketable\tsecurities | — | (107) | (107) |
| Minimum\tpension\tliability\tadjustment | — | (2) | (2) |
| Comprehensive\tincome | $65 | $46 | $111 |
| Year\tended\tDecember\t31,\t2001 |  |  |  |
| Net\tIncome | $204 | $69 | $273 |
| Foreign\tcurrency\ttranslation\tadjustment | (636) | — | (636) |
| Unrealized\tlosses\ton\tmarketable\tsecurities | (48) | — | (48) |
| Change\tin\tderivative\tfair\tvalue | (28) | — | (28) |
| Minimum\tpension\tliability\tadjustment | (9) | (7) | (16) |
|  | (93) |  | (93) |
| Comprehensive\tincome | $(610) | $62 | $(548) |

								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.

								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	is	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	is being	amortized	over	40	years.	At	December	31,	2000,	$848	million	of	cash	had	been	raised	by	AES	through	the	issuance	of	debt	and	equity	for	the	purchase	of	Gener. This	amount	is	recorded	as	restricted	cash	in	short-term	investments	in	the	accompanying	consolidated	balance	sheets.	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.

								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	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	800	MW	of	installed	capacity,	and 427,000	customers.

								The	purchase	price	allocations	for	Thermo	Ecotek,	SONEL,	Kievoblenergo	and	Rivnooblenergo	have	been	completed	on	a	preliminary	basis,	subject	to	adjustments resulting	from	engineering,	environmental,	legal	and	other	analyses	during	the	respective	allocation	periods.

								In	June	2000,	pursuant	to	its	tender	offer	for	ADSs,	a	subsidiary	of	the	Company	purchased	for	cash	approximately	35	million	ADSs,	each	representing	50	shares, of	C.A.	La	Electricidad	de	Caracas	and	Corporacion	EDC,	C.A.	(together,	"EDC")	at	$28.50	per	ADS.	Also	in	June,	2000,	pursuant	to	its	tender	offer	for	all	outstanding shares	of	EDC,	a	subsidiary	of	the	Company	purchased	approximately	1.1	billion	shares	of	EDC	at	$0.57	per	share.	The	purchases	brought	the	Company's	ownership interest	in	EDC	to	approximately	81%.	Subsequently,	the	Company's	total	ownership	reached	approximately	87%	due	to	a	stock	buyback	program	initiated	by	EDC	in July	2000.	The	total	purchase	price	was	$1.7	billion	of	cash.	EDC	is	the	largest	private	integrated	utility	in	Venezuela,	covering	the	capital	region	of	Caracas.	It	has interests	in	distribution	businesses	in	Venezuela,	as	well	as	El	Salvador-together	serving

over	1	million	customers.	EDC	also	provides	2,265	MW	of	installed	capacity	through	its	generation	facilities	in	Venezuela.	The	purchase	price	allocation	was	as	follows (in	millions):

								Property	and	equipment	was	reduced	by	the	negative	goodwill.	The	cost	of	the	acquisition	was	allocated	on	the	basis	of	estimated	fair	value	of	the	assets	acquired and	liabilities	assumed,	primarily	based	upon	an	independent	appraisal.	As	of	December	31,	2000,	the	severance	plan	was	completed	and	the	workforce	was	reduced	by approximately	2,500	people.	All	of	the	costs	associated	with	the	plan	were	recorded	during	2000,	and	all	of	the	cash	payments	were	made	in	2000.

								In	August	2000,	a	subsidiary	of	the	Company	completed	the	acquisition	of	a	59%	equity	interest	in	a	Hidroelectrica	Alicura	S.A.	("Alicura")	in	Argentina	from Southern	Energy,	Inc.	and	its	partners.	Alicura	operates	a	1,000	MW	peaking	hydro	facility	located	in	the	province	of	Neuquen,	Argentina.	The	purchase	price	of approximately	$205	million	includes	the	assumption	of	existing	non-recourse	debt.	In	December	2000	a	subsidiary	of	the	Company	acquired	an	additional	39% ownership	interest	in	Alicura,	19.5%	ownership	interests	each	from	the	Federal	Government	of	Argentina	and	the	Province	of	Neuquen,	for	approximately	$9	million.	At

December	31,	2000,	the	Company's	ownership	interest	was	98%.	The	employees	of	Alicura	own	the	remaining	2%.	All	of	the	purchase	price	was	allocated	to	property, plant	and	equipment	and	is	being	depreciated	over	the	useful	life.

								In	October	2000,	a	subsidiary	of	the	Company	completed	the	acquisition	of	Reliant	Energy	International's	50%	interest	in	El	Salvador	Energy	Holdings,	S.A. ("ESEH")	that	owns	three	distribution	companies	in	El	Salvador.	The	purchase	price	for	this	interest	in	ESEH	was	approximately	$173	million.	The	three	distribution companies,	Compania	de	Alumbrado	Electrico	de	San	Salvador,	S.A.	de	C.V.,	Empresa	Electrica	de	Oriente,	S.A.	de	C.V.	and	Distribuidora	Electrica	de	Usulutan,	S.A. De	C.V.	serve	3.5	million	people,	approximately	60%	of	the	population	of	El	Salvador,	including	the	capital	city	of	San	Salvador.	A	subsidiary	of	the	Company	had previously	acquired	a	50%	interest	in	ESEH	through	its	acquisition	of	EDC.	Through	the	purchase	of	Reliant	Energy	International's	ownership	interest,	the	Company owns	a	controlling	interest	in	the	three	distribution	companies.	The	total	purchase	price	for	100%	of	the	interest	in	ESEH	approximated	$325	million,	of	which approximately	$176	million	was	allocated	to	goodwill	and	is	being	amortized	over	40	years.

								In	December	2000,	the	Company	acquired	all	of	the	outstanding	shares	of	KMR	Power	Corporation	("KMR"),	including	the	buyout	of	a	minority	partner	in	one	of KMR's	subsidiaries,	for	approximately	$64	million	and	assumed	long-term	liabilities	of	approximately	$245	million.	The	acquisition	was	financed	through	the	issuance of	approximately	699,000	shares	of	AES	common	stock	and	cash.	KMR	owns	a	controlling	interest	in	two	gas-fired	power	plants	located	in	Cartagena,	Colombia:	a 100%	interest	in	the	314	MW	TermoCandelaria	power	plant	and	a	66%	interest	in	the	100

MW	Mamonal	plant.	Approximately	$77	million	of	the	purchase	price	was	allocated	to	goodwill	and	is	being	amortized	over	32	years.	The	TermoCandelaria	power	plant has	been	included	in	discontinued	operations	in	the	accompanying	consolidated	financial	statements.

								The	table	below	presents	supplemental	unaudited	pro	forma	operating	results	as	if	all	of	the	acquisitions	had	occurred	at	the	beginning	of	the	periods	shown	(in millions,	except	per	share	amounts).	No	pro	forma	operating	results	are	provided	for	2001,	because	the	impact	would	not	have	been	material.	The	pro	forma	amounts include	certain	adjustments,	primarily	for	depreciation	and	amortization	based	on	the	allocated	purchase	price	and	additional	interest	expense:

| Revenue | $8,137 |
| :--- | :--- |
| Income\tbefore\textraordinary\titems | 833 |
| Net\tIncome | 822 |
| Basic\tearnings\tper\tshare | $1.67 |
| Diluted\tearnings\tper\tshare | $1.61 |

								The	pro	forma	results	are	based	upon	assumptions	and	estimates	that	the	Company	believes	are	reasonable.	The	pro	forma	results	do	not	purport	to	be	indicative	of the	results	that	actually	would	have	been	obtained	had	the	acquisitions	occurred	at	the	beginning	of	the	periods	shown,	nor	are	they	intended	to	be	a	projection	of	future results.

								Effective	January	1,	2001,	the	Company	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.

								During	the	year,	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.	The	businesses	were	either	disposed	of	or	abandoned	during	the	year	or	were	classified	as	held	for	sale	at December	31,	2001.	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	has	certain	businesses	that	are	held	for	sale, including	TermoCandelaria.	The	Company	has	approved	and	committed	to	a	plan	to	sell	these	assets,	they	are	available	for	immediate	sale,	and	a	plan	has	been established	to	locate	a	buyer	at	a	reasonable	fair	market	value	price.	The	Company	believes	it	will	sell	these	assets	within	one	year	and	it	is	unlikely	that	significant changes	will	be	made	to	the	plan	to	sell.

								At	December	31,	2001,	the	assets	and	liabilities	associated	with	the	discontinued	operations	are	segregated	on	the	consolidated	balance	sheets.	A	majority	of	the long-lived	assets	related	to	discontinued	operations	are	for	the	TermoCandelaria	competitive	supply	business	located	in	Colombia.

								The	revenues	associated	with	the	discontinued	operations	were	$287	million,	$74	million	and	$7	million	for	the	years	ended	December	31,	2001,	2000	and	1999, respectively.	The	pretax	losses	associated	with	the	discontinued	operations	were	$58	million,	$31	million	and	$4	million	for	each	of	the	years	ended	December	31,	2001, 2000	and	1999,	respectively.	The	loss	on	disposal	and	impairment	write-downs	for	those	businesses	held	for	sale,	net	of	tax	associated	with	the	discontinued	operations, was	$145	million	for	the	year	ended	December	31,	2001.

# 4.	INVESTMENTS	IN	AND	ADVANCES	TO	AFFILIATES

								The	Company	is	a	party	to	joint	venture/consortium	agreements	through	which	the	Company	has	equity	investments	in	Companhia	Energetica	de	Minas	Gerais ("CEMIG"),	Light-Servicos	de	Eletricidade	S.A.	("Light")	and	Eletropaulo	Metropolitana	Electricidade	de	Sao	Paulo	S.A.	("Eletropaulo").	The	joint	venture/consortium parties	generally	share	operational	control	of	the	investee.	The	agreements	prescribe	ownership	and	voting	percentages	as	well	as	other	matters.	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.

								Effective	May	1,	2000,	the	Company	disposed	of	its	investment	in	Northern/AES	Energy.	The	disposition	of	the	investment	did	not	have	a	material	effect	on	the Company's	financial	condition	or	results	of	operations.

								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	is	being	amortized	over	23	years.

								In	August	2000,	a	subsidiary	of	the	Company	acquired	a	49%	interest	in	Songas	Limited	for	approximately	$40	million.	Songas	Limited	owns	the	Songo	Songo Gas-to-Electricity	Project	in	Tanzania.	Under	the	terms	of	a	project	management	agreement,	the	Company	has	assumed	overall	project	management	responsibility.	The project	consists	of	the	refurbishment	and	operation	of	five	natural	gas	wells	in	coastal	Tanzania,	the	construction	and	operation	of	a	65	mmscf/day	gas	processing	plant

and	related	facilities,	the	construction	of	a	230	km	marine	and	land	pipeline	from	the	gas	plant	to	Dar	es	Salaam	and	the	conversion	and	upgrading	of	an	existing	112 MW	power	station	in	Dar	es	Salaam	to	burn	natural	gas,	with	an	optional	additional	unit	to	be	constructed	at	the	plant.	Since	the	project	is	currently	under	construction, no	revenues	or	expenses	have	been	incurred,	and	therefore	no	results	are	shown	in	the	following	table.

								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	and	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	May	2000,	a	subsidiary	of	the	Company	acquired	an	additional	5%	of	the	preferred,	non-voting	shares	of	Eletropaulo	for	approximately	$90	million.	In	January 2000,	59%	of	the	preferred	non-voting	shares	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.	As	of	December	31,	2001,	44.4%	of	the	total	purchase	price had	been	paid.	Installments	of	1%,	28.5%	and	26.1%	are	due	in	2002,	2003	and	2004,	respectively.	At	December	31,	2000,	the	Company	had	a	total	economic	interest of	49.6%	and	a	voting	interest	of	17.35%	in	Eletropaulo.	The	Company	accounts	for	this	investment	using	the	equity-method	based	on	the	related	consortium	agreement. The	consortium	agreement	provides	the	Company	with	the	ability	to	exercise	significant	influence	but	not	control.

								In	December	2000,	a	subsidiary	of	the	Company	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	owns	approximately	21.14%	of	Light.

								In	December	2000,	a	subsidiary	of	the	Company	entered	into	an	agreement	with	EDF	International	S.A.	("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	and	a	corresponding	0.83%	in	Eletropaulo	for	$114.6	million.	At	December	31,	2001,	the	Company	owns	approximately	23.89%	of	Light	and 50.43%	of	Electropaulo.	The	additional	ownership	increased	the	Company's	economic	ownership	in	Eletropaulo	but	did	not	give	the	Company	the	ability	to	control	the business.	Control	of	the	business	did	not	occur	until	the	exchange	described	below	occurred.

								On	February	6,	2002,	a	subsidiary	of	the	Company	has	exchanged	with	EDF,	their	shares	representing	a	23.89%	interest	in	Light	for	88%	of	the	shares	of	AES	Elpa S.A.	(formerly	Lightgas	Lida).	AES	Elpa	owns	77%	of	the	voting	capital	(31%	of	total	capital)	of	Eletropaulo	and	100%	of	Light	Telecom.	Additionally,	AES	Elpa assumed	debt	of	$527	million	in	the	transaction	of	which	$245	million	is	due	in	April	2002	and	$111	million	is	due	in	October	2002.	As	a	result	of	this	transaction,	AES has	acquired	a	controlling	interest	in	Eletropaulo	and	will	begin	consolidating	the	subsidiary	in	2002.

								During	2001,	the	Company	was	removed	from	the	management	and	the	Board	of	Directors	of	CESCO,	a	subsidiary	of	the	Company,	by	GRIDCO.	GRIDCO	is	a 100%	owned	entity	of	the	Government	of	the	State	of	Orissa,	India,	and	the	minority	shareholder	of	CESCO,	a	distribution	company	also	in	Orissa.	An	administrator appointed	by	the	state	regulator	has	been	making	the	significant	decisions	that	are	expected	to	be	made	in	the	ordinary	course	of	business.	Due	to	these	actions	the Company	has	removed	all	of	its	people	from	the	business.	Because	the	Company	has	lost	operational	control	of	CESCO,	it	has	changed	its	accounting	for	this	business from	consolidation	to	equity-method	accounting.	The	investment	in	the	business	has	been	written-down	to	zero.	The	Company	does	not	believe	it	has	any	further ongoing	obligation	related	to	this	business.

								The	following	table	presents	summarized	financial	information	(in	millions)	for	the	Company's	investments	in	affiliates	over	which	it	has	the	ability	to	exercise significant	influence	but	does	not	control,	which	are	accounted	for	using	the	equity	method:

|  | 2001 | 2000 | 1999 |
| :--- | :--- | :--- | :--- |
| Revenues | $6,147 | $6,241 | $5,960 |
| Operating\tIncome | 1,717 | 1,989 | 1,839 |
| Net\tIncome | 650 | 859 | 62 |
| Current\tAssets | 3,700 | 2,423 | 2,259 |
| Noncurrent\tAssets | 14,943 | 13,080 | 15,359 |
| Current\tLiabilities | 3,510 | 3,370 | 3,637 |
| Noncurrent\tLiabilities | 8,297 | 5,927 | 7,536 |
| Stockholder's\tEquity | 6,836 | 6,206 | 6,445 |

								Relevant	equity	ownership	percentages	for	these	investments	are	presented	below:

| Affiliate | Country | 2001 | December	31,<br>2000 | 1999 |
| :--- | :--- | :--- | :--- | :--- |
| CEMIG | Brazil | 21.62% | 21.62% | 21.62% |
| CESCO | India | 48.45 | 48.45 | 48.45 |
| Chigen\taffiliates | China | 30.00 | 30.00 | 30.00 |
| EDC\taffiliates | Venezuela | 45.00 | 45.00 | n/a |
| Eletropaulo | Brazil | 50.43 | 49.60 | 9.90 |
| Elsta | Netherlands | 50.00 | 50.00 | 50.00 |
| Gener\taffiliates | Chile | 37.50 | n/a | n/a |
| Infovias | Brazil | 50.00 | 50.00 | 50.00 |
| Kingston | Canada | 50.00 | 50.00 | 50.00 |
| Light | Brazil | 23.89 | 21.14 | 17.68 |
| Medway\tPower,\tLtd. | United\tKingdom | 25.00 | 25.00 | 25.00 |
| Nigen | United\tKingdom | — | — | 46.17 |
| Northern/AES\tEnergy | United\tStates | — | — | 50.00 |
| OPGC | India | 49.00 | 49.00 | 49.00 |
| Songas\tLimited | Tanzania | 49.00 | 49.00 | n/a |

								The	results	of	operations	and	the	financial	position	of	the	Brazilian	affiliates,	Light,	Eletropaulo	and	CEMIG,	were	negatively	impacted	by	the	devaluation	of	the

Brazilian	Real.	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	at	December	31,	2001.	Additionally,	during	1999,	the	Brazilian	Real	experienced	a	significant	devaluation	relative	to	the	U.S.	Dollar	declining	from	1.21 Reais	to	the	U.S.	Dollar	at	December	31,	1998	to1.81	Reais	to	the	U.S.	Dollar	at	December	31,	1999.	This	continued	devaluation	resulted	in	significant	foreign	currency translation	and	transaction	losses	particularly	during	2001	and	1999.	The	Company	recorded	$210	million,	$64	million	and	$203	million	before	income	taxes	of	non- cash	foreign	currency	transaction	losses	on	its	investments	in	Brazilian	equity-method	affiliates	during	2001,	2000	and	1999,	respectively.

								The	Company's	cumulative	after-tax	share	of	undistributed	earnings	of	affiliates	included	in	consolidated	retained	earnings	was	$462	million,	$370	million,	and	$96 million	at	December	31,	2001,	2000,	and	1999,	respectively.	The	Company	charged	and	recognized	construction	revenues,	management	fees	and	interest	on	advances	to its	affiliates,	which	aggregated	$12	million,	$11	million,	$21	million	for	each	of	the	years	ended	December	31,	2001,	2000	and	1999,	respectively.

# 5.	INVESTMENTS

								The	short-term	investments	and	debt	service	reserves	and	other	deposits	were	invested	as	follows	(in	millions):

(1) Amounts	required	to	be	maintained	in	cash	or	cash	equivalents	in	accordance	with	certain	covenants	of	various	project	financing	agreements	and	lease	contracts. Restricted	cash	at	December	31,	2000,	also	includes	certain	cash	deposited	in	escrow.

								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.	All	of the	Company's	investments	were	short-term	at	December	31,	2001	and	2000.

								Also	included	in	short-term	investments	at	December	31,	2001	and	2000	was	restricted	cash	of	approximately	$357	million	and	$1.2	billion,	respectively.

								In	2001,	a	subsidiary	of	the	Company	sold	approximately	14	million	shares	of	Compania	Anonima	Nacional	Telefonos	de	Venezuela	resulting	in	a	realized	gain	of approximately	$18	million.	In	2000,	a	subsidiary	of	the	Company	sold	approximately	one	million	shares	of	Internet	Capital	Group,	Inc.	resulting	in	a	realized	gain	of approximately	$112	million.	The	after-tax	proceeds	from	this	sale	were	applied	primarily	to	the	reduction	of	the	Company's	outstanding	unsecured	debt.

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

# 6.	LONG-TERM	DEBT

								NON-RECOURSE	DEBT—Non-recourse	debt	at	December	31,	2001	and	2000	consisted	of	the	following	(in	millions):

|  | Interest<br>Rate	(1) | Final<br>Maturity | 2001 | 2000 |
| :--- | :--- | :--- | :--- | :--- |
| VARIABLE\tRATE: |  |  |  |  |
| Bank\tloans | 7.05% | 2023 | $5,760 | $6,861 |
| Commercial\tpaper | 6.40% | 2008 | 501 | 637 |
| Notes\tand\tBonds | 7.75% | 2030 | 889 | — |
| Debt\tto\t(or\tguaranteed\tby)\tmultilateral\tor\texport\tcredit\tagencies | 5.65% | 2018 | 945 | 649 |
| Other | 12.38% | 2022 | 602 | 837 |
| FIXED\tRATE: |  |  |  |  |
| Bank\tloans | 6.19% | 2018 | 1,892 | 2,003 |
| Commercial\tPaper | 13.50% | 2002 | 63 | — |
| Notes\tand\tbonds | 8.72% | 2029 | 5,922 | 3,994 |

| Debt	to	(or	guaranteed	by)	multilateral	or	export	credit	agencies | 7.90% | 2023 | 165 | 164 |
| :--- | :--- | :--- | :--- | :--- |
| Other | 3.43% | 2010 | 118 | 13 |
| SUBTOTAL |  |  | 16,857 | 15,158 |
| Less:\tCurrent\tmaturities |  |  | (2,184) | (2,462) |
| TOTAL |  |  | $14,673 | $12,696 |

# (1) Weighted	average	interest	rate	at	December	31,	2001.

								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	the	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	11).

								The	Company	has	interest	rate	swap	and	forward	interest	rate	swap	agreements	in	an	aggregate	notional	principal	amount	of	$3.2	billion	at	December	31,	2001.	The interest	rate	swaps	are	accounted	for	at	fair	value	(see	Note	7).	The	swap	agreements	effectively	change	the	variable	interest	rates	on	the	portion	of	the	debt	covered	by the	notional	amounts	to	weighted	average	fixed	rates	ranging	from	approximately	4.19%	to	9.90%.	The	agreements	expire	at	various	dates	from	2002	through	2017.	In the	event	of	nonperformance	by	the	counter	parties,	the	Company	may	be	exposed	to	increased	interest	rates;	however,	the	Company	does	not	anticipate	nonperformance by	the	counter	parties,	which	are	multinational	financial	institutions.

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

								At	December	31,	2001,	a	number	of	the	Company's	subsidiaries	were	in	default	under	their	outstanding	project	indebtedness	as	of	December	31,	2001,	including Chivor,	Edelap,	Eden/Edes	and	Parana.	Because	none	of	these	businesses	are	material	subsidiaries,	none	of	these	defaults	is	expected	to	have	a	material	adverse	effect on	the	Company's	results	of	operations	or	financial	condition.	All	of

the	related	loans	have	been	recorded	in	current	non-recourse	debt	in	the	accompanying	consolidated	balance	sheets.

								RECOURSE	DEBT—Recourse	debt	obligations	are	direct	borrowings	of	the	AES	parent	corporation	and	at	December	31,	2001	and	2000,	consisted	of	the following	(in	millions):

|  | Interest<br>Rate	(1) | Final<br>Maturity | First	Call<br>Date	(2) | 2001 | 2000 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Corporate\trevolving\tbank\tloan | 4.09% | 2003 | 2000 | $70 | $140 |
| Term\tloan | 4.49% | 2003 | — | 425 | — |
| Term\tloan | 4.50% | 2002 | — | 188 | — |
| Senior\tnotes | 8.75% | 2002 | — | 300 | 300 |
| Senior\tnotes | 8.00% | 2008 | 2000 | 200 | 200 |
| Senior\tnotes | 9.50% | 2009 | — | 750 | 750 |
| Senior\tnotes | 9.38% | 2010 | — | 850 | 850 |
| Senior\tnotes | 8.88% | 2011 | — | 600 | — |
| Senior\tnotes | 8.38% | 2011 | — | 196 | — |
| Senior\tnotes | 8.75% | 2008 | — | 400 | — |
| Remarketable\tor\tRedeemable\tSecurities | 7.38% | 2013 | 2003 | 200 | — |
| Senior\tsubordinated\tnotes | 10.25% | 2006 | 2001 | 250 | 250 |
| Senior\tsubordinated\tnotes | 8.38% | 2007 | 2002 | 325 | 325 |
| Senior\tsubordinated\tnotes | 8.50% | 2007 | 2002 | 375 | 375 |
| Senior\tsubordinated\tdebentures | 8.88% | 2027 | 2004 | 125 | 125 |
| Convertible\tjunior\tsubordinated\tdebentures | 4.50% | 2005 | 2001 | 150 | 150 |
| Unamortized\tdiscounts |  |  |  | (3) | (7) |
| SUBTOTAL |  |  |  | 5,401 | 3,458 |
| Less:\tCurrent\tmaturities |  |  |  | (488) | — |
| Total |  |  |  | $4,913 | $3,458 |

(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	March	2000,	the	Company	entered	into	an	$850	million	revolving	credit	agreement	with	a	syndicate	of	banks,	which	provides	for	a	combination	of	either	loans or	letters	of	credit	up	to	the	maximum	borrowing	capacity.	Loans	under	the	facility	bear	interest	at	either	Prime	plus	a	spread	of	0.50%	or	LIBOR	plus	a	spread	of	2%. Such	spreads	are	subject	to	adjustment	based	on	the	Company's	credit	ratings	and	the	term	remaining	to	maturity.	This	facility	replaced	the	Company's	then	existing separate	$600	million	revolving	credit	facility	and	$250	million	letter	of	credit	facilities.	As	of	December	31,	2001,	$496	million	was	available.	Commitment	fees	on	the facility	at	December	31,	2001	were	.50%	per	annum.	The	Company's	recourse	debt	borrowings	are	unsecured	obligations	of	the	Company.

								In	May	2001,	the	Company	issued	$200	million	of	Remarketable	or	Redeemable	Securities	("ROARS").	The	ROARS	are	scheduled	to	mature	on	June	15,	2013, but	such	maturity	date	may	be	adjusted	to	a	date,	which	shall	be	no	later	than	June	15,	2014.	On	the	First	Remarketing	Date	(June	15,	2003)	or	subsequent	Remarketing dates	thereafter,	the	remarketing	agent,	or	the	Company,	may	elect	to	redeem	the	ROARS	at	100%	of	the	aggregate	principal	amount	and	unpaid	interest,	plus	a premium	in	certain	circumstances.	The	Company	at	its	option,	may	also	redeem	the	ROARS	subsequent	to	the	First	Remarketing	Date	at	any	time.	Interest	on	the ROARS	accrues	at	7.375%	until	the	First	Remarketing	Date,	and	thereafter	is	set	annually	based	on	market	rate	bids,	with	a	floor	of	5.5%.	The	ROARS	are	senior	notes.

								The	Junior	Subordinate	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	at	December	31,	2001,	are	(in	millions):

								COVENANTS—The	terms	of	the	Company's	recourse	debt,	including	the	revolving	bank	loan,	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	incurrence	of	additional	debt	and payments	of	dividends	to	stockholders.	In	addition,	the	Company's	revolver	contains	provisions	regarding	events	of	default	that	could	be	caused	by	events	of	default	in other	debt	of	AES	and	certain	of	its	significant	subsidiaries,	as	defined	in	the	agreement.

								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,	2001,	approximately	$442	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	retained	earnings	to	the	parent	company.	Such	restricted retained	earnings	of	subsidiaries	amounted	to	approximately	$6.5	billion	at	December	31,	2001.

# 7.	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	year	ended	December	31,	2001,	the	impact	of	changes	in	derivative	fair	value	primarily	related	to	derivatives	that	do	not	qualify	for	hedge	accounting treatment	was	a	charge	of	$36	million,	after	income	taxes.	This	amount	includes	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	year	ended	December	31,	2001.	There	was	no	net	effect	on	results	of	operations	for	the	year	ended December	31,	2001,	of	derivative	and	non-derivative	instruments	that	have	been	designated	and	qualified	as	hedging	net	investments	in	foreign	operations. Approximately	$35	million	of	other	comprehensive	loss	related	to	derivative	instruments	as	of	December	31,	2001	is	expected	to	be	recognized	as	a	reduction	to earnings	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	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,	net	of	tax,	during	the	year-ended	December	31, 2001,	were	as	follows	(in	millions):

								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. Currency	forward	and	swap	agreements	are	utilized	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.	The	majority	of	AES's	foreign	currency	derivatives	are	designated	and	qualify	as	either	fair	value	hedges	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.	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	three	years.	For	the	year	ended	December	31,	2001,	a	charge	of	$4	million,	after	income	taxes,	was	recorded	for	two	cash	flow	hedges	that	were

discontinued	because	it	is	probable	that	the	hedged	forecasted	transaction	will	not	occur.	A	portion	of	this	charge	has	been	classified	as	discontinued	operations.	For	the year	ended	December	31,	2001,	no	fair	value	hedges	were	de-recognized	or	discontinued.

# 8.	COMMITMENTS,	CONTINGENCIES	AND	RISKS

								OPERATING	LEASES—As	of	December	31,	2001,	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	$32	million,	$13	million,	and	$7	million	in	the years	ended	December	31,	2001,	2000	and	1999,	respectively.	The	future	minimum	lease	commitments	under	these	leases	are	$44	million	for	2002,	$41	million	for 2003,	$37	million	for	2004,	$37	million	for	2005,	$38	million	for	2006,	and	a	total	of	$405	million	for	the	years	thereafter.

								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	$58	million,	$54	million	and	$26	million	in	2001, 2000	and	1999,	respectively.	Future	minimum	lease	commitments	are	$63	million	for	2002,	$58	million	for	2003,	$63	million	for	2004,	$59	million	for	2005,	$62 million	for	2006	and	a	total	of	$1.3	billion	for	the	years	thereafter.

								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	and	fixed	charges	expected	to	become	due	in	the	immediately	succeeding	three-year	period.	At	December	31,	2001	and	2000,	the amount	deposited	in	the	rent	reserve	account	approximated	$32	million	and	$31	million,	respectively.	This	amount	is	included	in	restricted	cash	and	can	only	be	utilized to	satisfy	lease	obligations.

								The	agreements	governing	the	leases	restrict	the	subsidiary's	ability	to	incur	additional	indebtedness,	sell	its	assets	or	merge	with	another	entity.	The	ability	of	the subsidiary	to	make	distributions	is	restricted	unless	certain	covenants,	including	the	maintenance	of	certain	coverage	ratios,	are	met.	The	subsidiary	is	also	required	to maintain	an	additional	liquidity	account	initially	equal	to	$65	million	less	the	balance	of	the	rent	reserve	account.	A	letter	of	credit	from	a	bank	for	$36	million	has	been obtained	to	satisfy	this	requirement.

								CONTRACTS—Operating	subsidiaries	of	the	Company	have	entered	into	"take-or-pay"	contracts	for	the	purchase	of	electricity	from	third	parties.	Purchases	in 2001	were	approximately	$368	million.	The	future	commitments	under	these	contracts	are	$409	million	for	2002,	$378	million	for	2003,	$341	million	for	2004,	$332 million	for	2005,	$318	million	for	2006	and	a	total	of	$4.3	billion	for	the	years	thereafter.

								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	2001	were	approximately	$617	million.	The	future	commitments	under	contracts	are	$546	million	for	2002,	$519	million	for	2003,	$492 million	for	2004,	$397	million	for	2005,	$248	million	for	2006,	and	$1.9	billion	thereafter.

								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	$127	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	29 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.

								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,	2001	and	2000,	the	Company	had receivables	of	approximately	$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,	2001,	the	Company	has	recorded	cumulative	liabilities	associated	with	acquired	generation	plants	of	approximately $33	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.

								In	May	2000,	the	New	York	State	Department	of	Environmental	Conservation	("DEC")	issued	a	Notice	of	Violation	("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.

								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	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.

								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	counter	parties,	and	as	a	result,	the	Company	is	exposed	to	the	risk	of	nonperformance	by	its	counter	parties.	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	obligations	discussed	below,	were	limited	as	of	December	31,	2001,	by	the	terms	of	the	agreements,	to	an	aggregate	of approximately	$775	million	representing	68	agreements	with	individual	exposures	ranging	from	less	than	$1	million	up	to	$100	million.	Of	this	amount,	$249	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.	These	amounts	aggregated	$50	million as	of	December

31,	2001.	In	addition,	the	Company	has	commitments	to	fund	its	equity	in	projects	currently	under	development	or	in	construction.	At	December	31,	2001,	such commitments	to	invest	amounted	to	approximately	$207	million.

								LETTERS	OF	CREDIT—At	December	31,	2001,	the	Company	had	$453	million	in	letters	of	credit	outstanding	representing	36	agreements	with	individual exposures	ranging	from	less	than	$1	million	up	to	$107	million,	which	operate	to	guarantee	performance	relating	to	certain	project	development	and	construction activities	and	subsidiary	operations.	Of	this	amount,	$262	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	0.50%	to	2.0%	per	annum	on	the	outstanding	amounts.	In	addition,	the	Company	had $76	million	and	a	subsidiary	of	the	Company	had	$271	million	in	surety	bonds	outstanding	at	December	31,	2001.

								LITIGATION—In	September	1999,	an	appellate	judge	in	the	Minas	Gerais,	Brazil	state	court	system	granted	a	temporary	injunction	that	suspends	the effectiveness	of	a	shareholders'	agreement	for	Cia.	Energetica	De	Minas	Gerais	("CEMIG").	This	appellate	ruling	suspends	the	shareholders'	agreement	while	the	action to	determine	the	validity	of	the	shareholders'	agreement	is	litigated	in	the	lower	court.	In	early	November	1999,	the	same	appellate	court	judge	reversed	this	decision	and reinstated	the	effectiveness	of	the	shareholders'	agreement,	but	did	not	restore	the	super	majority	voting	rights	that	benefited	the	Company.	In	March	2000,	a	state	court in	Minas	Gerais	again	ruled	that	the	shareholders'	agreement	was	invalid.	In	April	2000,	the	appellate	court	denied	the	appeal	of	that	second	state	court	decision.	In August	2001,	the	appellate	court	denied	another	appeal,	confirming	the	decision	that	the	shareholder's	agreement	was	null	and	void.	AES	was	required	to	exhaust	all state-level	appeals	before	the	matter	is	heard	before	the	Brazilian	federal	court.	In	November	2001,	a	special	procedure	was	initiated	whereby	CEMIG	requested	that	the case	be	transferred	from	state	court	to	superior	court	in	Brasilia.	The	Company	intends	to	vigorously	pursue	its	legal	rights	in	this	matter	and	to	restore	all	of	its	rights regarding	CEMIG.	Failure	to	prevail	in	this	matter	would	limit	the	Company's	influence	on	the	daily	operations	of	CEMIG.	However,	the	Company	would	still	own approximately	21.6%	of	the	voting	common	stock	of	CEMIG	and	be	able	to	exercise	significant	influence	over	the	operations	of	the	business.

								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.	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	Southland,	AES	Placerita	and	AES	New	Energy)	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.	Each	of	these	investigations	are	currently	in	the	document	gathering stage,	and	the	businesses	have	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.	Similar	to	the	state	investigation,	the	FERC	investigation	has	focused	their attention	to	date	upon	the	forced	and	planned	maintenance	outages	taken	by	the	plants	in	2000.	This	FERC	investigation	also	has	focused	on	the	activities	surrounding the	marketing	of	the	power	from	the	plants.

								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. 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.

								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	2001	and	1999,	the	Company's	financial	position	and	results	of	operations	were	adversely	affected	by a	significant	devaluation	of	the	Brazilian	Real	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	June	1999,	a	subsidiary	of	the	Company	assumed	long-term	managerial	control	of	two	regional	electric	distribution	companies	("RECs")	in	Kazakhstan	as	part of	a	settlement	of	receivables	outstanding	from	the	government	of	Kazakhstan.	The	Company's	claim	against	the	government	was	for	electricity	previously	provided. The	contractual	rights	to	control	the	operations	of	the	RECs	received	in	this	transaction	were	valued	at	approximately	$26	million,	based	on	the	net	present	value	of incremental	cash	flows	expected	to	be	received	as	a	result	of	operating	the	RECs.	The	value	of	the	contract	rights	was	recorded	in	the	statement	of	operations	in	1999. The	two	distribution	businesses

serve	approximately	1.8	million	people.	The	Company	expects	that	the	government	of	Kazakhstan	will	abide	by	the	terms	and	periods	agreed	to	in	the	original memorandum	of	understanding	that	currently	governs	the	Company's	operating	control	of	the	RECs.	However,	the	contract	is	subject	to	economic,	political	and regulatory	risks	associated	with	operating	in	Kazakhstan.	The	Company	does	not	consolidate	the	RECs	because	it	operates	them	under	a	management	agreement	and does	not	have	a	controlling	ownership	interest	in	them.

								Argentina	is	experiencing	a	significant	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.	During	January	and	February	2002,	many	new	economic	measures	have	been	adopted	by	the	Argentine	government, including	abandoning	the	country's	fixed	dollar-to-peso	exchange	rate,	converting	dollar	denominated	loans	into	pesos	and	placing	restrictions	on	the	convertibility	of the	Argentine	peso.	The	government	has	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	until	June	30,	2002.	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.

								AES	has	several	subsidiaries	in	Argentina	operating	in	both	the	competitive	supply	and	growth	distribution	segments	of	the	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	significant	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	beginning	in	2002.	AES	(the	parent	company)	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	overall	liquidity,	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,	2001,	AES's	total	contributed	cash	investment	and	the	retained	earnings	in	the	competitive	supply	business	in	Argentina	are	approximately	$575	million	and	the	total similar	investment	in	the	growth	distribution	business	is	approximately	$465	million.	Depending	on	the	ultimate	resolution	of	these	uncertainties,	AES	may	be	required in	2002	to	record	a	material	impairment	loss	or	write-off	associated	with	the	recorded	carrying	values	of	its	investments,	including	goodwill,	although	no	such	loss	has been	recorded	to	date.	Additionally,	under	current	conditions,	the	Argentine	businesses	may	also	incur	operating	losses	during	2002.	AES	is	currently	investigating	and pursuing	several	potential	alternatives	to	minimize	the	impacts	on	earnings.	It	is	possible,	as	AES	pursues	these	alternatives,	that	future	Argentine	business	results	may be	reported	as	discontinued	operations.

								AES	financed	certain	of	its	purchases	in	Eletropaulo	through	deferred	purchase	price	financing	arrangements	provided	by	BNDES	to	subsidiaries	of	the	Company, which	aggregates	approximately	$1.2	billion.	The	payment	schedule	varies	from	April	2002	through	January	2004.	BNDES	maintains	as	collateral	shares	that	represent substantially	all	of	the	Company's	ownership	interest	in	Eletropaulo.	As	a	result	of	the	volatility	of	the	Brazilian	Real	and	the	difficult	economic	conditions	in	Brazil,	the Company	is	evaluating	whether	to	contribute	equity	sufficient	to	allow	such	subsidiaries	to	make	the	payments.	If	AES	does	not	contribute	sufficient	equity	or	other consideration,	or	if	there	is	not	a	successful	renegotiation	of	the	debt	with	BNDES,	there	can	be	no	assurance	that	such	subsidiaries	will	be	able	to	pay	such	amounts,	or refinance	or	extend	the	maturities	of	any	or	all	of	the	payment	amounts.	In	such	event,	BNDES	may	choose	to	seize	the	shares	held	as	collateral,	and	this	may	result	in	a loss	and	resulting	write-off	of	a	portion	or	all	of	the	Company's	investment.

								LEVERAGED	LEASE	INVESTMENTS—CILCORP	has	investments	in	leveraged	leases	totaling	$136	million.	Related	deferred	tax	liabilities	total	$106 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.

								SALE	OF	ACCOUNTS	RECEIVABLE—IPALCO	has	sold,	on	a	revolving	basis,	an	undivided	interest	in	$50	million	of	its	accounts	receivable.	The	subsidiary is	required	to	maintain	eligible	accounts	receivable	of	$50	million	in	order	for	the	agreement	to	remain	valid.	The	accounts	receivable	were	sold	on	a	non-recourse	basis.

								OTHER—IPALCO	has	an	agreement	with	a	regulatory	body	that	establishes	certain	performance	measures	for	their	system	and	call	center	reliability.	If	these standards	are	not	maintained,	penalties	of	up	to	$7	million	per	violation	can	be	assessed.	The	agreement	is	in	effect	until	2004.	No	penalties	have	been	incurred	under	the agreement	in	2001.

								LIQUIDITY—AES	believes	that	its	sources	of	liquidity	will	be	adequate	to	meet	its	needs	through	the	end	of	2002.	This	belief	is	based	on	a	number	of assumptions,	including,	without	limitation,	assumptions	about	exchange	rates,	pool	prices,	the	ability	of	its	subsidiaries	to	pay	dividends	and	the	timing	and	amount	of asset	sale	proceeds.	In	addition,	as	discussed	in	this	Note	8,	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	2002,	many	of	the	events	which	would	give	rise	to	such	an	obligation	are	beyond	AES's	control.

# 9.		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.

# 10.	MINORITY	INTEREST

								Minority	interest	includes	$100	million	of	cumulative	preferred	stock	of	subsidiaries	at	December	31,	2001	and	2000.	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	$2	million	at	December	31,	2001.	$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.

# 11.	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.

								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	$6	million,	$8	million	and	$1	million	for	2001,	2000	and	1999,	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	stock	option	plans.	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.	At	December	31,	2001,	there	were	approximately	8.3	million	shares	reserved	for	future	grants	under	the plans.

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

|  | Shares | Weighted<br>Average<br>Exercise<br>Price | Shares | Weighted<br>Average<br>Exercise<br>Price | Shares | Weighted-<br>Average<br>Exercise<br>Price |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Outstanding—beginning\tof\tyear | 15,575 | $16.32 | 16,698 | $10.72 | 17,065 | $8.83 |
| Exercised\tduring\tthe\tyear | (1,507) | 8.95 | (5,069) | 14.11 | (2,817) | 7.45 |
| Forfeited\tduring\tthe\tyear | (1,743) | 42.21 | (129) | 30.85 | (14) | 21.83 |
| Granted\tduring\tthe\tyear | 21,164 | 17.78 | 4,075 | 36.98 | 2,464 | 20.16 |
| Outstanding—end\tof\tyear | 33,489 | 16.55 | 15,575 | 16.32 | 16,698 | 10.72 |
| Eligible\tfor\texercise—end\tof\tyear | 11,845 | $13.38 | 11,449 | $10.51 | 14,086 | $9.44 |

								The	following	table	summarizes	information	about	stock	options	outstanding	at	December	31,	2001	(in	thousands	of	shares):

| Range	of	Exercise	Prices | Total	Outstanding | Weighted-<br>Average<br>Remaining	Life<br>(In	Years) | Weighted-	Average<br>Exercise	Price | Total	Exercisable | Weighted-	Average<br>Exercise	Price |
| :--- | :--- | :--- | :--- | :--- | :--- |
| $\t\t0.78\t–\t$\t\t3.24 | 4 | 0.0 | $1.60 | 4 | $1.60 |
| $\t\t3.25\t–\t$\t\t9.88 | 5,548 | 3.1 | 5.20 | 5,548 | 5.20 |
| $\t\t9.89\t–\t$14.40 | 20,307 | 9.4 | 13.03 | 1,823 | 11.43 |
| $14.41\t–\t$22.85 | 2,887 | 6.6 | 17.93 | 2,869 | 17.94 |
| $22.86\t–\t$58.00 | 4,733 | 8.4 | 44.06 | 1,597 | 35.75 |
| $58.01\t–\t$80.00 | 10 | 8.7 | 61.42 | 4 | 61.66 |
| Total | 33,489 | 7.9 | $16.55 | 11,845 | $13.38 |

								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:

|  | 2001 | 2000 | 1999 |
| :--- | :--- | :--- | :--- |
| Interest\trate\t(risk-free) | 4.84% | 5.4% | 6.5% |
| Volatility | 86% | 41% | 46% |
| Dividend\tyield | — | 1% | — |

								Using	these	assumptions,	and	an	expected	option	life	of	approximately	8	years,	the	weighted	average	fair	value	of	each	stock	option	granted	was	$14.87,	$18.99	and $22.43,	for	the	years	ended	December	31,	2001,	2000	and	1999,	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,	2001,	2000	and	1999	would	have	been	reduced	to	the	following	pro	forma	amounts	(in	millions except	per	share	amounts):

Years	Ended	December	31,

| As	reported | $273 | $795 | $357 |
| :--- | :--- | :--- | :--- |
| Pro\tforma | 229 | 752 | 341 |
| BASIC\tEARNINGS\tPER\tSHARE: |  |  |  |
| As\treported | $0.52 | $1.66 | $0.84 |
| Pro\tforma | 0.43 | 1.56 | 0.81 |
| DILUTED\tEARNINGS\tPER\tSHARE: |  |  |  |
| As\treported | $0.51 | $1.59 | $0.82 |
| Pro\tforma | 0.43 | 1.50 | 0.79 |

								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.

								As	of	December	31,	1999,	the	Company	had	warrants	outstanding	to	purchase	up	to	2.6	million	shares	of	common	stock	at	$7.36	a	share.	These	warrants	expired	in July	2000.	Substantially	all	of	the	warrants	were	exercised	prior	to	expiration.

								COMMON	STOCK	HELD	BY	SUBSIDIARIES—The	Company	has	secured	equity-linked	loans	("SELLS")	of	$350	million	due	in	2003	and	$300	million	due in	2004.	The	loans	were	issued	by	consolidated	subsidiaries	and	have	been	classified	as	non-recourse	debt	in	the	accompanying	consolidated	balance	sheets.	The Company	is	required	to	maintain	as	collateral	2.25	times	the	amount	of	the	SELLS	in	the	form	of	unregistered	AES	common	shares.	Registration	of	the	shares	can	only occur	in	the	event	of	nonpayment	or	failure	to	maintain	adequate	collateral	levels.	An	event	of	default	under	the	Company's	revolver	would	cause	a	cross	default	in	the SELLS	agreements.	As	of	December	31,	2001	and	2000,	approximately	111	million	and	81	million	shares	of	the	Company's	common	stock,	respectively,	had	been issued	to	the	consolidated	subsidiaries.	These	shares	are	not	considered	outstanding	and	therefore	have	been	excluded	from	the	calculation	of	earnings	per	share.

# 12.	EARNINGS	PER	SHARE

								The	following	table	presents	a	reconciliation	of	the	numerators	and	denominators	of	the	basic	and	diluted	earnings	per	share	computations	for	income	from continuing	operations.	In	the	table	below,	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\tEPS\nIncome\tfrom\tcontinuing\toperations | $467 | 532.2 | $0.88 | $827 | 482.1 | $1.72 | $377 | 422.8 | $0.89 |
| EFFECT\tOF\tDILUTIVE\tSECURITIES: |  |  |  |  |  |  |  |  |  |
| Stock\toptions\tand\twarrants | — | 5.3 | (0.01) | — | 9.8 | (0.04) | — | 9.4 | (0.02) |
| Stock\tunits\tallocated\tto\tdeferred\tcompensation\tplans | — | .4 | — | — | 0.5 | — | — | 0.5 | — |
| Tecons\tand\tother\tconvertible\tdebt,\tnet\tof\ttax | 5 | 5.6 | — | 22 | 21.1 | (0.03) | — | — | — |
| DILUTED\tEARNINGS\tSHARE | $472 | 543.5 | $0.87 | $849 | 513.5 | $1.65 | $377 | 432.7 | $0.87 |

								There	were	approximately	4,048,470	and	173,000	options	outstanding	in	2001	and	2000	that	were	omitted	from	the	earnings	per	share	calculation	because	they were	antidilutive.	There	were	no	antidilutive	options	in	1999.

# 13.	SALE	OF	ASSETS

								In	October	1999,	AES	Placerita	Inc.	("Placerita"),	a	wholly	owned	subsidiary	of	the	Company,	received	proceeds	of	approximately	$110	million	to	complete	the buyout	of	its	long-term	power	sales	agreement.	In	connection	with	the	buyout,	the	Company	incurred	transaction	related	costs	of	approximately	$19	million	and recorded	a	gain	on	contract	buyout	of	$91	million.	The	buyout	of	the	power	sales	agreement	resulted	in	the	loss	of	a	significant	customer	and	required	the	Company	to assess	the	recoverability	of	the	carrying	amount	of	Placerita's	electric	generation	assets.	The	Company	recorded	an	impairment	loss	of	approximately	$62	million	to reduce	the	carrying	value	of	the	electric	generation	assets	to	their	estimated	fair	value	after	termination	of	the	contract.	The	estimated	fair	value	was	determined	by	an independent	appraisal.	Concurrent	with	the	buyout	of	the	power	sales	contract,	the	Company	extinguished	certain	liabilities	under	the	related	project	financing	debt	prior to	their	scheduled	maturity.	As	a	result,	the	Company	has	recorded	an	extraordinary	loss	of	approximately	$11	million,	net	of	income	tax	of	approximately	$5	million.

								In	September	1999,	AES	Thames	Inc.	("Thames"),	a	wholly	owned	subsidiary	of	the	Company,	amended	its	power	sales	agreement	with	Connecticut	Light	and Power	("CL&P"),	its	sole	customer.	The	amendment,	which	was	subject	to	regulatory	approval,	includes	a	partial	prepayment	for	certain	electricity	to	be	delivered	by Thames	to	CL&P	in	the	years	2001-2014.	According	to	the	terms	of	the	amendment,	the	Company	will	receive	$532	million	plus	accrued	interest	in	return	for	a reduction	in	future	electricity	rates.	Interest	accrues	on	the	prepayment	at	a	rate	of	8.3%	per	annum	from	the	date	of	regulatory	approval.	In	March	2000,	the	Connecticut Department	of	Public	Utility	Control	("DPUC")	approved	the	amendment	to	the	power	sales	agreement.	In	July	2000,	CL&P	requested	and	subsequently	received approval	from	the	DPUC	to	issue	bonds	to	fund	the	prepayment.	The	contractual	receivable	was	recorded	in	other	current	assets	with	a	corresponding	amount	of	deferred revenue	in	other	liabilities	in	the	accompanying	December	31,	2000	consolidated	balance	sheet.	The	deferred	revenue	is	being	amortized	into	income	on	a	ratable	basis over	the	contract	term	based	on	kilowatt	hours	provided.	Amortization	of	$32	million	was	recorded	for	the	year	ended	December	31,	2001.	The	contractual	receivable was	paid	during	2001.

								On	November	20,	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	($19

million	after	tax).	Of	the	net	proceeds,	$88	million	was	used	to	retire	debt	specifically	assignable	to	the	Thermal	Assets.	The	related	notes	were	retired	in	November 2000.	In	connection	with	the	retirement	of	the	debt,	the	Company	incurred	make-whole	payments	and	wrote	off	debt	issuance	costs	of	approximately	$4	million,	which was	recorded	as	an	extraordinary	loss	in	2000.

								INCOME	TAX	PROVISION—The	provision	for	income	taxes	consists	of	the	following	(in	millions):

|  | 2001 | 2000 | 1999 |
| :--- | :--- | :--- | :--- |
| Federal: |  |  |  |
| Current | $2 | $151 | $70 |
| Deferred | 10 | (29) | 46 |
| State: |  |  |  |
| Current | — | 20 | 11 |
| Deferred | 11 | (2) | 14 |
| Foreign: |  |  |  |
| Current | 181 | 208 | 98 |
| Deferred | 26 | 29 | (48) |
| Total | $230 | $377 | $191 |

								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:

|  | 2001 | 2000 | 1999 |
| :--- | :--- | :--- | :--- |
| Statutory\tFederal\ttax\trate | 35% | 35% | 35% |
| State\ttaxes,\tnet\tof\tFederal\ttax\tbenefit | 2 | 1 | 4 |
| Taxes\ton\tforeign\tearnings | (5) | (3) | (4) |
| Other-net | 1 | (2) | (1) |
| Effective\ttax\trate | 33% | 31% | 34% |

								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,	2001,	the	Company	had	Federal	net	operating	loss	carry	forwards	for	tax	purposes	of	approximately	$412	million	expiring	from	2008	through 2021,	Federal	general	business	tax	credit	carry	forwards	for	tax	purposes	of	approximately	$49	million	expiring	in	years	2005	through	2021,	and	Federal	alternative minimum	tax	credits	of	approximately	$53	million	that	carry	forward	without	expiration.	As	of	December	31,	2001,	the	Company	had	foreign	net	operating	loss	carry forwards	of	approximately	$1.1	billion	that	expire	at	various	times	beginning	in	2002,	and	some	of	which	carry	forward	without	expiration,	and	foreign	investment	and assets	tax	credits	of	approximately	$33	million

that	expire	at	various	times	beginning	in	2002	through	2006.	The	Company	had	state	net	operating	loss	carry	forwards	as	of	December	31,	2001,	of	approximately	$540 million	expiring	in	years	2001	through	2021,	and	state	tax	credit	carry	forwards	of	approximately	$5	million	expiring	in	years	2002	through	2010.

								The	valuation	allowance	decreased	by	$2	million	during	2001	to	$117	million	at	December	31,	2001.	This	decrease	was	primarily	the	result	of	the	utilization	of certain	foreign	net	operating	loss	carry	forwards	for	which	a	valuation	allowance	had	previously	been	established.	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):

|  | 2001 | 2000 |
| :--- | :--- | :--- |
| Differences\tbetween\tbook\tand\ttax\tbasis\tof\tproperty\tand\ttotal\tdeferred\ttax\tliability | $2,671 | $2,562 |
| Operating\tloss\tcarry\tforwards | (482) | (328) |
| Bad\tdebt\tand\tother\tbook\tprovisions | (107) | (104) |
| Retirement\tcosts | (79) | (75) |
| Tax\tcredit\tcarry\tforwards | (139) | (162) |
| Other\tdeductible\ttemporary\tdifferences | (337) | (316) |
| Total\tgross\tdeferred\ttax\tasset | (1,144) | (985) |
| Less:\tValuation\tallowance | 117 | 119 |
| Total\tnet\tdeferred\ttax\tasset | (1,027) | (866) |
| Net\tdeferred\ttax\tliability | $1,644 | $1,696 |

								Undistributed	earnings	of	certain	foreign	subsidiaries	and	affiliates	aggregated	approximately	$1.2	billion	and	$777	million	at	December	31,	2001	and	2000, 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.	A	deferred	tax	asset	of	$192	million	has been	recorded	as	of	December	31,	2001	for	the	cumulative	effects	of	certain	foreign	currency	translation	losses.

								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	$33	million,	$29	million	and	$27	million	for	the	years	ended December	31,	2001,	2000	and	1999,	respectively.

								Income	from	continuing	operations	before	income	taxes	consisted	of	the	following:

|  | 2001 | 2000 | 1999 |
| :--- | :--- | :--- | :--- |
| U.S. | $336 | $631 | 376 |
| Non\tU.S | 361 | 573 | 192 |
| Total | $697 | $1,204 | $568 |

# 15.	BENEFIT	PLANS

								PROFIT	SHARING	AND	STOCK	OWNERSHIP	PLANS—The	Company	sponsors	two	defined	contribution	plans,	qualified	under	section	401	of	the	Internal Revenue	Code,	which	are	available	to	eligible	AES	people.	The	plans	provide	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	$13	million,	$11	million	and	$7	million	for	the	years	ended	December	31,	2001,	2000	and 1999,	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	2001	under	such	plan.

								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	twelve	defined	benefit	plans,	six	are	at	U.S.	subsidiaries	and the	remaining	are	at	foreign	subsidiaries.

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

| Discount	rates | 7% | 8% | 8% |
| :--- | :--- | :--- | :--- |
| Rates\tof\tcompensation\tincrease | 3% | 3% | 4% |
| Expected\tlong-term\trate\tof\treturn\ton\tplan\tassets | 9% | 9% | 9% |

								A	subsidiary	of	the	Company	has	a	defined	benefit	plan,	which	has	a	benefit	obligation	of	$383	million	and	$320	million	at	December	31,	2001	and	2000, 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.

| Service	cost | $9 | $14 | $13 |
| :--- | :--- | :--- | :--- |
| Interest\tcost\ton\tprojected\tbenefit\tobligation | 57 | 55 | 29 |
| Expected\treturn\ton\tplan\tassets | (54) | (63) | (16) |
| Amount\tof\tcurtailment\tloss\trecognized | 6 | 6 | — |
| VERP\tbenefits | 19 | 57 | — |
| Other | 2 | (3) | (3) |
| Total\tpension\tcost | $39 | $66 | $23 |

								The	changes	in	the	benefit	obligation	of	the	plans	combined	for	the	years	ended	December	31,	2001	and	2000	are	as	follows	(in	millions):

|  | 2001 | 2000 |
| :--- | :--- | :--- |
| CHANGE\tIN\tBENEFIT\tOBLIGATION: |  |  |
| Benefit\tobligation\tat\tbeginning\tof\tyear | $810 | $650 |
| Effect\tof\tforeign\tcurrency\texchange\trate\tchange\ton\tbeginning\tbalance | (22) | (10) |
| Service\tcost | 9 | 14 |
| Interest\tcost | 57 | 55 |
| Assumed\tin\tacquisitions | 4 | 71 |
| VERP\tbenefits | 19 | 57 |
| Benefits\tpaid | (58) | (48) |
| Actuarial\tloss | 61 | 19 |
| Other | (11) | 2 |
| Benefit\tobligation\tas\tof\tDecember\t31 | $869 | $810 |

								The	changes	in	the	plan	assets	of	the	plans	combined	for	the	years	ended	December	31,	2001	and	2000	are	as	follows	(in	millions):

|  | 2001 | 2000 |
| :--- | :--- | :--- |
| CHANGE\tIN\tPLAN\tASSETS: |  |  |
| Fair\tvalue\tof\tplan\tassets\tat\tbeginning\tof\tyear | $685 | $714 |
| Effect\tof\tforeign\tcurrency\texchange\trate\tchange\ton\tbeginning\tbalance | (6) | (6) |
| Actual\treturn\ton\tplan\tassets | (32) | 12 |
| Benefits\tpaid | (58) | (48) |
| Other | 15 | 13 |
| Fair\tvalue\tof\tplan\tassets\tas\tof\tDecember\t31 | $604 | $685 |

								The	funded	status	of	the	plans	combined	for	the	years	ended	as	of	December	31,	2001	and	2000	are	as	follows	(in	millions):

|  | 2001 | 2000 |
| :--- | :--- | :--- |
| Funded\tstatus | $(265) | $(125) |
| Unrecognized\tnet\tactuarial\tgain | 53 | (84) |
| Other | 2 | 3 |
| Accrued\tbenefit\tcost\tas\tof\tDecember\t31 | $(210) | $(206) |

								All	of	the	Company's	pension	plans	have	been	aggregated	in	the	table	above.	All	of	the	Company's	plans	at	December	31,	2001,	had	benefit	obligations	exceeding the	fair	value	of	the	related	plan's	assets.	As	of	December	31,	2000,	the	Company	had	plans	with	benefit	obligations	exceeding	the	fair	values	of	plan	assets	by approximately	$165	million.

								In	November	2000,	a	subsidiary	of	the	Company	implemented	a	Voluntary	Early	Retirement	Program	("VERP").	This	program	offers	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	will	total	at	least	75	on June	30,	2001.	Participation	was	limited	to,	and	subsequently	accepted	by	400	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	the	$19	million	and	$57	million	pre-tax	non-cash	pension	benefit	costs	of	the	VERP	in	2001	and	2000, respectively.

								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.

# 16.	SEGMENTS

								The	Company	operates	in	four	business	segments:	contract	generation,	competitive	supply,	large	utilities	and	growth	distribution	businesses.	Contract	generation businesses	are	businesses	that	supply	wholesale	electricity	under	long-term	contracts	for	more	than	75%	of	their	output,	and	these	businesses	generally	have	little exposure	to	commodity	price	risk.	Competitive	supply	businesses	are	businesses	that	supply	electricity,	both	wholesale	and	retail,	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	economics,	unstable	governments	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.	The	Company	previously reported	two	business	segments.	All	prior	year	amounts	have	been	restated	to	reflect	four	business	segments.

								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 | Pre-Tax<br>Equity	in<br>Earnings | Total<br>Assets | in	and<br>Advances	to<br>Affiliates | Property<br>Additions |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Year\tEnded\tDecember\t31,\t2001 |  |  |  |  |  |  |  |
| Contract\tGeneration | $2,466 | $260 | $827 | $54 | $12,306 | $729 | $977 |
| Competitive\tSupply | 2,729 | 196 | 440 | (6) | 10,335 | 46 | 1,684 |
| Large\tUtilities | 2,444 | 289 | 739 | 140 | 9,351 | 2,292 | 420 |
| Growth\tDistribution | 1,688 | 111 | 296 | (13) | 4,300 | 12 | 89 |
| Discontinued\tBusinesses | — | — | — | — | 17 | — | — |
| Corporate | — | 3 | — | — | 427 | 21 | 3 |
| Total | $9,327 | $859 | $2,302 | $175 | $36,736 | $3,100 | $3,173 |
|  |  |  |  |  |  | Investment |  |
|  |  | Depreciation |  | Pre-Tax |  | in\tand |  |
|  |  | and | Gross | Equity\tin | Total | Advances\tto | Property |

|  | Revenues(1) | Amortization | Margin | Earnings | Assets | Affiliates | Additions |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Year\tEnded\tDecember\t31,\t1999 |  |  |  |  |  |  |  |
| Contract\tGeneration | $1,304 | $119 | $551 | $60 | $6,736 | $531 | $534 |
| Competitive\tSupply | 873 | 61 | 245 | — | 7,744 | 1 | 199 |
| Large\tUtilities | 992 | 140 | 282 | (31) | 5,415 | 1,042 | 103 |
| Growth\tDistribution | 948 | 79 | 185 | — | 3,158 | 1 | 102 |
| Corporate | — | 1 | — | — | 145 | — | — |
| Total | $4,117 | $400 | $1,263 | $29 | $23,198 | $1,575 | $938 |

								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):

|  | 2001 | 2000 | 1999 | 2001 | 2000 | 1999 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| United\tStates | $3,522 | $3,353 | $2,056 | $8,169 | $6,727 | $5,636 |
| United\tKingdom | 1,130 | 1,110 | 207 | 4,162 | 4,447 | 4,518 |
| Brazil | 895 | 695 | 376 | 1,958 | 2,076 | 2,283 |
| Argentina | 483 | 482 | 452 | 1,724 | 1,551 | 1,031 |
| Chile | 446 | — | — | 1,023 | — | — |
| Venezuela | 806 | 494 | — | 2,369 | 2,218 | — |
| Dominican\tRepublic | 391 | 333 | 170 | 424 | 225 | 210 |
| El\tSalvador | 341 | 139 | 80 | 250 | 153 | 73 |
| Pakistan | 231 | 232 | 206 | 301 | 319 | 369 |
| Colombia | 124 | — | — | 481 | 41 | — |

| Hungary | 175 | 177 | 212 | 97 | 91 | 120 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Other\tNon-U.S.(1) | 783 | 519 | 358 | 2,476 | 1,394 | 1,026 |
| Total\tNon-U.S. | 5,805 | 4,181 | 2,061 | 15,265 | 12,515 | 9,630 |
| Total | $9,327 | $7,534 | $4,117 | $23,434 | $19,242 | $15,266 |

(1) AES	has	operations	in	18	countries,	which	are	included	in	this	category.

# 17.	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	and	preferred	stock	with	mandatory	redemption,	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,	2001	and	2000	are	as	follows	(in	millions):

|  | Carrying<br>Amount | Fair<br>Value | Carrying<br>Amount | Fair<br>Value |
| :--- | :--- | :--- | :--- | :--- |
| Assets: |  |  |  |  |
| Foreign\tcurrency\tforwards\tand\tswaps,\tnet | $14 | $14 | $10 | $14 |
| Energy\tderivatives,\tnet | 7 | 7 | 25 | (2) |
| Liabilities: |  |  |  |  |
| Non-recourse\tdebt | $16,857 | $17,064 | $15,158 | $15,384 |
| Recourse\tdebt | 5,401 | 4,730 | 3,458 | 3,343 |
| Tecons | 978 | 626 | 1,228 | 1,624 |
| Interest\trate\tswaps | 166 | 166 | 2 | 141 |
| Interest\trate\tcaps\tand\tfloors,\tnet | 72 | 72 | 2 | 7 |
| Preferred\tstock\twith\tmandatory\tredemption | 22 | 22 | 22 | 20 |

								The	fair	value	estimates	presented	herein	are	based	on	pertinent	information	as	of	December	31,	2001	and	2000.	The	Company	is	not	aware	of	any	factors	that would	significantly	affect	the	estimated	fair	value	amounts	since	December	31,	2001.

								In	June	2001,	the	FASB	issued	SFAS	No.	142,	"Goodwill	and	Other	Intangible	Assets."	The	provisions	of	this	statement	are	required	to	be	applied	starting	with fiscal	years	beginning	after	December	15,	2001.	This	statement	is	required	to	be	applied	at	the	beginning	of	an	entity's	fiscal	year	and	to	be	applied	to	all	goodwill	and other	intangible	assets	recognized	in	its	financial	statements	at	that	date.	SFAS	No.	142	addresses	how	intangible	assets	(but	not	those	acquired	in	a	business combination)	should	be	accounted	for	in	financial	statements	upon	their	acquisition.	This	statement	also	addresses	how	goodwill	and	other	intangible	assets	should	be accounted	for	after	they	have	been	initially	recognized	in	the	financial	statements.	The	statement	requires	that	goodwill	and	certain	other	intangibles	with	an	indefinite life,	as	defined	in	the	standard,	no	longer	be	amortized.	However,	goodwill	and	intangibles	would	have	to	be	assessed	each	year	to	determine	whether	an	impairment	loss has	occurred.	Any	impairments	recognized	upon	adoption	would	be	recorded	as	a	change	in	accounting	principle.	Future	impairments	would	be	recorded	in	income from	continuing	operations.	The	statement	provides	specific	guidance	for	testing	goodwill	for	impairment.	The	Company	had	$3.2	billion	of	goodwill	at	December	31, 2001.	Goodwill	amortization	was	$62	million	for	the	year	ended	December	31,	2001.	The	Company	is	currently	assessing	the	impact	of	SFAS	No.	142	on	its	financial position	and	results	of	operations.

								In	June	2001,	the	FASB	issued	SFAS	No.	143,	"Accounting	for	Asset	Retirement	Obligations,"	which	addresses	financial	accounting	and	reporting	for	obligations associated	with	the	retirement	of	tangible	long-lived	assets	and	the	associated	asset	retirement	costs.	This	statement	is	effective	for	financial	statements	issued	for	fiscal years	beginning	after	June	15,	2002.	The	statement	requires	recognition	of	legal	obligations	associated	with	the	retirement	of	long-lived	assets	that	result	from	the acquisition,	construction,	development	and	(or)	the	normal	operation	of	a	long-lived	asset,	except	for	certain	obligations	of	lessees.	The	Company	is	currently	assessing the	impact	of	SFAS	No.	143	on	its	financial	position	and	results	of	operations.

# SELECTED	QUARTERLY	FINANCIAL	DATA	(UNAUDITED)

								The	following	table	summarizes	the	unaudited	quarterly	statements	of	operations	for	the	Company	for	2001	and	2000,	giving	effect	to	the	acquisition	of	IPALCO	as if	it	had	occurred	at	the	beginning	of	the	earliest	period	presented	(in	millions,	except	per	share	amounts).	Additionally,	the	amounts	have	been	adjusted	for	the	early implementation	of	SFAS	No.	144.

|  | Mar	31 | Jun	30 | Sep	30 | Dec	31 |
| :--- | :--- | :--- | :--- | :--- |
| Revenues | $2,495 | $2,184 | $2,261 | $2,387 |
| Gross\tmargin | 637 | 469 | 514 | 682 |
| Income\tfrom\tcontinuing\toperations | 120 | 144 | 13 | 190 |
| Discontinued\toperations | (9) | (29) | (10) | (146) |
| Extraordinary\titems,\tnet\tof\ttax\tbenefit | — | — | — | — |
| Net\tincome | 111 | 115 | 3 | 44 |
| Basic\tearnings\tper\tshare: |  |  |  |  |
| Income\tfrom\tcontinuing\toperations | $0.23 | $0.27 | $0.02 | $0.36 |
| Discontinued\toperations | (0.02) | (0.05) | (0.02) | (0.27) |
| Basic\tearnings\tper\tshare | $0.21 | $0.22 | $0.00 | $0.09 |
| Diluted\tearnings\tper\tshare:\t(1) |  |  |  |  |
| Income\tfrom\tcontinuing\toperations | $0.22 | $0.27 | $0.02 | $0.35 |
| Discontinued\toperations | (0.02) | (0.05) | (0.02) | (0.27) |
| Diluted\tearnings\tper\tshare | $0.20 | $0.22 | $0.00 | $0.08 |

|  | Mar	31 | Jun	30 | Sep	30 | Dec	31 |
| :--- | :--- | :--- | :--- | :--- |
| Revenues | $1,692 | $1,744 | $1,981 | $2,117 |
| Gross\tmargin | 478 | 400 | 532 | 585 |
| Income\tfrom\tcontinuing\toperations | 275 | 144 | 171 | 237 |
| Discontinued\toperations | (1) | (4) | (7) | (9) |
| Extraordinary\titems,\tnet\tof\ttax\tbenefit | (7) | — | — | (4) |
| Net\tincome | 267 | 140 | 164 | 224 |
| Basic\tearnings\tper\tshare: |  |  |  |  |
| Income\tfrom\tcontinuing\toperations | $0.61 | $0.30 | $0.34 | $0.47 |
| Discontinued\toperations | (0.00) | (0.01) | (0.01) | (0.02) |
| Extraordinary\titems | (0.01) | — | — | (0.01) |
| Basic\tearnings\tper\tshare | $0.60 | $0.29 | $0.33 | $0.44 |
| Diluted\tearnings\tper\tshare: |  |  |  |  |
| Income\tfrom\tcontinuing\toperations | $0.57 | $0.29 | $0.33 | $0.46 |
| Discontinued\toperations | (0.00) | (0.01) | (0.01) | (0.02) |
| Extraordinary\titems | (0.01) | — | — | (0.01) |
| Diluted\tearnings\tper\tshare | $0.56 | $0.28 | $0.32 | $0.43 |

(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.

# ITEM	9—CHANGES	IN	AND	DISAGREEMENTS	WITH	ACCOUNTANTS	ON	ACCOUNTING	AND	FINANCIAL	DISCLOSURE.

# 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	1	through	5,	inclusive,	of	the	Proxy	Statement	for	the	Annual	Meeting	of	Stockholders	of	the	Registrant	to	be	held	on	April	25,	2002,	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	I	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	April	25,	2002,	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	April	25,	2002,	which	information	is	incorporated	herein	by	reference.

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

# (c)	Changes	in	Control.

# 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	April	25,	2002,	which	information	is	incorporated	herein	by	reference.

# PART	IV

# ITEM	14—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,	2001	and	2000

Consolidated	Statements	of	Operations	for	the	years	ended	December	31,	2001,	2000	and	1999

Consolidated	Statements	of	Cash	Flows	for	the	years	ended	December	31,	2001,	2000	and	1999

Consolidated	Statements	of	Changes	in	Stockholders'	Equity	for	the	years	ended	December	31,	2001,	2000	and	1999

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.

# (b)	Exhibits.

10.10 The	AES	Corporation	Stock	Option	Plan	for	Outside	Directors	is	incorporated	herein	by	reference	to	Exhibit	10.43	to the	Annual	Report	on	Form	10-K	of	Registrant	for	the	Fiscal	Year	ended	December	31,	1991.

10.11 The	AES	Corporation	Supplemental	Retirement	Plan	is	incorporated	herein	by	reference	to	Exhibit	10.64	to	the Annual	Report	on	Form	10-K	of	the	Registrant	for	the	year	ended	December	31,	1994.

10.12 The	AES	Corporation	2001	Stock	Option	Plan	is	incorporated	herein	by	reference	to	Exhibit	10.12	to	the	Annual Report	on	Form	10-K	of	the	Registrant	for	the	year	ended	December	31,	2000.

								Registrant	filed	a	Current	Report	on	Form	8-K	dated	October	26,	2001	related	to	the	Company's	results	of	operations	for	the	quarter	ended	September	30,	2001.

# 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)

Name:	William	R.	Luraschi

Title:		Senior	Vice	President,	Secretary	and	General

# Counsel

								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.

# Attorney-in-fact

# 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.

# SCHEDULE	I	CONDENSED	FINANCIAL	INFORMATION	OF	REGISTRANT

# STATEMENTS	OF	UNCONSOLIDATED	BALANCE	SHEETS	(IN	MILLIONS)

Preferred	stock

| Common	stock | 5 | 5 |
| :--- | :--- | :--- |
| Additional\tpaid-in\tcapital | 5,225 | 5,172 |
| Retained\tearnings | 2,809 | 2,551 |
| Treasury\tstock | — | (507) |
| Accumulated\tother\tcomprehensive\tloss | (2,500) | (1,679) |
| Total\tstockholders'\tequity | 5,539 | 5,542 |
| Total | $12,041 | $10,309 |

# See	notes	to	Schedule	I

# STATEMENTS	OF	UNCONSOLIDATED	OPERATIONS	(IN	MILLIONS)

|  | 2001 | 2000 | 1999 |
| :--- | :--- | :--- | :--- |
| Revenues\tfrom\tsubsidiaries\tand\taffiliates | $164 | $116 | $85 |
| Equity\tin\tearnings\tof\tsubsidiaries\tand\taffiliates | 340 | 884 | 395 |
| Interest\tincome | 127 | 122 | 89 |
| Selling,\tgeneral\tand\tadministrative\texpenses | (34) | (21) | (44) |
| Interest\texpense | (367) | (255) | (172) |
| Income\tbefore\tincome\ttaxes\tand\textraordinary\titem | 230 | 846 | 353 |
| Income\ttax\t(benefit)\texpense | (43) | 44 | (4) |
| Income\tbefore\textraordinary\titem | 273 | 802 | 357 |
| Extraordinary\titem-loss\ton\textinguishment\tof\tdebt\tnet\tof\tapplicable |  |  |  |
| income\ttax\tbenefit | — | (7) | — |
| Net\tincome | $273 | $795 | $357 |

# STATEMENTS	OF	UNCONSOLIDATED	CASH	FLOWS	(IN	MILLIONS)

|  | 2001 | 2000 | 1999 |
| :--- | :--- | :--- | :--- |
| Net\tcash\tprovided\tby\t(used\tin)\toperating\tactivities | $1,038 | $(37) | $(252) |
| Investing\tActivities |  |  |  |
| Acquisitions | (1,448) | (2,584) | (2,024) |
| Project\tdevelopment\tcosts | — | (7) | (26) |
| Investment\tin\tand\tadvances\tto\tsubsidiaries | (1,283) | (127) | (622) |
| Escrow\tdeposits\tand\tother | — | 3 | (3) |
| Additions\tto\tproperty,\tplant\tand\tequipment | (3) | 2 | — |
| Net\tcash\tused\tin\tinvesting\tactivities | (2,734) | (2,713) | (2,675) |
| Financing\tActivities |  |  |  |
| (Repayments)\tborrowings\tunder\tthe\trevolver,\tnet | (70) | (195) | 102 |
| Issuance\tof\tnotes\tpayable\tand\tother\tcoupon\tbearing\tsecurities,\tnet | 1,754 | 1,610 | 1,524 |
| Proceeds\tfrom\tissuance\tof\tcommon\tstock,\tnet | 14 | 1,449 | 1,305 |
| Payments\tfor\tdeferred\tfinancing\tcosts | (30) | (50) | (39) |
| Net\tcash\tprovided\tby\tfinancing\tactivities | 1,668 | 2,814 | 2,892 |
| (Decrease)\tincrease\tin\tcash\tand\tcash\tequivalents | (28) | 64 | (35) |
| Cash\tand\tcash\tequivalents,\tbeginning\tof\tyear | 73 | 9 | 44 |
| Cash\tand\tcash\tequivalents,\tending\tof\tyear | $45 | $73 | $9 |

# 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	2001	presentation.

# 2.	Notes	Payable

|  | First	Call<br>Date(1) | 2001 | 2000 |
| :--- | :--- | :--- | :--- |
| Revolving\tBank\tLoan:\nVariable\trate\trevolving\tbank\tloan\tdue\t2003 | 2000 | $70 | $140 |
| Term\tLoans: |  |  |  |
| Term\tloan\tdue\t2002 | — | 188 | — |
| Term\tloan\tdue\t2003 | — | 425 | — |
| Total |  | 613 | — |
| Senior\tNotes\tPayable:\n8.75%\tSenior\tnotes\tdue\t2002 | 2002 | 300 | 300 |
| 8.00%\tSenior\tnotes\tdue\t2008 | 2000 | 200 | 200 |
| 8.75%\tSenior\tnotes\tdue\t2008 | — | 400 | — |
| 9.50%\tSenior\tnotes\tdue\t2009 | — | 750 | 750 |
| 9.38%\tSenior\tnotes\tdue\t2010 | — | 850 | 850 |
| 8.88%\tSenior\tnotes\tdue\t2011 | — | 600 | — |
| 8.38%\tSenior\tnotes\tdue\t2011 | — | 196 | — |
| Remarketable\tor\tRedeemable\tSecurities\tdue\t2013 | 2003 | 200 | — |
| Unamortized\tdiscount |  | — | (1) |
| Total |  | 3,496 | 2,099 |
| Senior\tSubordinated\tNotes\tand\tDebentures\tPayable:\n10.25%\tSenior\tsubordinated\tnotes\tdue\t2006 | 2001 | 250 | 250 |
| 8.38%\tSenior\tsubordinated\tnotes\tdue\t2007 | 2002 | 325 | 325 |
| 8.50%\tSenior\tsubordinated\tnotes\tdue\t2007 | 2002 | 375 | 375 |
| 8.88%\tSenior\tsubordinated\tdebentures\tdue\t2027 | 2004 | 125 | 125 |
| Unamortized\tdiscounts |  | (3) | (6) |
| Total |  | 1,072 | 1,069 |
| Junior\tSubordinated\tNotes\tand\tDebentures\tPayable:\n4.50%\tConvertible\tjunior\tsubordinated\tnotes\tdue\t2005 | 2001 | 150 | 150 |
| 6.00%\tConvertible\tjunior\tsubordinated\tdebentures\tdue\t2008 | 2003 | 460 | 460 |
| 6.75%\tConvertible\tjunior\tsubordinated\tdebentures\tdue\t2029 | 2002 | 518 | 518 |
| Variable\trate\tconvertible\tjunior\tsubordinated\tdebentures\tdue\t2007 | 1999 | — | 258 |
| Total |  | 1,128 | 1,386 |
|  |  | 6,379 | 4,694 |
| Less:\tcurrent\tmaturities |  | (488) | — |
| Total\tdebt |  | $5,891 | $4,694 |

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

								In	May	2001,	the	Company	issued	$200	million	of	Remarketable	or	Redeemable	Securities	("ROARS").	The	ROARS	are	scheduled	to	mature	on	June	15,	2013, but	such	maturity	date	may	be	adjusted	to	a	date,	which	shall	be	no	later	than	June	15,	2014.	On	the	First	Remarketing	Date	(June	15,	2003)	or	subsequent	Remarketing dates	thereafter,	the	remarketing	agent,	or	the	Company,	may	elect	to	redeem	the	ROARS	at	100%	of	the	aggregate	principal	amount	and	unpaid	interest,	plus

a	premium	in	certain	circumstances.	The	Company	at	its	option,	may	also	redeem	the	ROARS	subsequent	to	the	First	Remarketing	Date	at	any	time.	Interest	on	the ROARS	accrues	at	7.375%	until	the	First	Remarketing	Date,	and	thereafter	is	set	annually	based	on	market	rate	bids,	with	a	floor	of	5.5%.	The	ROARS	are	senior	notes.

| 2002 | $488 |
| :--- | :--- |
| 2003 | 495 |
| 2004 | — |
| 2005 | 150 |
| 2006 | 250 |
| Thereafter | 4,996 |
| TOTAL | $6,379 |

# 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):

|  | 2001 | 2000 | 1999 |
| :--- | :--- | :--- | :--- |
| Subsidiaries | $1,038 | $428 | $180 |
| Affiliates | 21 | 100 | 51 |

# VALUATION	AND	QUALIFYING	ACCOUNTS	(IN	MILLIONS)

|  | Balance	at<br>Beginning	of<br>Period | Charged	to<br>Costs	and<br>Expenses | Acquisitions/<br>Sale	of	Business | Translation<br>Adjustment | Amounts<br>Written<br>Off |  | Balance	at<br>End	of<br>Period |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Allowance\tfor\taccounts\treceivables: |  |  |  |  |  |  |  |
| Year\tended\tDecember\t31,\t1999 | $59 | $8 | $68 | $(21) $ |  | (10) $ | 104 |
| Year\tended\tDecember\t31,\t2000 | 104 | 72 | 47 | (1) |  | (21) | 201 |
| Year\tended\tDecember\t31,\t2001 | 201 | 137 | (50) | (5) |  | (32) | 251 |

# QuickLinks

ITEM	2—PROPERTIES ITEM	3—LEGAL	PROCEEDINGS

THE	AES	CORPORATION	CONSOLIDATED	BALANCE	SHEETS	DECEMBER	31,	2001	AND	2000 THE	AES	CORPORATION	CONSOLIDATED	STATEMENTS	OF	OPERATIONS	YEARS	ENDED	DECEMBER	31,	2001,	2000	AND	1999 THE	AES	CORPORATION	CONSOLIDATED	STATEMENTS	OF	CASH	FLOWS	YEARS	ENDED	DECEMBER	31,	2001,	2000	AND	1999

THE	AES	CORPORATION	CONSOLIDATED	STATEMENTS	OF	CHANGES	IN	STOCKHOLDERS'	EQUITY	YEARS	ENDED	DECEMBER	31,	2001,	2000 AND	1999

CONSOLIDATED	STATEMENTS	OF	CHANGES	IN	STOCKHOLDERS'	EQUITY	YEARS	ENDED	DECEMBER	31,	2001,	2000	AND	1999

THE	AES	CORPORATION	NOTES	TO	CONSOLIDATED	FINANCIAL	STATEMENTS	DECEMBER	31,	2001,	2000	AND	1999

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

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



Question: what percentage of scheduled maturities of total debt are due after 5 years?
Calculation: maturities_after_5_years = 12806
total_debt = 22258
percent_due_after_5_years = maturities_after_5_years / total_debt
answer = percent_due_after_5_years * 100
Answer: 57.5%