Table	of	Contents

# 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,	2010

¨ TRANSITION	REPORT	FILED	PURSUANT	TO	SECTION	13	OR	15(d)	OF	THE	SECURITIES	EXCHANGE	ACT

COMMISSION	FILE	NUMBER	1-12291

# The	AES	Corporation

(Exact	name	of	registrant	as	specified	in	its	charter)

Delaware

(State	or	other	jurisdiction	of

incorporation	or	organization)

4300	Wilson	Boulevard	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

Common	Stock,	par	value	$0.01	per	share

AES	Trust	III,	$3.375	Trust	Convertible	Preferred	Securities

Name	of	Each	Exchange	on	Which	Registered

New	York	Stock	Exchange

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

Indicate	by	check	mark	if	the	Registrant	is	a	well-known	seasoned	issuer,	as	defined	in	Rule	405	of	the	Securities	Act.				Yes		x				No		¨

Indicate	by	check	mark	if	the	Registrant	is	not	required	to	file	reports	pursuant	to	Section	13	or	Section	15	(d)	of	the	Act.				Yes		¨				No		x

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		x				No		¨

Indicate	by	check	mark	whether	the	registrant	has	submitted	electronically	and	posted	on	its	corporate	Web	site,	if	any,	every	Interactive	Data	File	required	to	be submitted	and	posted	pursuant	to	Rule	405	of	Regulation	S-T	during	the	preceding	12	months	(or	for	such	shorter	period	that	the	registrant	was	required	to	submit	and post	such	files).				Yes		x				No		¨

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.		x Indicate	by	check	mark	whether	the	registrant	is	a	large	accelerated	filer,	an	accelerated	filer,	a	non-accelerated	filer	or	a	smaller	reporting	company.	See	the definitions	of	"large	accelerated	filer,"	"accelerated	filer"	and	"smaller	reporting	company"	in	Rule	12b-2	of	the	Exchange	Act.	(Check	one):

Large	accelerated	filer		x

Accelerated	filer		¨

Non-accelerated	filer		¨

Smaller	reporting	company		¨

(Do	not	check	if	a	smaller

reporting	company)

Indicate	by	check	mark	whether	the	Registrant	is	a	shell	company	(as	defined	in	Rule	12b-2	of	the	Exchange	Act).				Yes		¨				No		x

The	aggregate	market	value	of	the	voting	and	non-voting	common	equity	held	by	non-affiliates	on	June	30,	2010,	the	last	business	day	of	the	Registrant's	most recently	completed	second	fiscal	quarter	(based	on	the	closing	sale	price	of	$9.24	of	the	Registrant's	Common	Stock,	as	reported	by	the	New	York	Stock	Exchange	on such	date)	was	approximately	$7.350	billion.

# DOCUMENTS	INCORPORATED	BY	REFERENCE

Portions	of	Registrant's	Proxy	Statement	for	its	2011	annual	meeting	of	stockholders	are	incorporated	by	reference	in	Parts	II	and	III

| PART	I | 1 |
| :--- | :--- |
| ITEM\t1.\tBUSINESS | 3 |
| Overview | 3 |
| Our\tOrganization\tand\tSegments | 6 |
| Customers | 19 |
| Employees | 19 |
| Executive\tOfficers | 19 |
| How\tto\tContact\tAES\tand\tSources\tof\tOther\tInformation | 20 |
| Regulatory\tMatters | 21 |
| ITEM\t1A.\tRISK\tFACTORS | 73 |
| ITEM\t2.\tPROPERTIES | 97 |
| ITEM\t3.\tLEGAL\tPROCEEDINGS | 97 |
| ITEM\t4.\tREMOVED\tAND\tRESERVED | \t107 |
| PART\tII | \t108 |
| SECURITIES | \t108 |
| Sale\tof\tUnregistered\tSecurities | \t108 |
| Purchases\tof\tEquity\tSecurities\tby\tthe\tIssuer\tand\tAffiliated\tPurchasers | \t108 |
| Market\tInformation | \t109 |
| Holders | \t110 |
| Dividends | \t110 |
| ITEM\t6.\tSELECTED\tFINANCIAL\tDATA | \t111 |
| ITEM\t\t7.\tMANAGEMENT'S\tDISCUSSION\tAND\tANALYSIS\tOF\tFINANCIAL\tCONDITION\tAND\tRESULTS\tOF\tOPERATIONS | \t113 |
| Overview\tof\tOur\tBusiness | \t113 |
| Performance\tHighlights | \t117 |
| Non-GAAP\tMeasures | \t120 |
| Consolidated\tResults\tof\tOperations | \t129 |
| Critical\tAccounting\tEstimates | \t149 |
| New\tAccounting\tPronouncements | \t153 |
| Capital\tResources\tand\tLiquidity | \t154 |
| Off-Balance\tSheet\tArrangements | \t164 |
| ITEM\t7A.\tQUANTITATIVE\tAND\tQUALITATIVE\tDISCLOSURES\tABOUT\tMARKET\tRISK | \t165 |
| ITEM\t8.\tFINANCIAL\tSTATEMENTS\tAND\tSUPPLEMENTARY\tDATA | \t168 |
| ITEM\t9.\tCHANGES\tIN\tAND\tDISAGREEMENTS\tWITH\tACCOUNTANTS\tON\tACCOUNTING\tAND\tFINANCIAL\tDISCLOSURE | \t277 |
| ITEM\t9A.\tCONTROLS\tAND\tPROCEDURES | \t277 |
| ITEM\t9B.\tOTHER\tINFORMATION | \t280 |
| PART\tIII | \t280 |
| ITEM\t10.\tDIRECTORS,\tEXECUTIVE\tOFFICERS\tAND\tCORPORATE\tGOVERNANCE | \t280 |
| ITEM\t11.\tEXECUTIVE\tCOMPENSATION | \t280 |
| ITEM\t\t12.\tSECURITY\tOWNERSHIP\tOF\tCERTAIN\tBENEFICIAL\tOWNERS\tAND\tMANAGEMENT\tAND\tRELATED\tSTOCKHOLDER\tMATTERS | \t280 |
| ITEM\t13.\tCERTAIN\tRELATIONSHIPS\tAND\tRELATED\tPARTY\tTRANSACTIONS\tAND\tDIRECTOR\tINDEPENDENCE | \t282 |
| ITEM\t14.\tPRINCIPAL\tACCOUNTANT\tFEES\tAND\tSERVICES | \t282 |
| PART\tIV | \t283 |
| ITEM\t15.\tEXHIBITS\tAND\tFINANCIAL\tSTATEMENT\tSCHEDULES | \t283 |
| SIGNATURES | \t288 |

# PART	I

In	this	Annual	Report	the	terms	"AES,"	"the	Company,"	"us,"	or	"we"	refer	to	The	AES	Corporation	and	all	of	its	subsidiaries	and	affiliates,	collectively.	The term	"The	AES	Corporation"	and	"Parent	Company"	refers	only	to	the	parent,	publicly-held	holding	company,	The	AES	Corporation,	excluding	its	subsidiaries	and affiliates.

# FORWARD-LOOKING	INFORMATION

In	this	filing	we	make	statements	concerning	our	expectations,	beliefs,	plans,	objectives,	goals,	strategies,	and	future	events	or	performance.	Such	statements	are "forward-looking	statements"	within	the	meaning	of	the	Private	Securities	Litigation	Reform	Act	of	1995.	Although	we	believe	that	these	forward-looking	statements and	the	underlying	assumptions	are	reasonable,	we	cannot	assure	you	that	they	will	prove	to	be	correct.

Forward-looking	statements	involve	a	number	of	risks	and	uncertainties,	and	there	are	factors	that	could	cause	actual	results	to	differ	materially	from	those expressed	or	implied	in	our	forward-looking	statements.	Some	of	those	factors	(in	addition	to	others	described	elsewhere	in	this	report	and	in	subsequent	securities filings)	include:

•the	economic	climate,	particularly	the	state	of	the	economy	in	the	areas	in	which	we	operate,	including	the	fact	that	the	global	economy	faces	considerable uncertainty	for	the	foreseeable	future,	which	further	increases	many	of	the	risks	discussed	in	this	Form	10-K;

•changes	in	inflation,	demand	for	power,	interest	rates	and	foreign	currency	exchange	rates,	including	our	ability	to	hedge	our	interest	rate	and	foreign currency	risk;

•changes	in	the	price	of	electricity	at	which	our	Generation	businesses	sell	into	the	wholesale	market	and	our	Utility	businesses	purchase	to	distribute	to	their customers,	and	the	success	of	our	risk	management	practices,	such	as	our	ability	to	hedge	our	exposure	to	such	market	price	risk;

•changes	in	the	prices	and	availability	of	coal,	gas	and	other	fuels	(including	our	ability	to	have	fuel	transported	to	our	facilities)	and	the	success	of	our	risk management	practices,	such	as	our	ability	to	hedge	our	exposure	to	such	market	price	risk,	and	our	ability	to	meet	credit	support	requirements	for	fuel	and power	supply	contracts;

•changes	in	and	access	to	the	financial	markets,	particularly	changes	affecting	the	availability	and	cost	of	capital	in	order	to	refinance	existing	debt	and finance	capital	expenditures,	acquisitions,	investments	and	other	corporate	purposes;

•our	ability	to	manage	liquidity	and	comply	with	covenants	under	our	recourse	and	non-recourse	debt,	including	our	ability	to	manage	our	significant liquidity	needs	and	to	comply	with	covenants	under	our	senior	secured	credit	facility	and	other	existing	financing	obligations;

•changes	in	our	or	any	of	our	subsidiaries'	corporate	credit	ratings	or	the	ratings	of	our	or	any	of	our	subsidiaries'	debt	securities	or	preferred	stock,	and changes	in	the	rating	agencies'	ratings	criteria;

•our	ability	to	purchase	and	sell	assets	at	attractive	prices	and	on	other	attractive	terms;

•our	ability	to	compete	in	markets	where	we	do	business;

•our	ability	to	manage	our	operation	and	maintenance	costs;

•the	performance	and	reliability	of	our	generating	plants,	including	our	ability	to	reduce	unscheduled	down-times;

•our	ability	to	locate	and	acquire	attractive	"greenfield"	projects	and	our	ability	to	finance,	construct	and	begin	operating	our	"greenfield"	projects	on schedule	and	within	budget;

•our	ability	to	enter	into	long-term	contracts,	which	limit	volatility	in	our	results	of	operations	and	cash	flow,	such	as	power	purchase	agreements,	fuel supply,	and	other	agreements	and	to	manage	counterparty	credit	risks	in	these	agreements;

•variations	in	weather,	especially	mild	winters	and	cooler	summers	in	the	areas	in	which	we	operate,	low	levels	of	wind	or	sunlight	for	our	wind	and	solar businesses,	and	the	occurrence	of	difficult	hydrological	conditions	for	our	hydro-power	plants,	as	well	as	hurricanes	and	other	storms	and	disasters;

•our	ability	to	meet	our	expectations	in	the	development,	construction,	operation	and	performance	of	our	wind	businesses,	which	rely,	in	part,	on	actual	wind conditions	and	wind	turbine	performance	being	in	line	with	our	expectations;

•the	success	of	our	initiatives	in	other	renewable	energy	projects,	as	well	as	greenhouse	gas	emissions	reduction	projects	and	energy	storage	projects;

•our	ability	to	keep	up	with	advances	in	technology;

•the	potential	effects	of	threatened	or	actual	acts	of	terrorism	and	war;

•the	expropriation	or	nationalization	of	our	businesses	or	assets	by	foreign	governments,	whether	with	or	without	adequate	compensation;

•our	ability	to	achieve	expected	rate	increases	in	our	Utility	businesses;

•changes	in	laws,	rules	and	regulations	affecting	our	international	businesses;

•changes	in	laws,	rules	and	regulations	affecting	our	North	America	business,	including,	but	not	limited	to,	deregulation	of	wholesale	power	markets	and	its effects	on	competition,	the	ability	to	recover	net	utility	assets	and	other	potential	stranded	costs	by	our	utilities,	the	establishment	of	a	regional	transmission organization	that	includes	our	utility	service	territory,	the	application	of	market	power	criteria	by	the	Federal	Energy	Regulatory	Commission,	changes	in law	resulting	from	new	federal	energy	legislation,	including	the	effects	of	the	repeal	of	Public	Utility	Holding	Company	Act	of	1935,	and	changes	in political	or	regulatory	oversight	or	incentives	affecting	our	wind	business,	our	solar	joint	venture,	our	other	renewables	projects	and	our	initiatives	in greenhouse	gas	reductions	and	energy	storage	including	tax	incentives;

•changes	in	environmental	laws,	including	requirements	for	reduced	emissions	of	sulfur,	nitrogen,	carbon,	mercury,	coal	ash,	hazardous	air	pollutants	and other	substances,	including	potential	greenhouse	gas	legislation,	regulation	and/or	treaties;

•changes	in	tax	laws	and	the	effects	of	our	strategies	to	reduce	tax	payments;

•the	effects	of	litigation	and	government	and	regulatory	investigations;

•our	ability	to	maintain	adequate	insurance;

•decreases	in	the	value	of	pension	plan	assets,	increases	in	pension	plan	expenses	and	our	ability	to	fund	defined	benefit	pension	and	other	post-retirement plans	at	our	subsidiaries;

•losses	on	the	sale	or	write-down	of	assets	due	to	impairment	events	or	changes	in	management	intent	with	regard	to	either	holding	or	selling	certain	assets;

•changes	in	accounting	standards,	corporate	governance	and	securities	law	requirements;

•our	ability	to	maintain	effective	internal	controls	over	financial	reporting;	and

•our	ability	to	attract	and	retain	talented	directors,	management	and	other	personnel,	including,	but	not	limited	to,	financial	personnel	in	our	foreign businesses	that	have	extensive	knowledge	of	accounting	principles	generally	accepted	in	the	United	States.

These	factors	in	addition	to	others	described	elsewhere	in	this	Form	10-K,	including	those	described	under	Item	1A.—Risk	Factors,	and	in	subsequent	securities filings,	should	not	be	construed	as	a	comprehensive	listing	of	factors	that	could	cause	results	to	vary	from	our	forward	looking	information.

We	undertake	no	obligation	to	publicly	update	or	revise	any	forward-looking	statements,	whether	as	a	result	of	new	information,	future	events,	or	otherwise.	If one	or	more	forward-looking	statements	are	updated,	no	inference	should	be	drawn	that	additional	updates	will	be	made	with	respect	to	those	or	other	forward-looking statements.

# ITEM	1. BUSINESS

# Overview

We	are	a	global	power	company.	We	own	a	portfolio	of	electricity	generation	and	distribution	businesses	on	five	continents	in	28	countries,	with	total	capacity	of approximately	40,500	Megawatts	("MW")	and	distribution	networks	serving	over	12	million	people	as	of	December	31,	2010.	In	addition,	we	have	more	than 2,000	MW	under	construction	in	six	countries.	Our	global	workforce	of	approximately	29,000	people	helps	provide	electricity	to	people	in	diverse	markets	ranging	from urban	centers	in	the	United	States	to	remote	villages	in	India.	We	were	incorporated	in	Delaware	in	1981	and	for	three	decades	we	have	been	committed	to	providing	safe and	reliable	energy.

We	own	and	operate	two	primary	types	of	businesses.	The	first	is	our	Generation	business,	where	we	own	and/or	operate	power	plants	to	generate	and	sell	power to	wholesale	customers	such	as	utilities	and	other	intermediaries.	The	second	is	our	Utilities	business,	where	we	own	and/or	operate	utilities	to	distribute,	transmit	and sell	electricity	to	end-user	customers	in	the	residential,	commercial,	industrial	and	governmental	sectors	within	a	defined	service	area.

Our	assets	are	diverse	with	respect	to	fuel	source	and	type	of	market,	which	helps	reduce	certain	types	of	operating	risk.	Our	portfolio	employs	a	broad	range	of fuels,	including	coal,	gas,	fuel	oil,	biomass	and	renewable	sources	such	as	hydroelectric	power,	wind	and	solar,	which	reduces	the	risks	associated	with	dependence	on any	one	fuel	source.	Our	presence	in	mature	markets	helps	reduce	the	volatility	associated	with	our	businesses	in	faster-growing	emerging	markets.	In	addition,	our Generation	portfolio	is	largely	contracted,	which	reduces	the	risk	related	to	market	prices	of	electricity	and	fuel.	We	also	attempt	to	limit	risk	by	hedging	some	of	our interest	rate	and	commodity	risk,	and	by	matching	the	currency	of	most	of	our	subsidiary	debt	to	the	revenue	of	the	underlying	business.	However,	our	business	is	still subject	to	these	and	other	risks,	which	are	further	described	in	Item	1A.—Risk	Factors	of	this	Form	10-K.

Our	goal	is	to	maximize	value	for	our	shareholders	through	continued	focus	on	increasing	the	profitability	of	our	existing	portfolio	and	increasing	cash	flow	while managing	our	risk	and	employing	rigorous	capital	allocation.	We	will	continue	to	seek	prudent	expansion	of	our	traditional	Generation	and	Utilities	lines	of	business, along	with	expansion	of	wind,	solar	and	energy	storage,	through	acquisitions	or	greenfield	developments.	Portfolio	management	remains	an	area	of	focus	through	which we	have	sold	and	expect	to	continue	to	sell	or	monetize	a	portion	of	certain	businesses	or	assets	when	market	values	appear	attractive.	Furthermore,	we	will	continue	to focus	on	improving	our	business	operations	and	management	processes,	including	our	internal	controls	over	financial	reporting.

# Key	Lines	of	Business

AES'	primary	sources	of	revenue	and	gross	margin	today	are	from	Generation	and	Utilities.	These	businesses	are	distinguished	by	the	nature	of	the	customers, operational	differences,	cost	structure,	regulatory	environment	and	risk	exposure.	The	breakout	of	revenue	and	gross	margin	between	Generation	and	Utilities	for	the years	ended	December	31,	2010,	2009	and	2008,	respectively,	is	shown	below.	Operating	results	for	integrated	utilities,	which	have	both	Generation	and	Utilities,	are reflected	in	the	Utilities	amounts	below.

# Revenue

# ($	in	billions)

# Gross	Margin

Utilities	gross	margin	includes	the	margin	from	generation	businesses	owned	by	the	Company	and	from	whom	the	utility	purchases	energy.

# Generation

We	currently	own	or	operate	a	generation	portfolio	of	approximately	34,100	MW,	excluding	the	generation	capabilities	of	our	integrated	utilities,	consisting	of 100	Generation	facilities	in	25	countries	on	five	continents	at	our	generation	businesses.	We	also	have	approximately	1,700	MW	of	capacity	currently	under	construction in	four	countries.	We	are	a	major	power	source	in	many	countries,	such	as	Panama	where	we	are	the	largest	generator	of	electricity,	and	Chile,	where	AES	Gener ("Gener")	is	the	second	largest	electricity	generation	company	in	terms	of	capacity.	Our	Generation	business	uses	a	wide	range	of	technologies	and	fuel	types	including coal,	combined-cycle	gas	turbines,	hydroelectric	power	and	biomass.	Generation	revenue	was	$7.5	billion,	$6.1	billion	and	$7.4	billion	for	the	years	ended	December	31, 2010,	2009	and	2008,	respectively.

Performance	drivers	for	our	Generation	businesses	include,	among	other	factors,	plant	reliability,	fuel	costs,	power	prices,	volume	and	fixed-cost	management. Growth	in	the	Generation	business	is	largely	tied	to	securing	new	power	purchase	agreements	("PPAs"),	expanding	capacity	in	our	existing	facilities	and	building	or acquiring	new	power	plants.

The	majority	of	the	electricity	produced	by	our	Generation	businesses	is	sold	under	long-term	PPAs,	to	wholesale	customers.	In	2010,	approximately	64%	of	the revenue	from	our	Generation	business	was	from	plants	that	operate	under	PPAs	of	three	years	or	longer	for	75%	or	more	of	their	output	capacity.	These	businesses	often reduce	their	exposure	to	fuel	supply	risks	by	entering	into	long-term	fuel	supply	contracts	or	fuel	tolling	arrangements	where	the	customer	assumes	full	responsibility	for purchasing	and	supplying	the	fuel	to	the	power	plant.	These	long-term	contractual	agreements	help	reduce	the	volatility	of	our	cash	flows	and	earnings	and	also	reduce exposure	to	volatility	in	the	market	price	for	electricity	and	fuel;	however,	the	amount	of	earnings	and	cash	flow	predictability	varies	from	business	to	business	based	on the	degree	to	which	its	exposure	is	limited	by	the	contracts	it	has	negotiated.

Our	Generation	businesses	with	long-term	contracts	face	most	of	their	competition	from	other	utilities	and	independent	power	producers	("IPPs")	prior	to	the execution	of	a	power	sales	agreement	during	the	development	phase	of	a	project	or	upon	expiration	of	an	existing	agreement.	Once	a	project	is	operational,	we traditionally	have	faced	limited	competition	due	to	the	long-term	nature	of	the	generation	contracts.	However,	as	our	existing	contracts	expire,	the	introduction	of	new power	markets	has	increased	competition	to	attract	new	customers	and	maintain	our	current	customer	base.

The	balance	of	our	Generation	business	sells	power	through	competitive	markets	under	short-term	contracts,	directly	in	the	spot	market	or,	in	some	cases,	at regulated	prices.	As	a	result,	the	cash	flows	and	earnings	associated	with	these	businesses	are	more	sensitive	to	fluctuations	in	the	market	price	for	electricity,	natural	gas, coal	and	other	fuels.	Competitive	factors	for	these	facilities	include	price,	reliability,	operational	cost	and	third-party	credit	requirements.

# Utilities

AES	utility	businesses	distribute	power	to	over	12	million	people	in	seven	countries	on	five	continents	and	consist	primarily	of	14	companies	owned	or	operated under	management	agreements,	each	of	which	operate	in	defined	service	areas.	These	businesses	also	include	15	generation	plants	in	two	countries	with	generation capacity	totaling	approximately	4,600	MW.	These	businesses	have	a	variety	of	structures	ranging	from	pure	distribution	businesses	to	fully	integrated	utilities,	which generate,	transmit	and	distribute	power.	For	instance,	our	wholly	owned	subsidiary	in	the	U.S.,	Indianapolis	Power	&	Light	("IPL"),	has	the	exclusive	right	to	provide retail	services	to	approximately	470,000	customers	in	Indianapolis,	Indiana.	Eletropaulo	Metropolitana	Electricidad	de	São	Paulo	S.A	("AES	Eletropaulo"	or "Eletropaulo"),	serving	the	São	Paulo	metropolitan	region	for	over	100	years,	has	approximately	six	million	customers	and	is	the	largest	electricity	distribution	company in	Brazil	in	terms	of	revenue	and	electricity	distributed.	In	Cameroon,	we	are	the	primary	generator	and	distributor	of	electricity	and	in	El	Salvador	we	provide distribution	services	to	serve	more	than	77%	of	the	country's	electricity	customers.	Utilities	revenue	was	$9.1	billion,	$7.8	billion	and	$7.8	billion	for	the	years	ended December	31,	2010,	2009	and	2008,	respectively.

Performance	drivers	for	Utilities	include,	but	are	not	limited	to,	reliability	of	service,	management	of	working	capital,	negotiation	of	tariff	adjustments, compliance	with	extensive	regulatory	requirements,	and	in	developing	countries,	reduction	of	commercial	and	technical	losses.	The	results	of	operations	of	our	Utilities businesses	are	sensitive	to	changes	in	economic	growth,	regulations	and	variations	in	weather	conditions	in	the	areas	in	which	they	operate.

Utilities	face	relatively	little	direct	competition	due	to	significant	barriers	to	entry	which	are	present	in	these	markets.	In	certain	locations,	our	distribution businesses	face	increased	competition	as	a	result	of	changes	in	laws	and	regulations	which	allow	wholesale	and	retail	services	to	be	provided	on	a	competitive	basis. Competition	is	a	factor	in	efforts	to	acquire	existing	businesses.	In	this	arena,	we	compete	against	a	number	of	other	market	participants,	some	of	which	have	greater financial	resources,	have	been	engaged	in	distribution	related	businesses	for	longer	periods	of	time	and/or	have	accumulated	more	significant	portfolios.	Relevant competitive	factors	for	our	power	distribution	businesses	include	financial	resources,	governmental	assistance,	regulatory	restrictions	and	access	to	non-recourse financing.

# Renewables	and	Other	Initiatives

In	recent	years,	as	demand	for	renewable	sources	of	energy	has	grown,	we	have	placed	increasing	emphasis	on	developing	projects	in	wind,	solar	and	other renewable	initiatives	including	energy	storage.	In	2005,	we	started	a	wind	generation	business	("AES	Wind	Generation"),	which	currently	has	20	plants	in	operation	in five	countries	totaling	approximately	1,800	MW	in	generation	capacity	and	is	one	of	the	largest	producers	of	wind	power	in	the	U.S.	In	addition,	264	MW	are	under construction	in	four	countries.	In	March	2008,	we	formed	AES	Solar	Energy	LLC	("AES	Solar"),	a	joint	venture	with	Riverstone	Holdings,	LLC	("Riverstone"),	a private	equity	firm,	which	has	since	commenced	commercial	operations	of	nine	plants	totaling	37	MW	of	solar	projects	in	France,	Greece	and	Spain.	We	have	a	few projects	producing	GHG	credits	in	Asia,	Europe	and	Latin	America.	We	also	have	a	line	of	business	to	develop	and	implement	utility	scale	energy	storage	systems	(such as	batteries),	which	store	and	release	power	when	needed.	While	none	of	these	initiatives	are	currently	material	to	our	operations,	we	believe	that	as	these	businesses grow,	they	may	become	a	material	contributor	to	our	operations.	However,	there	are	risks	associated	with	these	initiatives,	which	are	further	described	in	Item	1A.— Risk	Factors	of	this	Form	10-K.	As	further	described	in	"Our	Organization	and	Segments"	below,	some	of	these	projects	are	managed	within	the	region	in	which	they are	located,	while	others	are	managed	as	separate	business	units	and	reported	as	set	forth	below.

# Risks

We	routinely	encounter	and	address	risks,	some	of	which	may	cause	our	future	results	to	be	different,	sometimes	materially	different,	than	we	presently	anticipate. The	categories	of	risk	we	have	identified	in	Item	1A.—Risk	Factors	of	this	Form	10-K	include	the	following:

•risks	associated	with	our	disclosure	controls	and	internal	controls	over	financial	reporting;

•risks	related	to	our	high	level	of	indebtedness;

•risks	associated	with	our	ability	to	raise	needed	capital;

•external	risks	associated	with	revenue	and	earnings	volatility;

•risks	associated	with	our	operations;	and

•risks	associated	with	governmental	regulation	and	laws.

The	categories	of	risk	identified	above	are	discussed	in	greater	detail	in	Item	1A.—Risk	Factors	of	this	Form	10-K.	These	risk	factors	should	be	read	in conjunction	with	Item	7.—Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations,	and	the	Consolidated	Financial	Statements	and related	notes	included	elsewhere	in	this	report.

# Our	Organization	and	Segments

We	believe	our	broad	geographic	footprint	allows	us	to	focus	development	in	targeted	markets	with	opportunities	for	new	investment,	and	provides	stability through	our	presence	in	more	developed	regions.	In	addition,	our	presence	in	each	region	affords	us	important	relationships	and	helps	us	identify	local	markets	with attractive	opportunities	for	new	investment.	As	a	result,	we	have	structured	our	organization	into	geographic	regions,	and	each	region	is	led	by	a	regional	president	or other	senior	executive	responsible	for	managing	those	businesses.	The	regional	presidents	report	to	our	Chief	Operating	Officer	("COO"),	who	in	turn	reports	to	our Chief	Executive	Officer	("CEO").	Both	our	CEO	and	COO	are	based	in	Arlington,	Virginia.

The	Company's	segment	reporting	structure	is	organized	along	our	two	lines	of	business	(Generation	and	Utilities)	and	three	regions:	(1)	Latin	America	&	Africa; (2)	North	America;	and	(3)	Europe,	Middle	East	&	Asia	(collectively,	"EMEA"),	which	reflects	how	we	manage	the	business	internally.	Additionally,	AES	Wind Generation	is	managed	within	our	North	America	region.	For	financial	reporting	purposes,	the	Company	has	six	reportable	segments	which	include:

# •Latin	America—Generation;

•Latin	America—Utilities;

•	 North	America—Generation;

•	 North	America—Utilities;

•Europe—Generation;

# •	 Asia—Generation.

Corporate	and	Other—The	Company's	Europe	Utilities,	Africa	Utilities,	Africa	Generation	and	AES	Wind	Generation	businesses	as	well	as	the	Company's renewables	initiatives	are	reported	within	"Corporate	and	Other"	because	they	do	not	require	separate	disclosure	under	segment	reporting	accounting	guidance.	See Item	7.—Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations	for	further	discussion	of	the	Company's	segment	structure	used	for financial	reporting	purposes.

The	following	describes	our	businesses	as	they	are	aligned	in	our	segment	reporting	structure	for	financial	reporting	purposes.

# Latin	America

Our	Latin	America	operations	accounted	for	69%,	70%	and	68%	of	consolidated	AES	revenue	in	2010,	2009	and	2008,	respectively.	The	following	table	provides highlights	of	our	Latin	America	operations:

The	graph	below	shows	the	breakdown	between	our	Latin	America	Generation	and	Utilities	segments	as	a	percentage	of	total	Latin	America	revenue	and	gross margin	for	the	years	ended	December	31,	2010,	2009,	and	2008.	See	Note	15—Segment	and	Geographic	Information	in	the	Consolidated	Financial	Statements	in	Item	8 of	this	Form	10-K	for	information	on	revenue	from	external	customers,	Adjusted	Gross	Margin	(a	non-GAAP	measure)	and	total	assets	by	segment.

Latin	America	Generation.	Our	largest	generation	business	in	Latin	America,	AES	Tietê	("Tietê"),	located	in	Brazil,	represents	approximately	18%	of	the	total generation	capacity	in	the	state	of	São	Paulo	and	is	the	tenth	largest	generator	in	Brazil.	AES	holds	a	24%	economic	interest	in	Tietê.	In	Argentina,	we	are	the	third largest

private	power	generator	contributing	11%	of	the	country's	total	power	generation	capacity.	In	Chile,	we	are	the	second	largest	generator	of	power.	We	currently	have three	new	generation	plants	under	construction—two	coal	plants	in	Chile	and	one	hydro	plant	in	Panama	with	a	combined	generation	capacity	of	1,011	MW.

Set	forth	below	is	a	list	of	our	Latin	America	Generation	facilities:

|  |  |  |  | AES	Equity | Year |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | Interest | Acquired |
|  |  |  | Gross | (Percent, | or\tBegan |
| Business | Location | Fuel | MW | Rounded) | Operation |
| Alicura | Argentina | Hydro | 1,050 | 99% | 2000 |
| Central\tDique | Argentina | Gas/Diesel | 68 | 51% | 1998 |
| Gener—TermoAndes | Argentina | Gas/Diesel | 643 | 71% | 2000 |
| Los\tCaracoles^(1) | Argentina | Hydro | 125 | 0% | 2009 |
| Paraná-GT | Argentina | Gas/Diesel | 845 | 99% | 2001 |
| Quebrada\tde\tUllum^(1) | Argentina | Hydro | 45 | 0% | 2004 |
| Rio\tJuramento—Cabra\tCorral | Argentina | Hydro | 102 | 99% | 1995 |
| Rio\tJuramento—El\tTunal | Argentina | Hydro | 10 | 99% | 1995 |
| San\tJuan—Sarmiento | Argentina | Gas/Diesel | 33 | 99% | 1996 |
| San\tJuan—Ullum | Argentina | Hydro | 45 | 99% | 1996 |
| San\tNicolás | Argentina | Coal/Gas/Oil | 675 | 99% | 1993 |
| Tietê^(2) | Brazil | Hydro | 2,657 | 24% | 1999 |
| Uruguaiana | Brazil | Gas | 639 | 46% | 2000 |
| Gener—Electrica\tSantiago^(3) | Chile | Gas/Diesel | 479 | 64% | 2000 |
| Gener—Electrica\tVentanas^(4) | Chile | Coal | 272 | 71% | 2010 |
| Gener—Energía\tVerde^(5) | Chile | Biomass/Diesel | 49 | 71% | 2000 |
| Gener—Gener^(6) | Chile | Hydro/Coal/Diesel | 953 | 71% | 2000 |
| Gener—Guacolda^(7),(8) | Chile | Coal/Pet\tCoke | 608 | 35% | 2000 |
| Gener—Norgener | Chile | Coal/Pet\tCoke | 277 | 71% | 2000 |
| Chivor | Colombia | Hydro | 1,000 | 71% | 2000 |
| Andres | Dominican\tRepublic | Gas | 319 | 100% | 2003 |
| Itabo^(9) | Dominican\tRepublic | Coal | 295 | 50% | 2000 |
| Los\tMina | Dominican\tRepublic | Gas | 236 | 100% | 1996 |
| Bayano | Panama | Hydro | 260 | 49% | 1999 |
| Chiriqui—Esti | Panama | Hydro | 120 | 49% | 2003 |
| Chiriqui—La\tEstrella | Panama | Hydro | 48 | 49% | 1999 |
| Chiriqui—Los\tValles | Panama | Hydro | 54 | 49% | 1999 |

AES	operates	these	facilities	through	management	or	operations	and	maintenance	("O&M")	agreements	and	owns	no	equity	interest	in	these	businesses.

Tietê	plants:	Água	Vermelha,	Bariri,	Barra	Bonita,	Caconde,	Euclides	da	Cunha,	Ibitinga,	Limoeiro,	Mog-Guaçu,	Nova	Avanhandava,	Promissão	and	seven	other small	hydroelectric	plants	below	Tietê's	wholly-owned	subsidiary	"PCH	Minas	Ltda".

Gener—Electrica	Santiago	plants:	Nueva	Renca	and	Renca.

Gener—Electrica	Ventanas	plant:	Nueva	Ventanas.

Gener—Energia	Verde	Plants:	Constitución,	Laja	and	San	Francisco	de	Mostazal.

Gener—Gener	plants:	Alfalfal,	Laguna	Verde,	Laguna	Verde	Turbogas,	Los	Vientos,	Maitenas,	Queltehues,	Santa	Lidia,	Ventanas	and	Volcán.

Gener—Guacolda	plants:	Guacolda	1,	Guacolda	2,	Guacolda	3	and	Guacolda	4.

Unconsolidated	entities,	the	results	of	operations	of	which	are	reflected	in	Equity	in	Earnings	of	Affiliates.

Itabo	plants:	Itabo	complex	(two	coal-fired	steam	turbines	and	one	gas-fired	steam	turbine).

# Generation	under	construction

|  |  |  | Gross | (Percent, | Commercial |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Business | Location | Fuel | MW | Rounded) | Operations |
| Angamos | Chile | Coal | 518 | 71% | 2011 |
| Campiche | Chile | Coal | 270 | 71% | 2013 |
| Changuinola\tI | Panama | Hydro | 223 | 100% | 2011 |

Latin	America	Utilities.	Each	of	our	Utilities	businesses	in	Latin	America	sells	electricity	under	regulated	tariff	agreements	and	has	transmission	and	distribution capabilities	but	none	of	them	has	generation	capability.	AES	Eletropaulo,	a	consolidated	subsidiary	of	which	AES	owns	a	16%	economic	interest	and	which	has	served the	São	Paulo,	Brazil	area	for	over	100	years,	has	approximately	six	million	customers	and	is	the	largest	electricity	distribution	company	in	Brazil	in	terms	of	revenue and	electricity	distributed.	Pursuant	to	its	concession	agreement,	AES	Eletropaulo	is	entitled	to	distribute	electricity	in	its	service	area	until	2028.	AES	Eletropaulo's service	territory	consists	of	24	municipalities	in	the	greater	São	Paulo	metropolitan	area	and	adjacent	regions	that	account	for	approximately	17%	of	Brazil's	GDP	and 40%	of	the	population	in	the	State	of	São	Paulo.	AES	Sul	("Sul"),	a	wholly-owned	subsidiary,	serves	over	one	million	customers.	In	El	Salvador,	our	Utilities businesses	provide	electricity	to	over	81%	of	the	country,	serving	more	than	one	million	customers.

Set	forth	below	is	a	list	of	our	Latin	America	Utilities	facilities:

# Distribution

|  |  | Number	of |  | AES	Equity |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  | Customers | GWh | Interest |  |
| Business | Location | Served\tas\tof\n12/31/2010 | Sold\tin\n2010 | (Percent,\nRounded) | Year\nAcquired |
| Edelap | \tArgentina | 329,000 | 2,776 | 90% | 1998 |
| Edes | \tArgentina | 172,000 | 894 | 90% | 1997 |
| Eletropaulo | \tBrazil | \t5,832,000 | \t33,860 | 16% | 1998 |
| Sul | \tBrazil | \t1,181,474 | 8,320 | 100% | 1997 |
| CAESS | \tEl\tSalvador | 516,000 | 2,060 | 75% | 2000 |
| CLESA | \tEl\tSalvador | 304,000 | 786 | 64% | 1998 |
| DEUSEM | \tEl\tSalvador | 62,000 | 108 | 74% | 2000 |
| EEO | \tEl\tSalvador | 229,000 | 476 | 89% | 2000 |
|  |  | \t8,625,474 | \t49,280 |  |  |

# North	America

Our	North	America	operations	accounted	for	19%,	22%	and	22%	of	consolidated	revenue	in	2010,	2009	and	2008,	respectively.	The	following	table	provides highlights	of	our	North	America	operations:

The	graph	below	shows	the	breakdown	between	our	North	America	Generation	and	Utilities	segments	as	a	percentage	of	total	North	America	revenue	and	gross margin	for	the	years	ended	December	31,	2010,	2009	and	2008.	See	Note	15—Segment	and	Geographic	Information	in	the	Consolidated	Financial	Statements	in	Item	8 of	this	Form	10-K	for	information	on	revenue	from	external	customers,	Adjusted	Gross	Margin	(a	non-GAAP	measure)	and	total	assets	by	segment.

North	America	Generation.	Approximately	86%	of	the	generation	capacity	is	supported	by	long-term	power	purchase	or	tolling	agreements.	Our	North	America Generation	business	consists	of	six	gas-fired,	ten	coal-fired	and	three	petroleum	coke-fired	plants	in	the	United	States,	Puerto	Rico	and	Mexico.

Our	largest	generation	business	is	AES	Southland.	This	business	operates	three	gas-fired	plants,	representing	generation	capacity	of	4,327	MW,	in	the	Los Angeles	basin	under	a	long-term	tolling	agreement.	In	addition,	in	the	Western	New	York	power	market,	AES	Eastern	Energy	operates	four	of	our	coal-fired	plants, Cayuga,	Greenidge,	Somerset	and	Westover,	representing	generation	capacity	of	1,169	MW,	providing	power	to	this	market	under	short-term	contracts,	as	well	as	in	the spot	electricity	market.

Set	forth	below	is	a	list	of	our	North	America	Generation	facilities:

|  |  |  | Gross | (Percent, | or	Began |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Business | Location | Fuel | MW | Rounded) | Operation |
| Mérida\tIII | Mexico | Gas | 484 | 55% | 2000 |
| Termoelectrica\tdel\tGolfo\t(TEG) | Mexico | Pet\tCoke | 230 | 99% | 2007 |
| Termoelectrica\tdel\tPeñoles\t(TEP) |  | Pet |  |  |  |
|  | Mexico | Coke | 230 | 99% | 2007 |
| Southland—Alamitos | USA—CA | Gas | \t2,047 | 100% | 1998 |
| Southland—Huntington\tBeach | USA—CA | Gas | 904 | 100% | 1998 |
| Southland—Redondo\tBeach | USA—CA | Gas | \t1,376 | 100% | 1998 |
| Thames | USA—CT | Coal | 208 | 100% | 1990 |
| Hawaii | USA—HI | Coal | 203 | 100% | 1992 |
| Warrior\tRun | USA—MD | Coal | 205 | 100% | 2000 |
| Red\tOak | USA—NJ | Gas | 832 | 100% | 2002 |
| Cayuga | USA—NY | Coal | 306 | 100% | 1999 |
| Greenidge | USA—NY | Coal | 106 | 100% | 1999 |
| Somerset | USA—NY | Coal | 675 | 100% | 1999 |
| Westover | USA—NY | Coal | 82 | 100% | 1999 |
| Shady\tPoint | USA—OK | Coal | 360 | 100% | 1991 |
| Beaver\tValley | USA—PA | Coal | 125 | 100% | 1985 |
| Ironwood | USA—PA | Gas | 710 | 100% | 2001 |
| Puerto\tRico | USA—PR | Coal | 454 | 100% | 2002 |
| Deepwater |  | Pet |  |  |  |
|  | USA—TX | Coke | 160 | 100% | 1986 |

North	America	Utilities.	AES	has	one	integrated	utility	in	North	America,	IPL,	which	it	owns	through	IPALCO	Enterprises	Inc.	("IPALCO"),	the	parent	holding company	of	IPL.	IPL	generates,	transmits,	distributes	and	sells	electricity	to	approximately	470,000	customers	in	the	city	of	Indianapolis	and	neighboring	areas	within the	state	of	Indiana.	IPL	owns	and	operates	four	generation	facilities	that	provide	more	than	96%	of	the	electricity	it	distributes.	Two	of	the	generation	facilities	are	coal- fired	plants.	The	third	facility	has	a	combination	of	units	that	use	coal	(base	load	capacity)	and	natural	gas	and/or	oil	(peaking	capacity).	The	fourth	facility	is	a	small peaking	station	that	uses	gas-fired	combustion	turbine	technology.	IPL's	gross	generation	capacity	is	3,699	MW.	Approximately	45%	of	IPL's	coal	is	provided	by	one supplier	with	which	IPL	has	long-term	contracts.	A	key	driver	for	the	business	is	tariff	recovery	for	environmental	projects	through	the	rate	adjustment	process.	IPL's customers	include	residential,	industrial,	commercial	and	all	other	which	made	up	37%,	40%,	15%	and	8%,	respectively,	of	North	America	Utilities	revenue	for	2010.

# IPL's	generation	facilities

| Business | Location | Approximate<br>Number	of<br>Customers<br>Served	as	of<br>12/31/2010 | GWh<br>Sold	in<br>2010 | AES	Equity<br>Interest<br>(Percent,<br>Rounded) |
| :--- | :--- | :--- | :--- | :--- |
| IPL | USA—IN | 470,000 | \t16,537 | 100% |

# Europe

The	following	table	provides	highlights	of	our	Europe	operations:

Our	Utilities	operations	in	Europe	are	discussed	further	under	Corporate	and	Other	below.

Europe	Generation.	Our	Generation	operations	in	Europe	accounted	for	8%,	6%	and	8%	of	our	consolidated	revenue	in	2010,	2009	and	2008,	respectively.	In 2007,	we	began	commercial	operation	of	AES	Cartagena	("Cartagena"),	our	first	power	plant	in	Spain,	with	capacity	of	1,199	MW.	As	a	result	of	the	new	accounting guidance	for	variable	interest	entities,	the	Company	consolidated	Cartagena	effective	January	1,	2010.	In	prior	periods,	the	results	of	operations	for	Cartagena	were included	in	the	Equity	in	Earnings	of	Affiliates	line	item	on	the	Consolidated	Statements	of	Operations.	Today,	AES	operates	four	power	plants	in	Kazakhstan	which account	for	8%	of	the	country's	total	installed	generation	capacity.	In	September	2009,	AES	completed	construction	and	launched	commercial	operation	of	the	380	MW combined-cycle	Amman	East	power	plant	in	Jordan.	See	Note	15—Segment	and	Geographic	Information	in	the	Consolidated	Financial	Statements	in	Item	8	of	this Form	10-K	for	revenue,	Adjusted	Gross	Margin	(a	non-GAAP	measure)	and	total	assets	by	segment.	Key	business	drivers	of	this	segment	are:	foreign	currency exchange	rates,	new	legislation	and	regulations	including	those	related	to	the	environment.

Set	forth	below	is	a	list	of	our	Europe	Generation	facilities:

|  |  |  |  | AES	Equity | Year |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | Interest | Acquired |
|  |  |  | Gross | (Percent, | or\tBegan |
| Business | Location | Fuel | MW | Rounded) | Operation |
| Bohemia | \tCzech\tRepublic | \tCoal/Biomass | 50 | 100% | 2001 |
| Borsod | \tHungary | \tBiomass/Coal | 71 | 100% | 1996 |
| Tisza\tII | \tHungary | \tGas/Oil | 900 | 100% | 1996 |
| Tiszapalkonya | \tHungary | \tCoal/Biomass | 90 | 100% | 1996 |
| Amman\tEast | \tJordan | \tGas | 380 | 37% | 2008 |
| Shulbinsk\tHPP^(1) | \tKazakhstan | \tHydro | 702 | 0% | 1997 |
| Sogrinsk\tCHP | \tKazakhstan | \tCoal | 301 | 100% | 1997 |
| Ust—Kamenogorsk\tHPP^(1) | \tKazakhstan | \tHydro | 331 | 0% | 1997 |
| Ust—Kamenogorsk\tCHP | \tKazakhstan | \tCoal | \t1,354 | 100% | 1997 |
| Elsta^(2) | \tNetherlands | \tGas | 630 | 50% | 1998 |
| Cartagena | \tSpain | \tGas | \t1,199 | 71% | 2006 |
| Damlapinar^(2)(3) | \tTurkey | \tHydro | 16 | 51% | 2010 |
| Girlevik\tII-Mercan^(2) | \tTurkey | \tHydro | 12 | 51% | 2007 |
| Kepezkaya^(2)(3) | \tTurkey | \tHydro | 28 | 51% | 2010 |
| Yukari-Mercan^(2) | \tTurkey | \tHydro | 14 | 51% | 2007 |
| Ballylumford | \tUnited\tKingdom | \tNatural\tGas | \t1,246 | 100% | 2010 |
| Kilroot^(4) | \tUnited\tKingdom | \tCoal/Gas/Oil | 662 | 99% | 1992 |

AES	operates	these	facilities	under	concession	agreements	until	2017.

Joint	Venture	with	I.C.	Energy.

Includes	Kilroot	Open	Cycle	Gas	Turbine	("OCGT").

|  |  |  | Gross | (Percent, | Commercial |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Business | Location | Fuel | MW | Rounded) | Operation |
| Maritza\tEast^(1) | \tBulgaria | \tCoal | \t670 | 100% | 2011 |
| Kumkoy^(2) | \tTurkey | \tHydro | 18 | 51% | 2011 |
| Niksar^(2) | \tTurkey | \tHydro | 40 | 51% | 2011 |

Construction	of	the	Maritza	East	facility	is	currently	on	hold.	For	further	discussion	please	see	Item	7.—Management's	Discussion	and	Analysis—Key	Trends and	Uncertainties	and	Item	1A.—Risk	Factors,	"Our	business	is	subject	to	substantial	development	uncertainties."

Joint	Venture	with	I.C.	Energy.	The	joint	venture	is	an	unconsolidated	entity,	the	results	of	operations	of	which	are	reflected	in	Equity	in	Earnings	of	Affiliates.

Our	Asia	operations	accounted	for	4%,	3%	and	2%	of	consolidated	revenue	in	2010,	2009	and	2008,	respectively.	Asia's	Generation	business	operates	9	power plants	with	a	total	capacity	of	4,103	MW	in	four	countries.	In	Asia,	AES	operates	generation	facilities	only.	See	Note	15—Segment	and	Geographic	Information	in	the Consolidated	Financial	Statements	in	Item	8	of	this	Form	10-K	for	revenue,	Adjusted	Gross	Margin	(a	non-GAAP	measure)	and	total	assets	by	segment.	The	following table	provides	highlights	of	our	Asia	operations:

Asia	Generation.	In	2010,	the	Company	closed	the	sales	of	our	businesses	in	Oman,	Pakistan	and	Qatar.	See	Note	21—Discontinued	Operations	and	Held	for Sale	Businesses	in	Item	8	of	this	Form	10-K	for	further	information	on	these	sales.	More	than	half	of	our	remaining	generation	capacity	in	Asia	is	located	in	China.	In 1996,	AES	joined	with	Chinese	partners	to	build	Yangcheng,	the	first	"coal-by-wire"	power	plant	with	the	generation	capacity	of	2,100	MW.	In	April	2008,	the Company	completed	the	purchase	of	a	92%	interest	in	a	660	MW	coal-fired	thermal	power	generation	facility	in	Masinloc,	Philippines	("Masinloc").

Set	forth	below	is	a	list	of	our	generation	facilities	in	Asia:

|  |  |  |  | AES	Equity | Year |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | Interest | Acquired |
|  |  |  | Gross | (Percent, | or\tBegan |
| Business | Location | Fuel | MW | Rounded) | Operation |
| Aixi | \tChina | \tCoal | 51 | 71% | 1998 |
| Chengdu^(1) | \tChina | \tGas | 50 | 35% | 1997 |
| Cili | \tChina | \tHydro | 25 | 51% | 1994 |
| JHRH^(1) | \tChina | \tHydro | 379 | 35% | 2010 |
| Wuhu^(1),(2) | \tChina | \tCoal | 250 | 25% | 1996 |
| Yangcheng^(1) | \tChina | \tCoal | \t2,100 | 25% | 2001 |
| OPGC^(1) | \tIndia | \tCoal | 420 | 49% | 1998 |
| Masinloc | \tPhilippines | \tCoal | 660 | 92% | 2008 |
| Kelanitissa | \tSri\tLanka | \tDiesel | 168 | 90% | 2003 |

AES	agreed	to	sell	its	25%	equity	interest	in	this	business	on	August	11,	2010.	The	disposal	was	approved	by	the	government	authority	on	December	6,	2010.

# Corporate	and	Other

"Corporate	and	Other"	includes	the	net	operating	results	from	our	Utilities	businesses	in	Africa	and	Europe,	Africa	Generation	and	AES	Wind	Generation	and other	renewables	projects.	These	operations	do	not	require	separate	segment	disclosure.	The	following	provides	additional	details	about	our	Utilities	businesses	in	Africa and	Europe,	Africa	generation	and	AES	Wind	Generation,	which	are	reported	within	"Corporate	and	Other"	for	financial	reporting	purposes.

Europe	Utilities.	Our	distribution	businesses	in	the	Ukraine	and	Kazakhstan	together	serve	approximately	1.8	million	customers.

| Business | Location | Number	of<br>Customers<br>Served	as	of<br>12/31/2010 | GWh<br>Sold	in<br>2010 | AES	Equity<br>Interest<br>(Percent,<br>Rounded) | Year<br>Acquired |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Eastern\tKazakhstan\tREC^(1)(2) | \tKazakhstan | 459,000 | \t3,444 | 0% |  |
| Ust-Kamenogorsk\tHeat\tNets^(1)(3) | \tKazakhstan | 96,000 | — | 0% |  |
| Kievoblenergo | Ukraine | 861,828 | \t4,557 | 89% | 2001 |
| Rivneenergo | Ukraine | 405,934 | \t1,903 | 84% | 2001 |
|  |  | \t1,822,762 | \t9,904 |  |  |

AES	operates	these	businesses	through	management	agreements	and	owns	no	equity	interest	in	these	businesses.

Shygys	Energo	Trade,	a	retail	electricity	company,	is	100%	owned	by	Eastern	Kazakhstan	REC	("EK	REC")	and	purchases	distribution	service	from	EK	REC and	electricity	in	the	wholesale	electricity	market	and	resells	to	the	distribution	customers	of	EK	REC.

Ust-Kamenogorsk	Heat	Nets	provide	transmission	and	distribution	of	heat	with	a	total	heat	generating	capacity	of	224	Gcal.

Africa	Utilities.	AES	owns	a	56%	interest	in	an	integrated	utility,	Société	Nationale	d'Electricité	("Sonel").	Sonel	generates,	transmits	and	distributes	electricity	to over	half	a	million	people	and	is	the	sole	distributor	of	electricity	in	Cameroon.

Set	forth	below	is	a	list	of	the	generation	and	distribution	facilities	of	Sonel:

# Sonel's	generation	facilities

|  |  |  |  | AES	Equity | Year |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | Interest | Acquired |
|  |  |  | Gross | (Percent, | or\tBegan |
| Business | Location | Fuel | MW | Rounded) | Operation |
| Sonel^(1) | \tCameroon | \t Hydro/\tDiesel/Heavy\tFuel\tOil | \t936 | 56% | 2001 |

Sonel	plants:	Bafoussam,	Bassa,	Djamboutou,	Edéa,	Lagdo,	Limbé,	Logbaba	I,	Logbaba	II,	Oyomabang	I,	Oyomabang	II,	Song	Loulou,	and	other	small	remote network	units.

# Sonel's	distribution	facility

Africa	Generation.	Set	forth	below	is	a	list	of	our	generation	facilities	in	Africa.

|  |  |  | Gross | (Percent, | or	Began |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Business | Location | Fuel | MW | Rounded) | Operation |
| Dibamba | \tCameroon | \tHeavy\tFuel\tOil | 86 | 56% | 2009 |
| Ebute | \tNigeria | \tGas | \t294 | 95% | 2001 |

Wind	Generation.	We	own	and	operate	1,538	MW	of	wind	generation	capacity	and	operate	an	additional	215	MW	of	capacity	through	operating	and	management agreements.	Our	wind	business	is	located	primarily	in	North	America	where	we	operate	wind	generation	facilities	that	have	generation	capacity	of	1,269	MW.

Set	forth	below	is	a	list	of	AES	Wind	Generation	facilities:

|  |  |  |  | AES	Equity | Year |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | Interest | Acquired\tor |
|  |  | Power | Gross | (Percent, | Began |
| Business | Location | Source | MW | Rounded) | Operation |
| St.\tNikola | \tBulgaria | \tWind | 156 | 89% | 2010 |
| Dong\tQi^(1),(3) | \tChina | \tWind | 49 | 49% | 2010 |
| Huanghua\tI^(1),(3) | \tChina | \tWind | 49 | 49% | 2009 |
| Huanghua\tII^(1),(3) | \tChina | \tWind | 49 | 49% | 2010 |
| Hulunbeier^(1),(3) | \tChina | \tWind | 49 | 49% | 2008 |
| InnoVent^(2),(3) | \tFrance | \tWind | 75 | 40% | \t2003-2009 |
| St.\tPatrick | \tFrance | \tWind | 35 | 100% | 2010 |
| North\tRhins | \tScotland | \tWind | 22 | 100% | 2010 |
| Altamont | \tUSA—CA | \tWind | 40 | 100% | 2005 |
| Mountain\tView\tI\t&amp;\tII^(4) | \tUSA—CA | \tWind | 67 | 100% | 2008 |
| Palm\tSprings | \tUSA—CA | \tWind | 30 | 100% | 2005 |
| Tehachapi | \tUSA—CA | \tWind | 58 | 100% | 2007 |
| Storm\tLake\tII^(4) | \tUSA—IA | \tWind | 78 | 100% | 2007 |
| Lake\tBenton\tI^(4) | \tUSA—MN | \tWind | 106 | 100% | 2007 |
| Condon^(4) | \tUSA—OR | \tWind | 50 | 100% | 2005 |
| Armenia\tMountain^(4) | \tUSA—PA | \tWind | 101 | 100% | 2009 |
| Buffalo\tGap\tI^(4) | \tUSA—TX | \tWind | 121 | 100% | 2006 |
| Buffalo\tGap\tII^(4) | \tUSA—TX | \tWind | 233 | 100% | 2007 |
| Buffalo\tGap\tIII^(4) | \tUSA—TX | \tWind | 170 | 100% | 2008 |
| Wind\tgeneration\tfacilities^(5) | \tUSA | \tWind | 215 | 0% | 2005 |

# Joint	Venture	with	Guohua	Energy	Investment	Co.	Ltd.

InnoVent	plants:	Bignan,	Chepy,	Croixrault-Moyencourt,	Frenouville,	Gapree,	Grand	Fougeray,	Guehenno,	Hargicourt,	Hescamps,	LePortal,	Les	Diagots,	Nibas,

Plechatel,	Saint-Hilaire	la	Croix	and	Valhoun.	InnoVent	owns	various	percentages	of	underlying	projects.

AES	owns	these	assets	together	with	third	party	tax	equity	investors	with	variable	ownership	interests.	The	tax	equity	investors	receive	a	portion	of	the	economic attributes	of	the	facilities,	including	tax	attributes	that	vary	over	the	life	of	the	projects.	The	proceeds	from	the	issuance	of	tax	equity	are	recorded	as Noncontrolling	Interest	in	the	Company's	Consolidated	Balance	Sheets.

AES	operates	these	facilities	through	management	or	O&M	agreements	and	owns	no	equity	interest	in	these	businesses.

# AES	Wind	Generation	projects	under	construction

InnoVent	plants:	Allery,	Audrieu,	Lamballe,	Lefaux	and	Vron.	InnoVent	owns	various	percentages	of	underlying	projects.

Other.	AES	Solar	and	certain	other	unconsolidated	businesses	are	accounted	for	using	the	equity	method	of	accounting.	Therefore,	their	operating	results	are included	in	"Net	Equity	in	Earnings	of	Affiliates"	on	the	face	of	the	Consolidated	Statements	of	Operations,	not	in	revenue	and	gross	margin.	AES	Solar	was	formed	in March	2008	to	develop,	own	and	operate	solar	installations.	Since	its	launch,	AES	Solar	has	commenced	commercial	operations	of	37	MW	of	solar	projects	in	France, Greece	and	Spain,	has	75	MW	under	construction	in	Italy,	and	has	development	potential	in	Bulgaria,	India	and	the	U.S.

"Corporate	and	Other"	also	includes	general	and	administrative	expenses	related	to	corporate	staff	functions	and	initiatives,	executive	management,	business development,	finance,	legal,	human	resources	and	information	systems	which	are	not	allocable	to	our	business	segments	and	the	effects	of	eliminating	transactions,	such as	self	insurance	charges,	between	the	operating	segments	and	corporate.	See	Note	15—Segment	and	Geographic	Information	in	the	Consolidated	Financial	Statements in	Item	8	of	this	Form	10-K	for	information	on	revenue	from	external	customers,	Adjusted	Gross	Margin	(a	non-GAAP	measure)	and	total	assets	by	segment.

# Financial	Data	by	Country

The	table	below	presents	information,	by	country,	about	our	consolidated	operations	for	each	of	the	three	years	ended	December	31,	2010,	2009	and	2008, respectively,	and	property,	plant	and	equipment	as	of	December	31,	2010	and	2009,	respectively.	Revenue	is	recognized	in	the	country	in	which	it	is	earned	and	assets are	reflected	in	the	country	in	which	they	are	located.

|  | Revenue | Revenue | Revenue | Property,	Plant	&amp;	Equipment,	net | Property,	Plant	&amp;	Equipment,	net |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2010 | 2009 | 2008 | \t\t\t\t\t\t\t\t2010 | \t\t\t\t\t\t\t\t2009 |
|  |  |  | (in\tmillions) |  |  |
| United\tStates | $2,615 | $2,545 | $2,745 | $6,167 | $7,016 |
| Non-U.S.: |  |  |  |  |  |
| Brazil | 6,473 | 5,394 | 5,501 | 6,413 | 5,799 |
| Chile | 1,355 | 1,239 | 1,349 | 2,560 | 2,321 |
| Argentina | 887 | 684 | 949 | 459 | 448 |
| El\tSalvador | 648 | 619 | 484 | 261 | 254 |
| Dominican\tRepublic | 535 | 429 | 601 | 625 | 634 |
| Philippines^(1) | 501 | 250 | 148 | 784 | 765 |
| Cameroon | 422 | 370 | 379 | 823 | 742 |
| Spain^(2) | 411 | — | — | 667 | — |
| Mexico | 409 | 329 | 463 | 786 | 802 |
| Colombia | 393 | 347 | 291 | 387 | 390 |
| United\tKingdom | 385 | 241 | 342 | 527 | 433 |
| Ukraine | 356 | 286 | 403 | 86 | 80 |
| Hungary | 296 | 317 | 466 | 80 | 196 |
| Puerto\tRico | 253 | 267 | 251 | 596 | 609 |
| Panama | 194 | 168 | 210 | 921 | 834 |
| Kazakhstan | 138 | 123 | 234 | 63 | 48 |
| Jordan | 120 | 104 | 47 | 224 | 231 |
| Sri\tLanka | 100 | 109 | 184 | 69 | 74 |
| Bulgaria^(3) | 44 | — | — | 1,825 | 1,835 |
| Qatar^(4) | — | — | — | — | — |
| Pakistan^(5) | — | — | — | — | — |
| Oman^(6) | — | — | — | — | — |
| Other\tNon-U.S. | 112 | 133 | 150 | 298 | 285 |
| Total\tNon-U.S. | \t 14,032 | \t 11,409 | \t 12,452 | 18,454 | 16,780 |
| Total | $16,647 | $13,954 | $15,197 | $24,621 | $23,796 |

Masinloc	was	acquired	in	April	2008;	2008	revenue	represents	results	for	a	partial	year.

Cartagena	was	consolidated	effective	January	1,	2010	upon	implementation	of	the	variable	interest	entity	accounting	guidance.

Maritza	East	and	our	wind	project	in	Bulgaria	were	under	development	and	therefore	not	operational	as	of	December	31,	2009.	Our	wind	project	in	Bulgaria started	operations	in	2010.

Excludes	revenue	of	$129	million,	$163	million	and	$161	million	for	the	years	ended	December	31,	2010,	2009	and	2008,	respectively,	and	property,	plant	and equipment	of	$501	million	as	of	December	31,	2009	related	to	Ras	Laffan,	which	was	reflected	as	discontinued	operations	and	businesses	held	for	sale	in	the accompanying	Consolidated	Statements	of	Operations	and	Consolidated	Balance	Sheets.

Excludes	revenue	of	$299	million,	$470	million	and	$607	million	for	the	years	ended	December	31,	2010,	2009	and	2008,	respectively,	and	property,	plant	and equipment	of	$36	million	as	of	December	31,	2009	related	to	Lal	Pir	and	Pak	Gen,	which	were	reflected	as	discontinued	operations	and	businesses	held	for	sale	in the	accompanying	Consolidated	Statements	of	Operations	and	Consolidated	Balance	Sheets.

Excludes	revenue	of	$62	million,	$101	million	and	$105	million	for	the	years	ended	December	31,	2010,	2009	and	2008,	respectively,	and	property,	plant	and equipment	of	$311	million	as	of	December	31,	2009,	related	to	Barka,	which	was	reflected	as	discontinued	operations	and	businesses	held	for	sale	in	the accompanying	Consolidated	Statements	of	Operations	and	Consolidated	Balance	Sheets.

# Customers

We	sell	to	a	wide	variety	of	customers.	No	individual	customer	accounted	for	10%	or	more	of	our	2010	total	revenue.	In	our	generation	business,	we	own	and/or operate	power	plants	to	generate	and	sell	power	to	wholesale	customers	such	as	utilities	and	other	intermediaries.	Our	utilities	sell	to	end-user	customers	in	the residential,	commercial,	industrial	and	governmental	sectors	in	a	defined	service	area.

# Employees

# Executive	Officers

The	following	individuals	are	our	executive	officers:

Paul	Hanrahan,	53	years	old,	has	been	the	President,	CEO	and	a	member	of	our	Board	of	Directors	since	2002.	Prior	to	assuming	his	current	position, Mr.	Hanrahan	was	the	Executive	Vice	President	and	COO.	In	this	role,	he	was	responsible	for	managing	all	aspects	of	business	development	activities	and	the	operation of	multiple	electric	utilities	and	generation	facilities	in	Europe,	Asia	and	Latin	America.	Mr.	Hanrahan	was	previously	the	President	and	CEO	of	the	AES	China Generating	Company,	Ltd.,	a	public	company	formerly	listed	on	NASDAQ.	Mr.	Hanrahan	also	has	managed	other	AES	businesses	in	the	United	States,	Europe	and Asia.	In	March	2006,	he	was	elected	to	the	board	of	directors	of	Corn	Products	International,	Inc.	Prior	to	joining	AES,	Mr.	Hanrahan	served	as	a	line	officer	on	the	U.S. fast	attack	nuclear	submarine,	USS	Parche	(SSN-683).	Mr.	Hanrahan	is	a	graduate	of	Harvard	Business	School	and	the	U.S.	Naval	Academy.

Andres	R.	Gluski,	53	years	old,	has	been	an	Executive	Vice	President	and	COO	of	the	Company	since	March	2007.	Prior	to	becoming	the	COO	of	AES, Mr.	Gluski	was	Executive	Vice	President	and	the	Regional	President	of	Latin	America	from	2006	to	2007.	Mr.	Gluski	was	Senior	Vice	President	for	the	Caribbean	and Central	America	from	2003	to	2006,	CEO	of	La	Electricidad	de	Caracas	("EDC")	from	2002	to	2003	and	CEO	of	AES	Gener	(Chile)	in	2001.	Prior	to	joining	AES	in 2000,	Mr.	Gluski	was	Executive	Vice	President	and	CFO	of	EDC,	Executive	Vice	President	of	Banco	de	Venezuela	(Grupo	Santander),	Vice	President	for	Santander Investment,	and	Executive	Vice	President	and	CFO	of	CANTV	(subsidiary	of	GTE).	Mr.	Gluski	has	also	worked	with	the	International	Monetary	Fund	in	the	Treasury and	Latin	American	Departments	and	served	as	Director	General	of	the	Ministry	of	Finance	of	Venezuela.	Mr.	Gluski	currently	serves	on	the	Board	of	Directors	of Cliffs	Natural	Resources,	The	Council	of	Americas,	US	Spain	Business	Council	and	The	Edison	Electric	Institute	and	is	Chairman	of	AES	Gener	and	AES Brasiliana.	Mr.	Gluski	is	a	graduate	of	Wake	Forest	University	and	holds	an	M.A	and	a	Ph.D	in	Economics	from	the	University	of	Virginia.

Ned	Hall,	51	years	old,	has	been	an	Executive	Vice	President,	Regional	President	for	North	America	and	Chairman,	Global	Wind	Generation	and	Energy	Storage since	June	2008.	In	August	of	2009,	Mr.	Hall	joined	the	Board	of	AES	Solar	Energy,	Ltd.,	a	joint	venture	between	AES	and	Riverstone	Holdings	LLC.	Prior	to	his current	position,	Mr.	Hall	was	Vice	President	of	the	Company	and	President,	Global	Wind	Generation	from	April	2005	to	June	2008,	Managing	Director	of	AES	Global Development	from	September	2003	to	April	2005,	and	was	an	AES	Group	Manager	from	April	2001	to	September	2003.	Mr.	Hall	joined	AES	in	1988	as	a	Project Manager	working	in	the	Development	Group	and	has	held	a	variety	of	development	and	operating	roles	for	AES,	including	assignments	in	the	U.S.,	Europe,	Asia	and Latin	America.	He	is	a	registered	professional	engineer	in	the	Commonwealth	of	Massachusetts.	Mr.	Hall	holds	a	BSME	degree	from	Tufts	University	and	an	MBA degree	in	finance/operations	management	from	the	MIT	Sloan	School	of	Management.

Victoria	D.	Harker,	46	years	old,	has	been	an	Executive	Vice	President	and	CFO	since	January	2006.	Prior	to	joining	the	Company,	Ms.	Harker	held	the positions	of	Acting	CFO,	Senior	Vice	President	and	Treasurer	of	MCI	from	November	2002	to	January	2006.	Prior	to	that,	Ms.	Harker	served	as	CFO	of	MCI	Group,	a unit	of	WorldCom	Inc.,	from	1998	to	2002.	Prior	to	1998,	Ms.	Harker	held	several	positions	at	MCI	in	the	areas	of	finance,	information	technology	and	operations.	In November	of	2009,	she	was	elected	to	the	board	of	directors	of	Darden	Restaurants,	Inc.	She	has	also	been	a	member	of	the	University	of	Virginia	Board	of	Managers since	2007	and	the	board	of	the	Wolf	Trap	Foundation	for	the	Performing	Arts	since	2009.	Ms.	Harker	received	a	Bachelor	of	Arts	degree	in	English	and	Economics from	the	University	of	Virginia	and	a	Masters	in	Business	Administration,	Finance	from	American	University.

Brian	A.	Miller,	45	years	old,	is	an	Executive	Vice	President	of	the	Company,	General	Counsel,	and	Corporate	Secretary.	Since	November	of	2010,	Mr.	Miller has	also	served	as	the	co-head	of	the	Company's	Development	Steering	Committee.	Mr.	Miller	joined	the	Company	in	2001	and	has	served	in	various	positions including	Vice	President,	Deputy	General	Counsel,	Corporate	Secretary,	General	Counsel	for	North	America	and	Assistant	General	Counsel.	In	March	of	2008, Mr.	Miller	joined	the	Board	of	AES	Solar	Energy,	Ltd.,	a	joint	venture	between	AES	and	Riverstone	Holdings	LLC.	In	2009,	he	joined	the	board	of	AgCert International	Limited	and	AgCert	Canada	Holding	Limited.	Prior	to	joining	AES,	he	was	an	attorney	with	the	law	firm	Chadbourne	&	Parke,	LLP.	Mr.	Miller	received	a bachelor's	degree	in	History	and	Economics	from	Boston	College	and	holds	a	Juris	Doctorate	from	the	University	of	Connecticut	School	of	Law.

Richard	Santoroski,	46	years	old,	became	an	Executive	Vice	President	in	February	2010	and	has	led	the	Company's	Global	Risk	&	Commodity	Organization since	February	2008.	Since	November	of	2010,	he	has	also	served	as	co-head	of	the	Company's	Development	Steering	Committee.	Prior	to	his	current	position, Mr.	Santoroski	was	Vice	President,	Energy	&	Natural	Resources,	a	business	development	group,	and	Vice	President,	Risk	Management.	Mr.	Santoroski	joined	AES	in January	1999	to	lead	AES	Eastern	Energy's	commodity	management.	Prior	to	AES,	Mr.	Santoroski	held	various	engineering,	trading	and	risk	management	positions	at New	York	State	Electric	&	Gas,	including	leading	the	energy	trading	group.	He	graduated	from	Pennsylvania	State	University	with	a	Bachelor	of	Science	in	Electrical Engineering,	and	earned	an	MBA	and	a	Master	of	Science	in	Electrical	Engineering	from	Syracuse	University.	Mr.	Santoroski	is	a	Licensed	Professional	Engineer	in	the State	of	New	York.

Andrew	Vesey,	55	years	old,	is	Executive	Vice	President	and	Regional	President	of	Latin	America	and	Africa.	He	has	held	that	position	since	April	2009.	Prior	to this,	Mr.	Vesey	was	Executive	Vice	President	and	Regional	President	for	Latin	America	from	March	2008	through	March	2009	and	Chief	Operating	Officer	for	Latin America	from	July	2007	through	February	2008.	Mr.	Vesey	also	served	as	Vice	President	and	Group	Manager	for	AES	Latin	America,	DR-CAFTA	Region	from	2006 to	2007,	Vice	President	of	the	Global	Business	Transformation	Group	from	2005	to	2006,	and	Vice	President	of	the	Integrated	Utilities	Development	Group	from	2004 to	2005.	Prior	to	joining	the	Company	in	2004,	Mr.	Vesey	was	a	Managing	Director	of	the	Utility	Finance	and	Regulatory	Advisory	Practice	at	FTI	Consulting	Inc.,	a partner	in	the	Energy,	Chemicals	and	Utilities	Practice	of	Ernst	&	Young	LLP,	and	CEO	and	Managing	Director	of	Citipower	Pty	of	Melbourne,	Australia.	He	received his	BA	in	Economics	and	BS	in	Mechanical	Engineering	from	Union	College	in	Schenectady,	New	York	and	his	MS	from	New	York	University.

# How	to	Contact	AES	and	Sources	of	Other	Information

Our	principal	offices	are	located	at	4300	Wilson	Boulevard,	Arlington,	Virginia	22203.	Our	telephone	number	is	(703)	522-1315.	Our	website	address	is http://www.aes.com.	Our	annual	reports	on	Form	10-K,	quarterly	reports	on	Form	10-Q	and	current	reports	on	Form	8-K	and	any	amendments	to	such	reports	filed pursuant	to	Section	13(a)	or	Section	15(d)	of	the	Securities	Exchange	Act	of	1934	(the	"Exchange	Act")	are	posted	on	our	website.	After	the	reports	are	filed	with,	or furnished	to,	the	Securities	and	Exchange	Commission	("SEC"),	they	are	available	from	us	free	of	charge.	Material	contained	on	our	website	is	not	part	of	and	is	not incorporated	by	reference	in	this	Form	10-K.	You	may	also	read	and	copy	any	materials	we	file	with	the	SEC	at

the	SEC's	Public	Reference	Room	at	100	F	Street,	N.E.,	Washington,	D.C.	20549.	You	may	obtain	information	about	the	operation	of	the	Public	Reference	Room	by calling	the	SEC	at	1-800-SEC-0330.	The	SEC	maintains	an	internet	website	that	contains	the	reports,	proxy	and	information	statements	and	other	information	that	we file	electronically	with	the	SEC	at	www.sec.gov.

Our	CEO	and	our	CFO	have	provided	certifications	to	the	SEC	as	required	by	Section	302	of	the	Sarbanes-Oxley	Act	of	2002.	These	certifications	are	included	as exhibits	to	this	Annual	Report	on	Form	10-K.

Our	CEO	provided	a	certification	pursuant	to	Section	303A	of	the	New	York	Stock	Exchange	Listed	Company	Manual	on	May	21,	2010.

Our	Code	of	Business	Conduct	("Code	of	Conduct")	and	Corporate	Governance	Guidelines	have	been	adopted	by	our	Board	of	Directors.	The	Code	of	Conduct	is intended	to	govern,	as	a	requirement	of	employment,	the	actions	of	everyone	who	works	at	AES,	including	employees	of	our	subsidiaries	and	affiliates.	Our	Ethics	and Compliance	Department	provides	training,	information,	and	certification	programs	for	AES	employees	related	to	the	Code	of	Conduct.	The	Ethics	and	Compliance Department	also	has	programs	in	place	to	prevent	and	detect	criminal	conduct,	promote	an	organizational	culture	that	encourages	ethical	behavior	and	a	commitment	to compliance	with	the	law,	and	to	monitor	and	enforce	AES	policies	on	corruption,	bribery,	money	laundering	and	associations	with	terrorists	groups.	The	Code	of Conduct	and	the	Corporate	Governance	Guidelines	are	located	in	their	entirety	on	our	website	at	http://www.aes.com.	Any	person	may	obtain	a	copy	of	the	Code	of Conduct	or	the	Corporate	Governance	Guidelines	without	charge	by	making	a	written	request	to:	Corporate	Secretary,	The	AES	Corporation,	4300	Wilson	Boulevard, Arlington,	VA	22203.	If	any	amendments	to,	or	waivers	from,	the	Code	of	Conduct	or	the	Corporate	Governance	Guidelines	are	made,	we	will	disclose	such amendments	or	waivers	on	our	website.

# Regulatory	Matters

In	each	country	where	we	conduct	business,	we	are	subject	to	extensive	and	complex	governmental	regulations	which	affect	most	aspects	of	our	business,	such	as regulations	governing	the	generation	and	distribution	of	electricity	and	environmental	regulations.	These	regulations	affect	the	operation,	development,	growth	and ownership	of	our	businesses.	Regulations	differ	on	a	country-by-country	basis	and	are	based	upon	the	type	of	business	we	operate	in	a	particular	country.

# Regulation	of	our	Generation	Businesses

Our	Generation	businesses	operate	in	two	different	types	of	regulatory	environments:	Market	Environments	and	Other	Environments.

Market	Environments.	In	market	environments,	sales	of	electricity	may	be	made	directly	on	the	spot	market,	under	negotiated	bilateral	contracts,	or	pursuant	to PPAs.	The	spot	markets	are	typically	administered	by	a	central	dispatch	or	system	operator	who	seeks	to	optimize	the	use	of	the	generation	resources	throughout	an interconnected	system	(the	cost	of	the	least	expensive	next-generation	plant	required	to	meet	system	demand).	The	spot	price	is	usually	set	at	the	marginal	cost	of	energy or	based	on	bid	prices.	In	addition,	many	of	these	wholesale	markets	include	markets	for	ancillary	services	to	support	the	reliable	operation	of	the	transmission	system, such	as	regulation	(a	service	that	corrects	for	short-term	changes	in	electricity	use	that	could	impact	the	stability	of	the	power	system).	Most	of	our	businesses	in	Europe, Latin	America	and	the	United	States	operate	in	these	types	of	liberalized	markets.

Other	Environments.	We	operate	Generation	assets	in	certain	countries	that	do	not	have	a	spot	market.	In	these	environments,	electricity	is	sold	only	through PPAs	with	state-owned	entities	and/or	industrial	clients	as	the	offtaker.	Examples	of	countries	where	we	operate	in	this	type	of	environment	include	Jordan,	Nigeria, Puerto	Rico	and	Sri	Lanka.

# Regulation	of	our	Distribution	Businesses

In	general,	our	distribution	companies	sell	electricity	directly	to	end-users	such	as	homes	and	businesses	and	bill	customers	directly.	The	amount	our	distribution companies	can	charge	customers	for	electricity	is	governed	by	a	regulated	tariff.	The	tariff,	in	turn,	is	generally	based	upon	a	certain	usage	level	that	includes	a	pass- through	to	the	customer	of	costs	that	are	not	controlled	by	the	distribution	company,	including	the	costs	of	fuel	(in	the	case	of	integrated	utilities)	and/or	the	costs	of purchased	energy,	plus	a	margin	for	the	value	added	by	the	distributor,	which	is	usually	calculated	as	a	fair	return	on	the	fair	value	of	the	company's	assets.	This regulated	tariff	is	periodically	reviewed	and	reset	by	the	applicable	regulatory	agency.	Components	of	the	tariff	that	are	directly	passed	through	to	the	customer	are usually	adjusted	through	an	automated	process.	In	many	instances,	the	tariffs	can	be	adjusted	between	scheduled	regulatory	resets	pursuant	to	an	inflation	adjustment	or another	index.	Customers	with	demand	above	a	certain	level	are	often	unregulated	and	can	choose	to	contract	with	generation	companies	directly	and	pay	a	wheeling	fee, which	is	a	fee	to	the	distribution	company	for	use	of	the	distribution	system.	Most	of	our	utilities	operate	as	monopolies	within	exclusive	geographic	areas	set	by	the regulatory	agency	and	face	limited	competition	from	other	distributors.

Set	forth	below	is	a	discussion	of	certain	regulations	we	operate	under	in	the	countries	where	we	do	business.	In	each	country,	the	regulatory	environment	can pose	material	risks	to	our	business,	operations	or	financial	condition.	For	further	discussion	of	those	risks,	see	the	Item	1A.—Risk	Factors	of	this	Form	10-K.

# Latin	America	and	Africa

# Argentina

Structure	of	Electricity	Market.	The	Argentine	electricity	market	is	divided	into	three	separate	lines	of	business:	generation,	transmission	and	distribution.	AES Argentina	operates	12%	of	the	installed	capacity	of	the	Wholesale	Electricity	Market	("WEM")	and	two	distribution	companies:	one	under	federal	jurisdiction– EDELAP;	and	the	other	under	the	jurisdiction	of	the	Province	of	Buenos	Aires–EDES.	The	law	recognizes	a	category	of	large	users	made	up	of	industrial	companies	and other	consumers	with	substantial	electricity	supply	needs.

The	WEM	is	comprised	of:

•	 A	Term	Contracts	Market,	with	contracts	freely	agreed	amongst	producers	and	consumers;

•	 A	Spot	Market,	with	prices	sanctioned	on	an	hourly	basis	considering	the	economic	cost	of	production	represented	by	the	short-term	marginal	cost	(spot prices);	and

•	 A	Stabilization	System	on	a	quarterly	basis	of	the	prices	forecasted	for	the	spot	market,	created	for	the	purchase	of	the	distributors	(seasonal	prices).

Principal	Regulators.	The	National	Electricity	Regulating	Agency	("ENRE")	is	responsible	for	ensuring	transmission	and	distribution	companies	comply	with	the concessions	granted	by	the	Argentine	government	and	approving	distribution	tariffs.	The	WEM	is	managed	by	Compañía	Administradora	del	Mercado	Mayorista Eléctrico,	Sociedad	Anónima	("CAMMESA"),	the	independent	system	operator.	CAMMESA	also	acts	as	the	dispatch	entity,	or	OED	(Organismo	Encargado	de Desapacho),	and	manages	the	organization,	dispatch	and	operations	of	the	WEM	at	large	according	to	the	policies	established	by	the	Energy	Secretariat,	under	the Ministry	of	Federal	Planning,	Public	Investment	and	Services.	In	such	capacity,	CAMMESA	is	empowered	to	interpret	the	rules	relating	to	the	organization,	dispatch and	energy	agreements	in	the	WEM.	In	addition	to	these	duties,	CAMMESA	manages	the	information	on	supply	and	demand	in	the	WEM,	which	is	used	by	the	Energy Secretariat	to	fix	the	seasonal	prices	and	the	market's	operational	rules.	CAMMESA's	operating	costs	are	borne	by	the	WEM's	participants	and	agents.

In	the	Provincial	Jurisdiction,	the	regulator	is	the	Organismo	de	Control	de	la	Electricidad	de	Buenos	Aires	and	the	Dirección	Provincial	de	Energía	under	the Ministry	of	Infrastructure.

Principal	Regulations.	The	electricity	sector	activities	are	regulated	by	the	Electricity	Act.	Law	24.065	and	Law	11.796	regulate	the	activities	of	generation, transmission	and	distribution	of	electric	energy	in	the	territory	of	the	Province	of	Buenos	Aires,	determining	what	activities	of	transmission	and	distribution	of	energy are	public	services,	whereas	the	generation	is	an	activity	of	general	interest.

Presently,	the	price	of	electric	energy	is	determined	assuming	all	generating	units	in	Argentina	are	operating	with	natural	gas,	even	though	the	generators	may	be using	more	expensive,	alternative	fuels.	In	the	case	of	generators	using	alternative	fuels,	CAMMESA	pays	the	total	variable	cost	of	production,	which	may	exceed	the established	spot	price.	Additionally,	in	the	spot	market,	generators	are	also	remunerated	for	their	capacity	to	generate	electricity	in	excess	of	supply	agreements	or	private contracts	executed	by	them.

The	Argentine	government	has	adopted	many	new	economic	measures	since	2002,	by	means	of	the	"Emergency	Law"	25561,	as	amended	and	extended	by various	supplemental	laws	and	regulations.	These	laws	and	regulations	effectively	terminated	the	use	of	the	United	States	Dollar	as	the	functional	currency	of	the Argentine	electricity	sector.	Distribution	companies	are	ruled	by	their	Concession	Contracts	on	November	12,	2004.

Material	Regulatory	Actions.	On	July	31,	2008,	the	ENRE	issued	Resolution	324	that	granted	EDELAP	a	tariff	DVA	increase	of	approximately	18%.	In	addition, the	government	recognized	that	a	process	to	establish	the	RTI	(integral	tariff	reset)	should	take	place	during	February	2009.	On	September	12,	2009,	EDELAP	submitted the	tariff	reset	proposal	to	the	ENRE.	ENRE	is	considering	the	tariff	proposals	submitted	by	the	federal	distribution	companies.	If	the	regulatory	agency	continues	to delay	the	granting	of	the	tariff	increase	needed	by	EDELAP,	EDELAP	could	experience	significant	operational	challenges	in	the	future.	Total	DVA	increase	granted	to EDELAP	pursuant	to	this	process	is	66%.

In	March	2008,	the	Ministry	of	Infrastructure	of	the	Province	of	Buenos	Aires	issued	Resolution	741	which	settled	a	tariff	increase	of	15%	average)	to	be	applied for	EDES	during	2008	and	an	increase	of	15%	average	to	be	applied	from	2009.	On	March	22,	2010,	the	Ministry	of	Infrastructure	of	the	Province	of	Buenos	Aires issued	Resolution	141	which	settled	the	new	tariff	to	be	applied	by	EDES	during	2010.	It	represents	an	average	increase	of	approximately	24%.	Total	DVA	increase granted	to	EDES	pursuant	to	this	process	is	190%.

During	2004,	the	Energy	Secretariat	reached	agreements	with	natural	gas	and	electricity	producers	to	reform	the	energy	markets.	In	the	electricity	sector,	the Energy	Secretariat	passed	Resolution	826/2004,	inviting	generators	to	contribute	a	percentage	of	their	sales	margins	to	fund	the	development	and	construction	of	two new	combined	cycle	power	plants	to	be	installed	by	2008/2009	("FONINVEMEM	I	&	II").	The	time	period	for	the	funding	was	set	from	January	2004	through December	2006	and	was	subsequently	extended	through	December	2007.	During	2008,	both	power	plants	started	operation	of	the	gas	turbines,	and	since	March	2010, the	plants	started	operations	in	combined	cycle	mode.	In	exchange,	the	Argentine	government	committed	to	reform	market	regulation	to	match	more	favorable regulations	that	existed	prior	to	2001.	Additionally,	participating	generators	will	receive	a	pro	rata	ownership	share	in	the	new	generation	plants	after	ten	years.

Potential	or	Proposed	Regulations.	A	non-binding	general	agreement	with	the	rest	of	the	Generators	operating	in	Argentina	and	the	government	was	signed	on November	25,	2010	to	address	a	nation-wide	problem	of	overdue	accounts	receivables	to	the	generation	market.	The	non-binding	agreement	established	the	guidelines for	the	detailed	documentation	that	will	allow	the	execution	FONINVEMEM	III	project	agreement	and	some	additional	cash	revenues.	Under	the	agreement,	accounts receivable	accrued	from	July	2009	to	December	2011,	for	an	amount	of	approximately	$204	million	will	be	converted	into	a	generation	asset	(estimated	at	800	MW)	to be	built	under	the	FONINVEMEM	III	project.	The	government	will	provide	funds	necessary	to	finance	the	projects.	The	plant	will	have	a	PPA	with	CAMMESA	for	ten (10)	years,	calculated	to	recover	100%	of	the	receivables	invested	plus	a	margin	of	LIBOR	+	5%.	Payments	will	be	made	once	the	project	begins	operations.	We	expect the	existing	FONINVEMEM	I	and	II	documents	will	be	taken	as	a	base	for	the	future	contracts;	assuming	this,	the	collection	of	the	120	installment	will	not	be	tied	to	the availability	of	the	plant.	Availability

risk	will	be	assumed	by	the	operator	through	a	Long-Term	Service	Agreement	("LTSA").	Some	penalties	may	apply	to	the	generating	companies,	but	only	in	those	cases where	the	unavailability	is	caused	by	their	operating	decisions	not	considered	in	the	LTSA.	According	to	this,	the	yearly	penalty	would	be	capped	at	10%	of	the	yearly amount	required	under	the	PPA.	Initially,	AES	Argentina	Generación	S.A.	will	participate	in	this	proposal	under	the	terms	and	conditions	referred	to	above.	Its	equity ownership	in	the	new	project	will	equal	its	contribution	of	receivables	among	the	generating	companies,	estimated	to	be	24%	of	the	resulting	plants.	Both	power	plants that	were	built	under	similar	regulations	started	full	operation	in	combined	cycle	mode	in	March	2010,	and	the	installments	agreed	are	being	paid	on	a	timely	basis.

# Brazil

Structure	of	Electricity	Market.	In	Brazil,	there	are	two	regulatory	regimes	which	regulate	PPAs	the	Regulated	Contracting	Ambience	("ACR"),	for	the Generation	and	Distribution	of	Electric	Power	Agents,	and	the	Ambience	for	Free	Contracting	("ACL"),	for	the	Generation,	Commercialization,	Importers	and	Exporters of	Energy	Power	Agents	as	well	as	consumers.

This	model	establishes	a	number	of	requirements	to	be	followed	by	the	participants	in	the	industry,	such	as	the	obligation	for	distributors	to	contract	for	their market	growth	years	in	advance	through	regulated	auctions;	hydro	and	thermal	energy	contracting	conditions	to	ensure	better	balance	between	supply	cost	and	system stability;	and	a	permanent	supply	monitoring	structure	to	detect	possible	imbalances	between	supply	and	demand.

Principal	Regulators.	In	Brazil,	there	are	a	number	of	regulatory	bodies	which	govern	the	electricity	sector	including	the	Brazilian	Electricity	Regulatory	Agency ("ANEEL")	and	the	Chamber	of	Electrical	Energy	Commercialization	("CCEE").

ANEEL's	responsibilities	are	to	regulate	and	inspect	production,	transmission,	distribution	and	commercialization	of	electricity	in	order	to	assure	quality	of provided	services	and	universal	access.	ANEEL	is	also	responsible	for	the	establishment	of	tariffs	for	end	consumers,	in	a	way	that	the	economic	and	financial	feasibility of	power	sector	participants	as	Generation,	Transmission	and	Distribution	companies	and	such	as	the	industry	as	a	whole	is	preserved.	The	changes	brought	about	in 2004	by	the	new	model	made	ANEEL	responsible	for	promoting,	directly	or	indirectly,	auctions	for	the	Distribution	companies	to	purchase	energy	through	long-term contracts	within	the	National	Interconnected	System	(Sistema	Interligado	Nacional)	("SIN").

The	CCEE	(former	Mercado	Atacadista	de	Energia)	paramount	obligations	include:	the	determination	of	the	Differences'	Price	Settlement	(Preço	de	Liquidação de	Diferenças)	("PLD"),	or	Spot	Price,	used	to	value	short-term	market	transactions;	the	execution	of	the	energy	accounting	process,	identifying	who	and	how	much electricity	is	involved	in	multilateral	short-term	market	transactions;	the	financial	settlement	of	the	amounts	calculated	in	the	energy	accounting	process;	and	preparation and	execution	of	energy	auctions	within	the	ACR	by	ANEEL's	delegation.

# Principal	Regulations.

Distribution	Companies.	AES	has	two	distribution	businesses	in	Brazil:	AES	Eletropaulo	and	AES	Sul.	Under	the	power	sector	model,	distribution	companies have	to	purchase	electricity	at	the	regulated	market	through	auctions.	Every	distribution	utility	is	obligated	to	contract	to	meet	100%	of	its	energy	needs	in	the	ACR. Bilateral	contracts	are	being	honored	but	cannot	be	renewed.	The	tariff	charged	by	distribution	companies	to	captive	customers	is	composed	of	a	non-manageable	cost component	("Parcel	A"),	which	includes	energy	purchase	costs	and	charges	related	to	the	use	of	transmission	and	distribution	systems	and	is	directly	passed	through	to customers,	and	a	manageable	cost	component	("Parcel	B"),	which	includes	operation	and	maintenance	costs	based	on	a	model	distribution	company	defined	by	ANEEL, recovery	of	depreciated	assets	and	a	component	for	the	value	added	by	the	distributor	(calculated	as	net	asset	base	multiplied	by	pre-tax	weighted

average	cost	of	capital).	Parcel	B	is	reset	every	four	years	for	AES	Eletropaulo	and	every	five	years	for	AES	Sul.	There	is	an	annual	tariff	adjustment	to	pass	through Parcel	A	costs	to	customers	and	to	adjust	the	Parcel	B	costs	by	inflation,	less	an	efficiency	factor.	Distribution	companies	could	also	be	entitled	to	extraordinary	tariff revisions	in	the	event	of	significant	changes	to	their	cost	structure.

In	the	first	half	of	2010,	all	distribution	companies	signed	amendments	to	the	Concession	Contracts,	capturing	market	variance	effects	over	sector	charges.	AES Eletropaulo	signed	its	amendment	on	May	3,	while	AES	Sul	signed	it	on	April	12.	The	2010	tariff	readjustment	already	reflected	such	amendment.	Additionally, ANEEL	conducted	a	public	hearing	regarding	the	partition	of	the	extraordinary	tariff	reset	("RTE")	between	Generation	and	Distribution	companies.	The	RTE	was designed	to	recover	revenue	losses	of	Distribution	companies	and	energy	purchase	costs	of	Generation	companies,	both	during	the	rationing	period	that	occurred	in	2001 and	as	a	result	of	regulatory,	market	and	weather-related	conditions.	The	RTE's	period	of	application	for	AES	Eletropaulo	was	limited	to	70	months,	which	was	not sufficient	to	recover	its	revenue	losses.	The	Public	Hearing	process	was	concluded	on	January	12,	2010,	generating	an	initial	negative	impact	before	taxes	to	AES Eletropaulo	of	R$6.8	million	($4.1	million)	recorded	in	2009,	offset	by	a	positive	impact	before	taxes	of	R$7.3	million	($4.4	million)	recorded	in	2010	for	additional RTE	adjustments.	AES	Tietê	recorded	revenue	of	R$6.2	million	($3.7	million)	in	2010.

Generation	Companies.	AES	has	two	generation	businesses	in	Brazil:	AES	Tietê	and	AES	Uruguaiana.	Under	the	power	sector	model,	the	Ministry	of	Mines	and Energy	MME	determines	the	amount	of	energy	to	be	sold	by	each	plant	known	as	"assured	energy"	or	the	amount	of	energy	representing	the	long-term	average	energy production	of	the	plant	defined	by	ANEEL.	Together	with	the	system	operator,	ANEEL	establishes	the	assured	energy	which	is	the	amount	of	energy	to	be	sold	by	each plant	through	long	term	contracts.	The	system	operator	determines	generation	dispatch	which	takes	into	account	nationwide	electricity	demand,	hydrological	conditions and	system	constraints.	In	order	to	mitigate	the	risks	involved	in	hydroelectric	generation	for	each	generator	and	to	optimize	the	system	generation	capacity,	a mechanism	is	in	place	to	transfer	energy	from	those	who	generated	more	than	the	average	of	the	system	to	those	who	generated	less	than	the	average.	The	energy	that	is reallocated	through	this	mechanism	is	priced	pursuant	to	an	energy	optimization	tariff,	designed	to	optimize	the	use	of	generation	available	in	the	system.

AES	Tietê	is	allowed	to	sell	electric	power	within	the	ACR	and	ACL,	maintaining	the	competitive	nature	of	the	generation.	Generation	companies	must	provide physical	coverage	from	their	own	power	generation	or	purchase	contracts	for	100%	of	their	sale	contracts.	The	failure	to	provide	the	required	physical	coverage	and/or present	purchase	contracts,	which	is	subject	to	monthly	verification,	exposes	the	generation	company	to	the	payment	of	penalties.

Beginning	in	2003,	25%	of	AES	Tiete's	assured	energy	has	been	added	annually	to	the	volume	marketed	through	a	PPA	and	consequently	since	2006,	all	of	AES Tiete's	assured	energy	has	been	sold	to	AES	Eletropaulo.	The	PPA	entered	into	with	AES	Eletropaulo	which	expires	on	December	31,	2015,	and	requires	that	the	price of	energy	sold	be	adjusted	annually	based	on	the	Brazilian	inflation	variation.	Before	the	end	of	the	PPA	in	2015,	AES	Tietê	must	seek	alternatives	to	the	immediate	re- contracting	of	its	assured	energy	from	2016	onwards.	Existing	legislation	allows	AES	Tietê	to	allocate	its	energy	to	the	regulated	auctions	of	existing	energy,	or	in	the free	market	through	bilateral	contracts	for	non-distribution	companies.

The	state	of	São	Paulo	stablished	some	conditions	to	privatize	the	generation	sector	in	Sao	Paulo	state	including	an	obligation	to	increase	generation	capacity	by 15%,	originally	to	be	accomplished	by	the	end	of	2007.	AES	Tietê,	as	well	as	other	concessionaire	generators,	were	not	able	to	meet	this	requirement	due	to	regulatory, environmental	and	hydrological	constraints.	Currently,	the	matter	is	under	consideration	by	the	government	of	the	State	of	São	Paulo	(related	to	the	increased	capacity) after	a	decision	by	ANEEL's	Board	of	Officers	that	ANEEL	is	not	the	appropriate	authority	to	consider	the	extension,	since	the	expansion	obligation	derives	from	the purchase	and	sale	agreement	between	AES	Tietê	and	the	Government	of	São	Paulo,	and	not	from	the	concession	agreement	itself.	AES	Tietê	is	reviewing	any	may pursue	the	development	of	certain	gas-fired	facilities	in	order	to	meet	this	obligation.

Environmental	Regulations.	Electric	sector	companies	are	subject	to	strict	environmental	legislation	in	federal,	state	and	municipal	spheres	in	matters	such	as atmospheric	emissions	and	special	protected	areas.	Such	companies	need	permits	and	authorizations	from	government	bodies	in	order	to	conduct	their	activities.	In	case of	violation	of	or	non-compliance	with	such	laws,	regulations,	permits	and	authorizations,	companies	may	suffer	administrative	sanctions	such	as	fines,	shutdown	of activities,	invalidation	of	permits	and	the	annulment	of	authorizations.	The	government	Attorney's	Office	may	institute	a	civil	investigation	and/or	promote	a	public	civil action	seeking	indemnity	for	environmental	or	third-party	damages.	Government	agencies	or	other	authorities	may	enact	new	stricter	rules	or	search	for	more	restrictive interpretations	of	existing	laws	and	regulations	that	may	oblige	power	companies	to	spend	additional	resources	for	environmental	compliance,	including	attainment	of environmental	permits	for	facilities	and	equipment	that	did	not	require	those	types	of	permits	previously.	Government	agencies	or	other	authorities	may	delay	the issuance	of	permits	and	necessary	authorizations	for	the	development	of	power	companies	causing	project	implementation	schedule	delays	and,	consequently, unfavorable	effects	in	the	companies'	businesses	and	results.	Any	action	in	this	direction	from	the	government	agencies	may	negatively	affect	businesses	in	the	power sector	and	have	adverse	effects	on	the	business	and	results	of	the	companies.

Material	Regulatory	Actions.	According	to	the	Concession	Contract,	distribution	companies	go	through	a	tariff	adjustment	process	every	year.	AES	Eletropaulo was	granted	an	8.00%	average	tariff	adjustment	to	be	applied	to	the	Company's	tariff	as	from	July	4,	2010.	AES	Sul's	average	tariff	adjustment	was	5.56%	as	of April	19,	2010.

On	May	16,	2002,	ANEEL	issued	the	Order	#288,	a	regulation	that	established	the	retroactive	denial	to	the	choice	of	not	participating	in	the	"exposition	relief mechanism,"	a	tool	that	allowed	the	sale	of	energy	from	Itaipu	Generating	Co.	in	the	Spot	Market.	Due	to	its	negative	impact,	AES	Sul	filed	a	lawsuit	seeking	the annulment	of	Order	#288.	For	a	further	discussion	of	this	dispute	see	Item	3.—Legal	Proceedings	in	this	Form	10-K.

Potential	or	Proposed	Regulations.	In	2011,	the	Third	Reset	Cycle	begins;	AES	Eletropaulo's	will	take	place	in	2011	and	AES	Sul's	will	occur	in	2013.	A	public hearing	proposed	a	new	methodology	for	tariff	reset	and	our	comments	were	submitted	on	January	10,	2011,	There	is	a	another	on	going	regarding	a	new	methodology for	tariff	reset	promote	a	new	methodology	for	defining	quality	of	service	indicators.	The	outcome	of	these	hearings	is	unknown.	However,	if	the	revised	tariff	is inexplicitly	low	or	our	quality	of	service	indicators	are	found	inadequate,	there	could	be	a	material	impact	on	our	business.

# Cameroon

Structure	of	Electricity	Market.	Our	subsidiaries	in	Cameroon	are	involved	in	the	generation,	transmission,	distribution	and	sale	of	electricity	through	AES SONEL,	Dibamba	Power	Development	Company	("DPDC")	and	Kribi	Power	Development	Company	("KPDC").	AES	SONEL	is	an	integrated	utility	which	operates approximately	930	MW	of	generation	capacity,	two	interconnected	transmission	networks	and	distributes	electricity	to	approximately	700,000	customers	under	a	20- year	concession	agreement	that	was	signed	in	July	of	2001.	AES	SONEL	has	the	exclusive	distribution	rights	to	all	medium	voltage	and	low	voltage	customers,	except for	customers	with	an	installed	capacity	of	more	than	1	MW	("Major	Customers")	who	are	free	to	negotiate	bilateral	agreements.	Generation	in	Cameroon	is	open	for competition	and	our	subsidiary,	DPDC,	developed,	built	and	is	currently	operating	an	86	MW	heavy	fuel	oil	power	plant	near	Douala	as	an	IPP	which	provides	power	to AES	SONEL	under	a	tolling	agreement.	In	order	to	meet	increasing	demand	for	power,	the	government	is	developing	the	Lom	Pangar	Dam	project	on	the	Sanaga	River which	will	increase	the	flows	of	the	Sanaga	River	and	increase	the	generation	capacity	of	the	two	major	hydro	power	plants	currently	operated	by	AES	SONEL.	The Lom	Pangar	Dam	will	also	generate	50	MW.	Another	AES	subsidiary,	KPDC,	is	developing	a	216	MW	gas-fired	power	plant	in	Kribi	as	another	IPP	which	will	provide power	to	AES	SONEL.

Under	its	Concession	Agreement,	AES	SONEL	operates	the	two	interconnected	transmission	networks	in	the	country:	the	Southern	Grid	with	a	length	of	1550 km	and	the	Northern	Grid	with	a	length	of	665	km.	Major

Customers,	distributors,	or	vendors	can	access	the	grid	subject	to	paying	a	fee.	Sales	to	low	voltage	and	medium	voltage	customers	are	subject	to	tariff	levels	agreed	to between	AES	SONEL	and	the	regulator	based	on	the	framework	established	in	the	AES	SONEL	Concession	Agreement.	Management	of	energy	flows	on	the transmission	network	is	currently	undertaken	by	AES	SONEL.	Under	the	Concession	requirements,	AES	SONEL	will	be	required	to	create	a	separate	legal	entity	under which	the	transmission	system	will	operate.	Under	the	regulation	in	force,	such	entity	is	contemplated	to	be	a	100%	subsidiary	of	AES	SONEL	whose	share	capital	will be	opened	up	to	other	operators	in	the	sector	in	accordance	with	procedures	to	be	approved	by	the	regulator.

Principal	Regulators.	Cameroon's	electricity	regulatory	agency,	ARSEL,	has	functional	and	decision-making	autonomy,	and	is	run	by	a	Board	of	Directors	and	a General	Manager	assisted	by	a	Deputy	General	Manager.	Its	financing	is	provided	by	the	state	budget	and	fees	collected	from	revenues	generated	from	activities	carried out	by	operators	of	the	sectors	concerned.	ARSEL's	decisions	are	highly	influenced	by	the	government	via	the	Ministry	of	Power,	the	Prime	Minister's	Office	and	the General	Secretariat	of	the	Presidency	of	the	Republic.	The	Ministry	of	Energy	and	Water	is	the	Ministry	mandated	to	issue	specific	regulations	relating	to	the	electricity sector	and	to	issue	the	concessions,	licenses	and	authorizations	to	be	granted	to	the	operators	in	the	sector.

Principal	Regulations.	The	principal	legislative	instrument	governing	the	power	sector	is	Law	No.	98/022	of	December	24,	1998	which	sets	out	a	new institutional	framework	for	the	Power	Sector	and	lays	the	foundations	for	competition	in	the	power	market	in	Cameroon.	It	is	supplemented	by	the	following	instruments:

•	 Decree	No.	2001/021/PM	of	January	29,	2001	setting	out	the	rates	and	methods	of	calculation,	collection	and	distribution	of	the	fees	payable	by	operators involved	in	the	power	sector;

•	 Ministerial	Order	No.	061/CAB/MINMEE	of	January	30,	2001	setting	out	the	documents	and	fees	required	in	applying	for	concessions,	licenses, authorizations	and	declarations	for	the	generation,	transmission,	distribution,	export	and	sale	of	power;

•	 Ministerial	Order	No.	000013/MINMEE	of	January	26,	2009	approving	the	regulation	of	the	public	distribution	of	electricity	in	Cameroon;	and

•The	Concession	Agreements	and	license	between	the	Republic	of	Cameroon	and	AES	SONEL	signed	on	July	18,	2001	and	amended	in	2006.

Material	Regulatory	Issues.	Cameroon	is	currently	preparing	for	presidential	elections	in	2011	and	local	elections	in	2012.	Tariff	adjustments	expected	for	2010 were	challenged	by	the	government,	resulting	in	shortfalls	of	compensation	due	under	the	Concession	Agreement	to	AES	SONEL	for	2010	and	2011.	Following	lengthy negotiations,	a	compensation	agreement	was	signed	by	both	parties	on	November	24,	2010,	which	provides,	among	other	things,	for	compensation	to	be	paid	to	AES SONEL	by	the	government	of	Cameroon	for	any	revenue	shortfall	in	2010	and	2011	arising	from	the	difference	between	tariffs	applied	to	end-users	and	tariffs	due	under the	Concession	Agreement.	The	estimated	shortfall	for	2010	was	approximately	$22	million,	which	has	been	paid	in	full.	The	normal	tariff	mechanisms	to	end-users	are expected	to	be	restored	in	2012.

Environmental	Regulations.	The	environmental	regulation	is	derived	from	Law	No.	96/12	of	August	5,	1996	and	various	implementing	decrees	and	ministerial orders.	This	regulation	applies	to	all	sectors	but	there	are	some	specific	requirements	relating	to	the	electricity	sector.	The	main	requirement	of	this	regulation	is	the obligation	to	conduct	an	environmental	impact	analysis	for	planned	construction	of	new	generation	installations	or	new	transmission	lines	or	substations.

Potential	or	Proposed	Regulations.	In	addition,	there	are	plans	to	review	the	legal	and	regulatory	framework	of	the	power	sector	to	consider	the	formation	of	new public	entities.	Presently,	to	make	up	for	the	power	shortage	anticipated	in	2012	(due	to	delays	in	commissioning	the	Kribi	power	plant	developed	by	KPDC	and	the	Lom 27

Pangar	Dam	developed	by	the	government)	and	the	additional	demand	generated	by	a	number	of	infrastructural	projects,	the	government	is	planning	to	construct	thermal plants	with	an	overall	capacity	of	40	MW	and	a	hydroelectric	plant	with	a	capacity	of	200	MW.	Additionally,	there	are	other	generation	projects	whose	specifications have	yet	to	be	clearly	determined.	The	regulatory	framework	relating	to	the	development	of	this	new	capacity	and	to	the	future	contractual	relationship	between	these new	projects	and	AES	SONEL	is	still	unclear.	However,	the	tariff	compensation	agreement	referred	to	above	provides	that	additional	costs	imposed	on	AES	SONEL with	regard	to	these	projects	shall	be	fully	passed	through	in	tariffs	charged	to	end-users.

Despite	the	provisions	of	the	regulation	described	above	relating	to	the	operation	of	the	transmission	network,	the	Minister	of	Energy	has	formally	expressed	his preference	for	a	different	solution	that	would	take	responsibilities	for	transmission	activity	and	management	of	the	transmission	grid	away	from	AES	SONEL	and	assign them	to	a	new	public	entity	to	be	created	and	majority-owned	by	the	state.	The	impact	on	AES	is	not	known	at	this	time;	however,	it	could	be	material	to	our	results	of operations.

# Chile

Structure	of	Electricity	Market.	In	Chile,	except	for	the	small	isolated	systems	of	Aysén	and	Punta	Arenas,	generation	activities	are	principally	in	two	electric systems:	the	Central	Interconnected	Grid	("SIC"),	which	supplies	approximately	92%	of	the	country's	population;	and	the	Northern	Interconnected	Grid	("SING"), where	the	principal	users	are	mining	and	industrial	companies.	Power	generation	is	based	primarily	on	long-term	contracts	between	generation	companies	and	customers specifying	the	volume,	price	and	conditions	for	the	sale	of	energy	and	capacity.	The	law	recognizes	two	types	of	customers	for	generation	companies:	unregulated customers	and	regulated	customers.	Unregulated	customers	are	principally	consumers	whose	connected	capacity	is	higher	than	2	MW	and	consumers	whose	connected capacity	is	between	500	kW	and	2	MW	who	have	selected	the	unregulated	pricing	mechanism	for	a	period	of	four	years.	These	customers	are	not	subject	to	price regulation	and	are	able	to	freely	negotiate	prices	and	conditions	for	electricity	supply	with	generation	and	distribution	companies.	Regulated	customers	are	those	whose connected	capacity	is	less	than	or	equal	to	500	kW	and	those	with	connected	capacity	between	500	kW	and	2	MW	who	have	selected,	also	for	four	years,	the	regulated pricing	system.

Electricity	generation	in	each	of	the	SIC	and	the	SING	is	coordinated	by	the	respective	independent	Economic	Load	Dispatch	Center	("CDEC")	in	order	to minimize	operational	costs	and	ensure	the	highest	economic	efficiency	of	the	system,	while	fulfilling	all	quality	of	service	and	reliability	requirements	established	by current	regulations.	In	order	to	satisfy	demand	at	the	lowest	possible	cost	at	all	times,	each	CDEC	orders	the	dispatch	of	generation	plants	based	strictly	on	variable generation	costs,	starting	with	the	lowest	variable	cost,	and	does	so	independent	of	the	contracts	held	by	each	generation	company.	Thus,	while	the	generation	companies are	free	to	enter	into	supply	contracts	with	their	customers	and	are	obligated	to	comply	with	such	contracts,	the	energy	needed	to	satisfy	demand	is	always	produced	by the	CDEC	members	whose	variable	production	costs	are	lower	than	the	system's	marginal	cost	at	the	time	of	dispatch.	For	this	reason,	in	each	hour	a	given	generator	is either	a	net	supplier	to	the	system	or	a	net	buyer.	Net	buyers	pay	net	suppliers	the	system's	marginal	cost.	In	addition,	the	Chilean	market	is	designed	to	include payments	for	capacity	(or	firm	capacity),	which	are	explicitly	paid	to	generation	companies	for	contributing	to	the	system's	sufficiency.	The	cost	of	investment	and operation	of	transmission	systems	is	borne	by	generation	companies	and	consumers	(regulated	tolls)	in	proportion	to	their	use.

Principal	Regulators.	The	Chilean	Ministry	of	Energy,	created	in	2010,	grants	concessions	for	the	provision	of	the	public	service	of	electric	distribution	and	the National	Commission	for	the	Environment	administers	the	system	for	evaluating	the	environmental	impact	of	projects.	Thermoelectric	plants	do	not	require	electrical concession	agreements	from	the	government	in	order	to	be	built	or	operate.	The	new	Ministry	of	Energy	works	with	several	agencies	related	to	energy	issues,	such	as	the National	Energy	Commission	("NEC"),	the	Electricity	and	Fuel	Superintendent	and	the	Chilean	Nuclear	Commission,	among	others,	in	order	to	provide	a	better coordination	of	energy	affairs.	The	Ministry	of	Energy	will	also	oversee	a	new	Energy	Efficiency	agency.	The

NEC	establishes,	regulates	and	coordinates	energy	policy.	The	Superintendent	of	Electricity	and	Fuels	oversees	compliance	with	service	quality	and	safety	regulations. The	General	Water	Authority	issues	the	rights	to	use	water	for	hydroelectric	generation	plants.	The	Chilean	electric	system	includes	a	Panel	of	Experts—an	independent technical	agency	whose	purpose	is	to	analyze	and	resolve	in	a	timely	fashion	conflicts	arising	between	companies	within	the	electric	sector	and	among	one	or	more	of these	companies	and	the	energy	regulators.	In	addition,	the	Ministry	of	Environment	is	responsible	for	the	development	and	implementation	of	environmental regulations,	protection	of	the	environment,	environmental	education	and	pollution	control,	among	others.

Principal	Regulations.	The	distinct	electricity	sector	activities	are	regulated	by	the	General	Electricity	Services	Law.	Sector	activities	are	also	governed	by	the corresponding	technical	regulations	and	standards.	The	keystones	of	the	electricity	regulation	are:	(i)	a	regulated	compulsory	marginal	cost	dispatch	based	on	audited variable	costs;	(ii)	a	contract-based	wholesale	generation	market;	(iii)	an	open-access	regime	for	transmission	with	benchmark	regulation	for	existent	transmission	lines and	open	bids	for	new	lines;	(iv)	benchmark	regulation	for	the	distribution	grid;	and	(v)	electricity	retailing	by	distribution	companies	in	their	exclusive	concession	areas.

In	accordance	with	these	laws,	new	contracts	assigned	by	distribution	companies	for	consumption	from	2010	onward	must	be	awarded	to	generation	companies based	on	the	lowest	supply	price	offered	in	public	bid	processes.	These	prices,	called	"long-term	node	prices,"	include	indexation	formulas	and	are	valid	for	the	entire term	of	the	contract,	up	to	a	maximum	of	fifteen	years.	More	precisely,	the	long-term	energy	node	price	for	a	particular	contract	is	the	lowest	energy	price	offered	by	the generation	companies	participating	in	each	respective	bid	process,	while	the	long-term	capacity	node	price	is	that	set	in	the	node	price	decree	in	effect	at	the	time	of	the bid.

On	February	17,	2011,	President	Sebastian	Pinera's	administration	enacted	an	energy	decree	that	enables	the	government	to	take	preventive	measures	to	reduce the	risk	of	future	energy	shortages.	Chile	is	experiencing	a	significant	drought	that	has	diminished	the	country's	reservoir	levels	and	hydroelectric	power	capacity affecting	the	(SIC).	The	decree	will	be	in	forced	until	August	2011	and	focuses	on	three	main	actions:	cutting	available	voltage	by	10-12.5%;	saving	reservoir	capacity up	to	500	GWh;	and	offering	incentives	for	consumers	to	save	electricity.	The	decree	is	not	expected	to	have	a	material	impact	on	AES	Gener's	results	in	2011

Environmental	Regulations.	Law	20,257	was	enacted	in	April	2008	and	promotes	non-conventional	renewable	energy	sources,	such	as	solar,	wind,	small hydroelectric	and	biomass	energy.	The	Law	requires	that	a	percentage	of	the	new	power	purchase	contracts	held	by	generation	companies	after	August	31,	2007	be supplied	from	renewable	sources.	The	required	energy	percentage	begins	at	5%	for	2010-2014,	and	gradually	increases	to	a	maximum	of	10%	in	2024.	Generation companies	are	charged	for	each	kWh	not	supplied	in	accordance	with	the	Law.	Our	businesses	in	Chile	have	developed	a	plan	for	complying	with	this	law,	which includes	the	sale	of	certain	water	rights,	the	purchasers	of	which	have	agreed	to	build	a	small	hydroelectric	plant	and	sell	the	energy	to	our	businesses	in	Chile	at	a	fixed price.

Potential	or	Proposed	Regulations.	In	December	2009,	the	environmental	agency	published	a	draft	of	a	potential	new	ruling	which	will	regulate	the	emissions from	thermal	power	plants	of	NO ,	SO ,	particulate	matter	("PM")	and	metals.	The	President	of	Chile	approved	the	regulation	on	January	18,	2011	and	the	regulation will	become	effective	upon	approval	of	the	General	Comptroller	of	Chile.	The	regulation	will	require	AES	Gener,	our	Chilean	subsidiary,	to	install	emissions	reduction equipment	at	its	existing	thermal	plants	from	late	2011	through	2015.	The	exact	costs	of	compliance	with	such	regulation	have	not	yet	been	determined	and	the Company	believes	some	of	the	compliance	costs	are	contractually	passed	through	to	counterparties.	However,	the	compliance	costs	could	be	material.

A	proposed	law	which	would	give	new	incentives	to	Non-Conventional	Renewable	Energy	("NCRE")	such	as	solar,	wind,	small	hydroelectric	and	biomass energy	is	under	discussion	in	the	Congress.	The	proposed	law

increases	the	requirements	of	NCRE	beginning	2015,	such	requirements	reaching	20%	as	a	percentage	of	the	customer	load	in	2020.	The	current	law	imposes	a requirement	to	reach	10%	in	2024.	The	new	requirements	would	need	to	be	fulfilled	with	NCRE	coming	from	the	same	system	(separates	SIC	and	SING).	The	NCRE would	need	to	be	accredited	by	the	NEC,	which	may	impose	fines	for	non-compliance.	The	impact	to	AES	Gener	is	under	analysis;	however,	it	will	depend	on	the	new size	limit	of	small	run	of	river	units	and	if	the	new	requirement	affects	the	current	supply	contracts,	which	only	include	the	10%	required	by	the	current	law.	The proposed	law,	if	passed,	could	result	in	increased	costs	or	otherwise	have	a	material	impact	on	our	results	of	operations.

In	September	2010,	the	NEC	proposed	a	new	normative	in	Ancillary	Services	("AASS")	based	on	a	cost-efficient	regulation	informed	by	generators	and customers.	The	normative	regulates	the	AASS	transactions	among	generators	in:	regulation,	spinning	reserve,	non-operating	reserve	and	the	Automatic	Load	Shedding Scheme	("ALSS").	AES	Gener	has	presented	observations	principally	against	compulsory	investments	requested	by	the	CDEC;	AASS	costs	allocated	incorrectly	among generators	according	to	their	power	generation	(it	believes	it	should	be	according	to	their	electricity	withdrawals)	and	the	ALSS's	are	a	demand-side	obligation	and adjustment	mechanisms	are	only	considered	for	imbalances	in	contributions	between	consumers.	AES	Gener	is	assessing	the	potential	impact	of	this	regulation,	and	an estimate	of	the	impact	can	only	be	established	when	the	final	regulation	is	issued.	However,	if	passed,	the	regulations	could	result	in	required	investments	or	other increased	costs	which	could	have	a	material	and	adverse	impact	on	our	results	of	operations.

# Colombia

Structure	of	Electricity	Market.	Colombia	has	one	main	national	interconnected	system	(the	"SIN").	The	wholesale	market	is	organized	around	both	bilateral contracts	and	a	mandatory	pool	and	spot	market	for	all	generation	units	larger	than	20	MW.

In	the	spot	market,	each	unit	bids	its	availability	and	a	set	price	for	a	24-hour	period.	The	dispatch	is	arranged	from	lowest	to	highest	bid	price	and	the	spot	price is	set	by	the	marginal	price.	There	are	two	types	of	customers:	unregulated	customers	and	regulated	customers.	Unregulated	customers	are	consumers	whose	maximum capacity	consumption	is	higher	than	0.1	MW,	or	whose	energy	demand	is	greater	than	55	MWh/month.	These	customers	are	not	subject	to	price	regulation;	therefore, generators	or	trader	companies	are	able	to	freely	negotiate	prices	and	conditions	for	electricity	supply	with	them.	Regulated	customers	have	their	prices	determined	by means	of	public	tenders.

Electricity	generation	in	the	Colombian	system	is	coordinated	by	the	market	administrator	whose	goal	is	to	minimize	operational	costs	while	fulfilling	all	quality- of-service	and	reliability	requirements	established	by	current	regulations.	In	order	to	satisfy	demand	at	the	lowest	possible	cost	at	all	times,	market	administrator	orders the	dispatch	of	generation	plants	based	on	offer	price	(variable	cost	plus	reliability	charge)	by	merit,	starting	with	the	lowest	offer	price,	and	does	so	independent	of	the contracts	held	by	each	generation	company.	For	this	reason,	in	each	hour	a	given	generator	is	either	a	net	supplier	to	the	system	or	a	net	buyer.	Net	buyers	pay	net suppliers	the	system's	spot	price.	In	addition,	the	Colombian	market	is	designed	to	include	reliability	payments,	which	are	paid	to	generation	companies	for	contributing to	the	system's	sufficiency.	The	cost	of	investment	and	operation	of	transmission	systems	are	borne	by	the	consumers	in	proportion	to	their	use.

Principal	Regulators.	The	Ministry	of	Mines	and	Energy	("MME")	establishes	the	energy	policies	and	the	Regulatory	Commission	of	Electricity	and	Gas ("CREG")	was	created	to	foster	the	efficient	supply	of	energy	through	regulation	of	the	wholesale	market,	the	natural	monopolies	of	transmission,	and	distribution,	and by	setting	limits	for	horizontal	and	vertical	integration.	The	Ministry	of	the	Environment	("MMA")	establishes	the	environmental	policies.

The	Public	Services	Superintendence	supervises	the	correct	provision	of	utilities	and	the	Industry	and	Commerce	Superintendence	is	in	charge	of	sanctioning	any anticompetitive	practice.	Other	entities	that	have	an

impact	on	the	electric	system	include	the	Energy	Planning	Unit	("UPME"),	in	charge	of	planning	the	electricity	and	gas	system,	and	the	National	Development	Planning Office	("DNP"),	whose	main	role	is	to	develop	a	general	development	plan	for	the	government.

Principal	Regulations.	The	laws	of	Domiciliary	Public	Services	and	the	Electricity	Law	set	the	institutional	arrangement	and	the	general	regulatory	framework	for the	electricity	sector.	The	keystones	of	the	electricity	regulation	are:	(i)	the	dispatch	is	based	on	an	offer	price	that	represents	the	variable	cost	of	the	plants;	(ii)	a contract-based	wholesale	generation	market;	(iii)	an	open	access	regime	for	transmission	with	revenue	regulated	for	existent	transmission	lines	and	open	bids	for	new lines;	(iv)	revenue	regulated	for	the	distribution	grid;	and	(v)	electricity	retail	can	be	performed	by	distribution	and/or	traders.

The	spot	market	started	in	July	1995,	and	in	1996	a	capacity	payment	was	introduced	for	a	term	of	ten	years.	In	December	2006,	a	regulation	was	enacted	that replaced	the	capacity	charge	with	the	reliability	charge	and	established	two	implementation	periods.	The	first	period	consists	of	a	transition	period	from	December	2006 to	November	2012	during	which	the	price	is	equal	to	$13.045	per	MWh	and	volume	is	determined	based	on	each	plant's	firm	energy	which	is	prorated	so	that	the	total firm	energy	level	does	not	exceed	system	demand.	During	the	second	period,	which	begins	on	December	2012,	the	reliability	charge	will	be	determined	based	on	the energy	price	and	the	volume	of	offers	submitted	by	market	participants	bidding	for	new	capacity	for	the	system.	The	first	reliability	charge	auction	was	held	in	May 2008	with	the	following	results:	(i)	the	reliability	charge	for	existing	plants	for	the	period	between	December	2012	and	November	2013	will	be	$13.998	per	MWh; (ii)	for	new	plants	that	won	the	auction,	the	charge	will	be	paid	for	twenty	years	starting	December	2012;	and	(iii)	three	new	projects	won	the	auction	for	a	total	capacity of	430	MW	starting	in	2012.	The	new	methodology	established	in	2006	recognized	the	reliability	provide	by	Chivor's	system	and	favored	the	company	by	increasing	the reliability	charge	by	approximately	120%,	moving	from	$18	million	in	2006	to	almost	$40	million	in	2007	and	is	expected	to	have	a	similar	amount	per	year	until	2015.

Environmental	Regulations.	In	Colombia,	Law	99	created	the	MMA	in	1993.	This	law	requires	that	projects	that	affect	the	land	or	impact	the	environment	must obtain	a	license	from	the	MMA.	While	regional	environmental	authorities	can	issue	licenses	for	generation	projects	with	capacity	of	less	than	100	MW,	only	the	MMA has	the	authority	to	issue	licenses	for	the	construction	of	large-scale	generation	or	transmission	projects.	Chivor	initiated	operations	in	1977	through	a	water	concession, the	only	environmental	requirement	at	that	time.	Furthermore,	in	August	1995	the	MMA	requested	hydroelectrical	plants,	including	Chivor	to	fulfill	the	requirements	of an	"Environmental	Management	Plan,"	which	serves	as	an	environmental	permit	to	operate.	Each	year,	Chivor	has	to	demonstrate	to	the	environmental	authorities	that the	obligations	included	in	such	plan	are	accordingly	fulfilled.	Additionally,	hydro	plants	must	contribute	6%	of	their	gross	generation	and	thermal	plants	4%	of	their gross	generation	to	the	area	of	influence	valued	at	a	special	tariff	defined	by	CREG.	In	2008,	MMA	issued	Resolution	909	that	regulates	the	emission	of	thermal	power plants.	This	Resolution	is	not	expected	to	affect	Chivor	because	it	is	a	hydro	but	could	affect	AES	if	we	decide	to	acquire	or	build	a	thermal	plant	in	Colombia.

Potential	or	Proposed	Regulations.	CREG	issued	a	proposal	to	create	the	Organized	Regulated	Market	("MOR").	The	MOR	will	replace	the	current	bilateral contracts	markets	(between	traders/utilities	and	generators)	by	putting	in	place	a	centralized	auction	in	which	the	Market	Administrator	buys	energy	for	all	regulated customers	served	by	the	traders/utilities.	The	main	provisions	contained	in	the	proposal	are:	(i)	it	is	mandatory	for	all	traders/utilities	to	buy	energy	at	the	auction	price and	it	is	voluntary	for	sellers	(generators	and	trade	companies)	to	offer	energy	in	each	auction;	(ii)	one	single	price	for	the	energy	sales	in	the	auction;	(iii)	the	auctions are	held	one	year	before	the	actual	dispatch	and	the	commitment	period	of	the	auction	is	one	year;	and	(iv)	to	establish	four	auctions	per	year.	Bilateral	contracts executed	before	the	beginning	of	the	MOR's	operation	will	not	suffer	any	change	and	will	remain	valid.	In	general,	we	consider	that	if	MOR	is	correctly	designed,	it should	benefit	our	businesses	in	Colombia.	We	expect	that	a	definitive	resolution	will	be	issued	in	the	first	half	of	2011.

During	2010,	MME	issued	Decree	2730	which	intends	to	solve	the	potential	long-term	and/or	cyclical	unavailability	of	gas	by	(i)	importing	LNG	and (ii)	establishing	strategic	storage	alternatives.	Also,	the	government	presented	the	basis	for	the	"National	Development	Plan	2011–2014."	For	the	electricity	sector,	the plan	mainly	focuses	on:	(i)	maintaining	stability	of	the	current	regulatory	framework,	supporting	the	current	reliability	charge	structure,	promoting	fair	competition among	technologies	and	guaranteeing	no	new	taxes	to	transactions	made	in	the	wholesale	market;	(ii)	assuring	energy	supply	for	the	medium	and	long	term; (iii)	enhancing	and	strengthening	the	electricity	market's	competitiveness	in	order	to	maintain	investment	confidence	and	convert	the	electricity	system	in	Colombia	into a	world	class	sector;	(iv)	making	the	right	decisions	in	the	natural	gas	sector	to	make	it	reliable;	and	(v)	promoting	institutional	improvement	guided	by	transparency, independence	and	efficiency.	Among	these	initiatives,	they	are	considering	reviewing	the	separation	of	National	Dispatch	Center	from	the	Commercial	Transactions Administrator	and	self-regulation	initiatives	to	avoid	or	minimize	interventions	in	the	market	by	the	government.	These	initiatives	also	seek	to	resolve	the	gas	supply problem	for	thermal	plants.	As	a	result,	we	believe	they	may	be	favorable	to	our	business	in	Colombia	because	they	may	improve	the	overall	reliability	of	the	electricity system	and	reduce	the	current	uncertainties.	Additionally,	we	believe	these	initiatives	may	help	Chivor	better	manage	its	water	resources	and	its	associated	risk	and	may also	provide	more	certainty	about	long	term	energy	prices.	Furthermore,	the	National	Development	Plan	proposal	aims	to	maintain	the	stability	and	certainty	of	the market	rules	in	order	to	consolidate	the	investor	trust.

As	a	part	of	CREG	regulatory	agenda	for	2011,	the	regulator	is	planning	to	review	the	lessons	learned	from	the	dry	conditions	brought	by	the	2009-10	"El	Niño" phenomenon	and	issue	regulations	for	these	extreme	events,	permitting	players	to	know	in	advance	the	additional	reliability	measures	that	the	regulator	may	take	under those	circumstances.	Also,	CREG	is	planning	to	issue	regulations	that	will	strengthen	the	energy	market	by	improving	the	spot	market	guarantees	scheme,	and	establish measures	to	control	market	power	from	pivotal	agents	(agents	needed	at	any	cost	to	fulfill	the	demand	requirements).	This	last	initiative	may	affect	spot	prices	but	should not	materially	impact	AES	as	Chivor	has	a	high	level	of	coverage	through	bilateral	contracts.

# Dominican	Republic

Structure	of	Electricity	Market.	The	Dominican	Republic	has	one	main	interconnected	system	composed	primarily	of	thermal	generation	and	supplemented	by hydroelectric	power	plants	that	harness	power	from	available	rivers.	The	regulatory	framework	in	the	Dominican	Republic	consists	of:	decentralized	industry;	unbundled generation,	transmission	and	distribution;	regulated	prices	in	monopolistic	segments	(transmission	and	distribution);	and	a	competitive	wholesale	generation	market.	In accordance	with	this	regulatory	structure,	all	agents	and	electric	generation,	transmission	and	distribution	companies	must	conduct	their	operations	to	provide	the	best service	at	minimum	cost;	and	comply	with	standards	of	quality,	safety,	continuity	of	services	and	conservation	of	the	environment.

The	spot	or	wholesale	market	is	based	on	a	centralized	economic	dispatch.	The	Organismo	Coordinador	("OC")	is	in	charge	of	planning	and	supervision	of operations	through	the	"Centro	del	Control	del	SENI,"	which	is	in	charge	of	real-time	dispatch.	The	dispatch	of	the	thermal	units	is	based	on	auditable	declared	variable costs	and,	for	the	hydro	units,	the	variable	cost	is	equal	to	zero,	meaning	that	these	units	are	the	first	for	dispatch	and	reflect	optimal	system	costs.	The	spot	market	relies on	competitive	bidding	based	on	each	generator's	variable	costs	as	a	means	of	providing	a	merit	order	for	dispatch.	Variable	cost	information	is	submitted	weekly	by	the generators	to	the	OC,	which	then	determines	the	merit	order	for	dispatch	based	on	this	information.

For	the	sale	of	electricity	under	long-term	contracts,	the	regulatory	framework	establishes	that	the	sale	of	electricity	of	a	generating	company	to	a	distribution company	will	be	done	at	prices	resulting	from	the	competitive	procedures	of	public	bidding.	These	bids	are	governed	by	the	conditions	established	by	the Superintendency	of	Electricity	("SIE")	which	supervises	the	bidding	and	awarding	process.	With	the	objective	of	ensuring	that	generation	prices	represent	reasonable values	in	the	market,	the	SIE	ensures	that	the	sale	of	electricity	through	contracts	is	not	greater	than	80%	of	interconnected	electric	energy	demand,	and	that	the	spot market	represents	a	minimum	of	20%	of	the	total	national	consumption	of	the	interconnected	system	annually.

The	electricity	tariff	applicable	to	regulated	customers	is	subject	to	regulation	within	the	concessions	of	the	distribution	companies.	Electricity	end-users	are considered	customers	of	public	services	according	to	regulations;	hence	the	tariff	is	set	by	resolution	of	the	SIE.	For	clients	with	demand	above	1.2	MW	who	are classified	as	unregulated	customers,	tariffs	are	unregulated.

Principal	Regulators.	In	order	to	regulate	the	electric	sector	and	implement	the	provisions	contained	in	the	General	Electricity	Law	No.	125	and	its	By-Law,	two regulators	are	responsible	for	monitoring	and	ensuring	compliance	with	the	law:	the	National	Energy	Commission	("CNE")	and	the	SIE.	All	electric	companies (generators,	transmission	and	distributors),	are	subject	to	and	regulated	by	the	General	Electricity	Law,	whether	they	are	of	national	and/or	foreign	capital,	private	and/or public.

In	general,	CNE's	main	responsibilities	are	to	draft	and	coordinate	the	legal	framework	and	regulatory	legislation;	propose	and	adopt	policies	and	procedures	to assure	best	practices;	draft	plans	to	ensure	the	proper	functioning	and	development	of	the	energy	sector	and	propose	them	to	the	executive	branch;	ensure	compliance with	the	law;	promote	investment	decisions	in	accordance	with	these	plans;	and	advise	the	executive	branch	on	all	matters	related	to	the	energy	sector.	The	SIE's	main responsibilities	are	to	develop,	ensure	compliance	with	and	analyze	the	structure	and	level	of	prices	of	electricity	and	to	set	the	rates	and	tolls	subject	to	regulation.	SIE also	reviews	electricity	rate	levels	requested	by	companies,	monitors	and	supervises	compliance	with	legal	provisions	and	rules	and	monitors	compliance	with	the technical	procedures	governing	generation,	transmission,	distribution	and	commercialization	of	electricity.	In	addition,	SIE	supervises	electric	market	behavior	in	order to	avoid	monopolistic	practices	and	applies	penalties	and	fines	in	the	cases	of	non-compliance	with	the	laws	and	regulations.

Principal	Regulations.	The	energy	sector	regulatory	framework	in	the	Dominican	Republic	is	governed	primarily	by:

•	 General	Electricity	Law	125-01,	its	by-law	and	its	amendment	by	Law	186-07,	constitute	the	legal	framework	which	regulates	all	phases	related	to	the production,	transmission,	distribution	and	commercialization	of	electricity,	as	well	as	the	functions	of	State	agencies	created	by	this	Law	and	related	to these	matters.	The	regulatory	framework	in	the	Dominican	electricity	market	establishes	a	methodology	for	calculating	the	firm	capacity	for	each	power generation	unit.

•	 Renewable	Energy	Incentives	Law	57-07	establishes	incentives	for	renewable	energy,	mainly	income	tax	exemption,	import	taxes	reduction,	as	well	as special	operational,	technical	and	commercial	treatment.	The	law	applies	to	hydro	generation	with	a	capacity	equal	to	or	below	5	MW,	wind	generation with	a	capacity	less	than	50	MW,	biomass	generation	with	a	capacity	less	than	80	MW,	photovoltaic	generation,	and	thermo-solar	generation	with	a capacity	less	than	120	MW.

•	 Hydrocarbons	Law	112-00	is	a	regime	that	established	a	tax	on	consumption	of	fossil	fuels	and	oil.	All	fossil	fuels	used	to	produce	electricity	has	a	tax exemption	under	the	law,	as	well	as	natural	gas,	and	any	change	in	this	regulation	does	not	affect	AES	Dominicana	as	a	natural	gas	provider.	All	agents that	use	any	fossil	fuel	to	produce	electricity	need	a	resolution	from	CNE	and	the	Industry	and	Commerce	Ministry	to	apply	for	this	exemption.

•Industry	and	Commerce	Ministry	periodic	resolutions	for	technical	and	price	regulations	for	vehicular	natural	gas	use	(transportation).

In	addition,	the	Dominican	government	has	directly	exercised	varying	degrees	of	regulation	over	the	electricity	market	and	AES	Dominicana's	businesses	in	the past,	such	as	involvement	in	the	re-negotiation	of	the	existing	PPAs,	oversight	responsibilities	of	the	SENI	and	environmental	controls.	No	assurance	can	be	given	that the	Dominican	government	will	not	alter	regulations	in	the	future	in	a	way	that	will	negatively	affect	AES	Dominicana's	businesses,	financial	conditions	or	results	of operations.

Environmental	Regulations.	The	main	environmental	regulations	are	the	General	Law	on	Environment	and	Natural	Resources	64-00	and	the	Regulation	and Licensing	Systems	Environmental	Permits	by-law.	These

regulations	provide	for	centralized	environmental	planning	by	the	state	through	the	integration	of	environmental	protection	and	economic	development	plans	in	a common	approach	and	policy	throughout	the	sector.	Environmental	management	is	achieved	through	permits	or	environmental	licenses,	environmental	quality	standards and	environmental	reporting.	The	main	regulatory	institutions	are:

•The	Ministry	for	the	Environment	and	Natural	Resources,	which	is	responsible	for	implementing	and	designing	the	policy	for	the	conservation	and protection	of	the	environment	and	natural	resources	in	the	Dominican	Republic;

•	 National	Council	of	Environment	and	Natural	Resources	which	is	the	link	between	the	various	Ministries	of	State	in	charge	of	evaluating	the	impact	of environmental	policies;	and

•Procurator	for	the	Defense	of	the	Environment	and	Natural	Resources,	which	is	responsible	for	performing	the	actions	by	the	State	Environmental	conflicts environment.

Despite	extensive	compliance	plans	in	place	by	each	of	the	entities,	it	is	possible	AES	Dominicana	generating	units	could	fall	out	of	compliance	with	such environmental	standards.	Such	non-compliance,	and	resulting	penalties	or	bad	publicity	might	negatively	affect	the	financial	results	of	AES	Dominicana.	One	such penalty	could	be	a	requirement	that	AES	Dominicana	operates	its	offending	unit	below	its	rated	capacity,	and	such	unavailability	might	affect	compliance	with obligations	under	its	PPAs.	In	such	a	scenario	AES	Dominicana	might	need	to	make	significant	investments	in	environmental-related	infrastructure.	In	addition,	the environmental	laws	and	regulations	may	become	more	stringent	and	AES	Dominicana	might	be	forced	to	make	certain	investments	to	be	compliant	with	the	new standards.

Potential	or	Proposed	Regulations.	Last	year,	the	CNE	proposed	a	Natural	Gas	Act,	which	seeks	to	establish	new	regulations	for	the	services	and	the commercialization	of	natural	gas,	which	may	result	in	access	barriers	to	develop	the	natural	gas	market.	The	proposed	law	does	not	establish	a	mechanism	for	promoting investments	in	the	construction	of	new	gas	pipelines	or	kits	for	fuel	conversion	for	the	automotive	sector	in	accordance	with	modern	regulation	in	this	market.	However, AES	does	not	currently	expect	any	material	impact	to	AES	Dominicana	with	the	promulgation	of	such	law,	mainly	because	AES	Dominicana's	role	is	as	a	supplier	of natural	gas	to	the	Dominican	Republic,	which	is	not	regulated	under	the	Natural	Gas	Act.

# El	Salvador

Structure	of	Electricity	Market.	The	Salvadorean	electricity	market	is	composed	of	a	single	interconnected	system.	Under	the	General	Electriticity	Law	("GEL"), competition	was	introduced	in	generation	and	trading	and	additional	regulations	were	implemented	related	to	price	and	quality	of	service	in	non-competitive	segments such	as	distribution,	transmission,	system	operation	and	administration.

The	wholesale	electricity	market	is	based	on	a	contract	market	and	a	spot	market.	The	contract	market	is	further	classified	into	bilateral	contracts,	which	are	freely negotiated	by	electricity	generators,	distributors,	and	trading	companies;	and	regulated	contracts,	which	are	the	product	of	regulated	public	bids	carried	out	by	the distribution	companies	under	the	supervision	of	the	Regulator,	Superintendencia	General	de	Electricidad	y	Telecomunicaciones	("SIGET").	Starting	in	June	2011,	the distribution	companies	are	required	to	acquire	70%	of	their	forecasted	demand	through	regulated	bids.	The	spot	market	is	structured	as	a	day-ahead	market,	and transactions	are	settled	on	a	monthly	basis.	Currently,	the	price-setting	mechanism	for	the	spot	market	is	based	on	a	bidding	system.	Regulations	are	in	place	to implement	a	cost-based	system	to	replace	the	current	bidding	system.

Distribution	companies	are	regulated	under	an	incentive	system,	specifically	a	Revenue	Cap	system,	whereby	the	maximum	tariff	to	be	charged	to	the	end-users is	subject	to	the	approval	of	SIGET.	The	components	of	the	electricity	tariff	are	(i)	charges	for	the	use	of	the	distribution	network	(the	"Distribution	Charge"), (ii)	customer	service	costs	(the	"Service	Charge")	and	(iii)	average	energy	price	(the	"Energy	Charge").	Both	the

Distribution	Charge	and	Service	Charge	are	based	on	average	capital	costs	as	well	as	operation	and	maintenance	costs	of	an	efficient	distribution	company.	The Distribution	Charge	and	Service	Charge	are	approved	by	SIGET	every	five	years	and	have	two	adjustments:	(i)	an	annual	adjustment	considering	the	inflation	variation and	(ii)	an	automatic	adjustment	in	April,	July	and	October,	provided	that	the	change	in	inflation	is	greater	than	10%.

Competition	is	encouraged	by	the	GEL	and	it	provides	the	end	user	with	the	option	to	acquire	its	electricity	from	a	Distribution	Company	or	an	electricity	trader. The	Distribution	and	Transmission	Companies	are	mandated	by	the	GEL	to	allow	the	use	of	the	distribution	grid	to	traders	in	order	to	deliver	electricity	to	their customers.	The	grid	access	terms,	including	tariffs,	are	detailed	in	a	"distribution	contract"	registered	and	regulated	by	SIGET.

Principal	Regulators.	SIGET	is	the	Independent	Regulatory	Authority	established	through	the	GEL.	SIGET's	principal	responsibilities	and	attributions	are approval	of	Distribution	Charges,	enforcement	of	sector	regulation,	dispute	resolution	among	market	participants,	granting	concessions	for	hydroelectric	and	geothermal projects,	among	others.

In	addition,	the	National	Energy	Council,	formed	in	2007,	is	the	policy-making	entity,	whose	board	of	directors	is	composed	by	the	Secretaries	of	the	Treasury, the	Economy,	Public	Works,	Environmental	and	Natural	Resources	and	the	Consumer	Protection	Agency.

Principal	Regulations.	The	electricity	sector	is	governed	by	the	General	Electricity	Act,	the	General	Electricity	Act	Regulations,	the	Transmission	System	and Wholesale	Market	Operating	Regulations	and	the	general	and	specific	orders	issued	by	SIGET,	under	its	statutory	attributions.

Environmental	Regulations.	The	environment	is	protected	through	the	Environment	and	Natural	Resources	Act	("ENRA"),	enacted	in	1998,	and	it's	Regulation, enacted	in	2000.	These	statutes	empower	the	Environment	and	Natural	Resources	Secretary	as	the	policy-making	entity	and	ENRA	establishes	a	duty	of	care	to	the environment	and	orders	the	sustainable	use	of	natural	resources.	Additionally,	ENRA	introduces	the	concept	of	the	Environmental	Permit	for	the	handling	of	certain potentially	hazardous	or	risky	materials	or	performing	certain	activities	in	the	environment,	such	as	the	construction	and	operation	of	power	plants	(except	fuel	oil)	and transmission	lines.

Material	Regulatory	Actions.	The	Energy	Charge	has	been,	under	current	methodology,	adjusted	every	six	months	to	reflect	the	spot	market	price	for	electricity during	the	previous	six	months.	However,	starting	on	January	12,	2011,	the	energy	charge	will	be	adjusted	quarterly.	Presidential	decree	160	was	published	on December	23,	2010	and	went	into	effect	on	January	1,	2011.	This	decree	shortens	the	Energy	Charge	reset	period	from	six	months	to	three	months;	the	new	Energy Charge	reset	dates	will	be	January	12th,	April	12th,	July	12th	and	October	12th	instead	of	April	12th	and	Oct	12th	each	year.	The	reduction	of	the	"energy	charge"	reset period	reduces	the	distribution	companies'	cash	flow	exposure	before	any	significant	spike	in	energy	prices	since	the	lag	between	energy	revenues	and	costs	has	been reduced	by	half.

Potential	or	Proposed	Regulations.	The	Transmission	System	and	Wholesale	Market	Operating	Rules	have	been	amended	to	convert	the	wholesale	market	price- setting	mechanism	to	be	based	on	audited	variable	production	costs	instead	of	a	competitive	bidding	process	and	will	become	effective	in	June	2011.	However,	this effective	date	may	be	delayed	due	to	technical	delays	necessary	for	implementation.	Again,	since	electricity	costs	are	a	pass-through	for	distribution	companies,	such new	regulation	will	have	an	indirect	benefit	to	the	companies	by	providing	a	stable,	marginal	cost	of	electricity.

# Nigeria

Structure	of	Electricity	Market.	In	Nigeria,	the	state-owned	entity,	Power	Holding	Company	of	Nigeria	("PHCN"),	holds	approximately	80%	of	the	electricity market	share	and	private	power	generating	companies	account	for	the	remaining	20%.	The	power	generating	companies,	of	which	AES	Nigeria	Barge	Ltd.	("AESNB") is	one,	maintain	long-term	contracts	with	PHCN	as	the	sole	offtaker.

All	power	transmission	operations	are	currently	carried	out	by	PHCN.	Under	new	political	initiatives	and	reforms,	as	provided	under	the	Roadmap	for	Power Sector	Reforms	("the	Power	Roadmap"),	there	are	indications	that	11	distribution	companies	and	six	generation	companies	would	be	fully	privatized	while	the ownership	of	the	Transmission	Company	of	Nigeria	("TCN")	would	be	retained	by	the	government,	but	with	private	sector	management.	Current	electricity	generation	is from	either	gas-fired	or	hydro	power	plants.	Most	assets	are	owned	by	state-owned	companies,	though	some	private	investors	have	been	able	to	establish	IPPs	following recent	reforms.	In	addition,	the	government	is	developing	approximately	4,800	MW	of	installed	capacity	intended	to	be	completed	by	2013,	known	as	the	National Integrated	Power	Plants	("NIPPs").	The	Presidential	Task	Force	on	Power	has	announced	its	intention	to	privatize	the	NIPPs	in	future	rounds	of	privatization,	following completion	of	construction.

Principal	Regulators.	The	Nigerian	Electricity	Regulatory	Commission	("Nigerian	ERC")	is	an	independent	regulatory	agency,	that	was	established	under	the 2005	Reform	Act	to	undertake	both	the	technical	and	economic	regulation	of	the	Nigerian	electricity	sector.	It	is	responsible	for	general	oversight	functions,	including the	licensing	of	operators,	setting	of	tariffs	and	industry	standards	for	future	electricity	sector	development.

Two	of	the	Nigerian	ERC's	key	regulatory	functions	are	licensing	and	tariff	regulation.	Since	AESNB	operates	under	a	long-term	bilateral	agreement	with PHCN,	it	is	not	subject	to	the	tariff	setting	process.	On	the	basis	of	the	current	reforms	embodied	in	the	Power	Roadmap,	a	number	of	new	regulatory	and/or	other governing	bodies	will	be	established	to	regulate	the	industry.

Principal	Regulations.	In	March	2005,	the	Nigerian	President	signed	the	Electric	Power	Sector	Reform	Bill	into	law,	enabling	private	companies	to	participate	in transmission	and	distribution	in	addition	to	electricity	generation	that	had	previously	been	legalized.	The	government	has	separated	PHCN	into	eleven	distribution	firms, six	generating	companies,	and	a	transmission	company,	in	preparation	for	privatization.

Several	problems,	including	union	opposition,	have	delayed	the	privatization	indefinitely,	however,	in	recent	months	the	current	Government	has	put	significant emphasis	on	completing	the	privatization	of	the	eighteen	successor	companies	of	the	PHCN	in	2011.	There	are	clauses	in	the	AESNB	PPA	that,	upon	the	effective	date of	a	privatization,	require	the	business	to	use	all	reasonable	endeavors	to	obtain	and	require	all	fuel	necessary	for	the	operation	of	the	plant.	Additionally,	the	off-taker	is envisaged	to	be	transferred	from	PHCN	to	Lagos	State.	However,	no	material	impact	to	our	operations	is	expected	at	this	time.

Potential	or	Proposed	Regulations.	The	Nigerian	Government	is	currently	preparing	for	an	election	in	2011	and	privatization	of	the	electricity	sector	has	been	a principal	issue	emphasized	by	political	parties.	The	2005	Reform	Act	and	NERC	regulations	provide	for	a	generation	license	to	have	a	duration	of	10	years,	renewable for	a	further	five	years.	This	is	in	line	with	a	current	proposal	for	a	uniform	tariff	for	the	power	sector,	MYTO,	which	is	derived	from	a	building	blocks	approach	that intends	a	cost-reflective	outcome,	including	a	capacity	and	an	energy	component;	financing	costs	and	other	key	costs	(operating	costs,	depreciation)	are	intended	to	be accommodated;	and	key	fluctuating	costs	(fuel	costs,	foreign	exchange,	inflation)	are	also	intended	to	be	reflected.	A	total	license	and	uniform	tariff	duration	of	15	years may	present	challenges	to	potential	investors	given	that	15	years	may	be	shorter	than	the	useful	life	of	assets	and	shorter	than	the	tenor	of	potential	long-term	debt financing.	These	regulations,	if	adopted,	could	make	it	difficult	to	acquire	or	develop	new	facilities.

# Panama

Structure	of	Electricity	Market.	In	Panama,	distribution	companies	are	required	to	contract	100%	of	their	annual	power	requirements	(although	they	can	self- generate	up	to	15%	of	their	demand).	Generators	can	enter	into	long-term	PPAs	with	distributors	or	unregulated	consumers.	In	addition,	generators	can	enter	into alternative	supply	contracts	with	each	other.	The	terms	and	contents	of	PPAs	are	determined	through	a	competitive	bidding	process	and	are	governed	by	the	Commercial Rules.	Besides	the	PPA	market,	generators	may	buy	and	sell	energy	in	the	spot	market.	Energy	sold	in	the	spot	market	corresponds	to	the	hourly	differences	between	the actual	dispatch	of	energy	by	each	generator	and	its	contractual	commitments	to	supply	energy.	The	energy	spot	price	is

set	by	the	order	in	which	generators	are	dispatched.	The	National	Dispatch	Center	("CND")	ranks	generators	according	to	their	variable	cost	(thermal)	and	water	value (hydroelectric),	starting	with	the	lowest	value,	thereby	establishing	on	an	hourly	basis	the	merit	order	in	which	generators	will	be	dispatched	the	following	day	in	order	to meet	expected	demand.

Principal	Regulators.	The	National	Secretary	of	Energy	("SNE")	was	created	by	Law	52	on	July	30,	2008;	and	has	the	responsibilities	of	planning,	investigating, directing,	supervising	and	controlling	policies	of	the	energy	sector	within	Panama.	With	these	responsibilities,	the	Secretariat	has	defined	strategies	and	policies	for	the Republic	of	Panama,	which	include	promoting	energy	security	for	the	benefit	of	the	population	and	the	country's	development,	and	proposing	laws	and	regulations	to	the executive	agency	that	promote	the	procurement	of	electrical	energy,	hydrocarbons	and	alternative	energies	in	the	best	conditions	for	the	country.	The	regulator	of	public services,	known	as	the	National	Authority	of	Public	Services	("ASEP"),	was	created	by	Law	26	on	January	29,	1996.	ASEP	is	an	autonomous	agency	of	the	state,	with legal	responsibility	and	self-patrimony.	ASEP	is	responsible	for	the	control	and	oversight	of	public	services,	such	as	potable	water,	sewerage,	electricity,

telecommunications	and	radio	and	television	systems,	as	well	as	the	transmission	and	distribution	of	natural	gas	utilities	and	the	companies	that	provide	such	services. ASEP's	mission	is	to	ensure	the	efficient	provision	of	the	public	services,	as	well	as	national	technical,	commercial,	and	environmental	quality	standards.

Principal	Regulations.	In	the	Republic	of	Panama,	the	electricity	sector	is	regulated	by	Law	No.	6	issued	on	February	1997	which	was	amended	by	Law	Decree	10 on	February	26,	1998,	and	more	recently	by	Law	57	on	October	2009.	The	most	notable	amendments	by	Law	57	were:	(i)	generators	are	now	obligated	to	participate	in public	bids	for	PPAs,	to	the	extent	they	have	available	firm	capacity	and	energy,	and	failure	to	do	so	precludes	them	from	participating	in	the	spot	market;	(ii)	ETESA, as	opposed	to	the	distribution	companies,	will	now	be	the	purchaser	in	charge	of	adjudicating	PPA	bids	to	the	winning	generators,	subsequently	assigning	such	PPAs	to the	corresponding	distribution	companies;	and	(iii)	the	maximum	fines	which	ASEP	may	impose	for	violations	to	the	provisions	of	the	Electricity	Law	increased	from	$1 million	to	$20	million.	Resolution	AN	No.	3885-Elec,	which	was	approved	on	October	8,	2010,	sets	forth	the	methodology	for	calculating	the	capacity	and/or	energy that	generators	must	make	available	for	short	term	bids	and	long	term	contracting.

These	amendments	state	that	ETESA	has	to	prepare	the	list	of	charges,	make	the	call	for	bids	and	evaluate	and	award	contracts	for	supply	in	accordance	with	the parameters,	criteria	and	procedures	established	by	ASEP.	Consequently,	ASEP	must	approve	the	list	of	charges	produced	by	ETESA	in	addition	to	overseeing	the process	to	confirm	it	complies	with	legal	requirements	and	current	regulations.

Environmental	Regulations.	ASEP	issued	Resolution	AN	No.	3932-Elec	on	October	22,	2010	related	to	the	Security	of	Dams	in	the	Electricity	Sector.	This legislation	has	sensitive	and	important	Security	and	Environmental	elements	related	to:	reports,	controls	by	ASEP,	protocols	for	modifications	to	the	structure	of	the dams	and	the	operation	of	dams	and	reservoirs	during	floods.	This	regulation	will	be	effective	on	November	9,	2011,	but	it	will	require	a	thorough	process	to	review	our current	action	plans	during	emergencies	and	protocols	against	the	requirements	of	the	new	law	to	properly	determine	the	impact	to	AES	Panama.	However,	the	new requirements	may	require	AES	Panama	to	expend	additional	amounts	which	could	have	a	material	adverse	impact	on	our	business	and	results	of	operations.

Material	Regulatory	Actions.	By	virtue	of	Resolutions	AN	No.	34-01-Elec	on	April	1,	2010	and	Resolution	AN	No.	3852-Elec	on	September	21,	2010,	ASEP declared	the	Changuinola	I	project	to	be	of	public	interest	and	urgent	necessity	(granting	AES	access	to	private	properties	near	the	project).	The	owner	of	one	of	the Fincas	(land)	filed	a	constitutional	action	alleging	violations	of	due	process	and	private	property	rights.	The	impact	to	the	business	is	that	if	the	Supreme	Court	admits	the request,	this	will	automatically	suspend	the	effects	of	the	ASEP	resolution	and	the	project	will	no	longer	be	of	public	interest.	This	could	impact	AES	Panama's authorization	with	regard	to	the	premises	and	impede	progress	on	the	project.	AES	Panama	has	requested	that	the	Supreme	Court	reject	the	action	filed.	For	further discussion	see	Item	3.—Legal	Proceedings	in	this	Form	10-K.

Potential	or	Proposed	Regulations.	In	July	2010,	ASEP	hired	Consorcio	Fundación	Bariloche-PSI	Consultores	to	evaluate	alternative	allocation	of	the	Charge	per Usage	of	the	Principal	Transmission	System	in	order	to	encourage	the	development	of	alternative	sources	of	generation,	especially	hydropower.	The	consultants	expect to	deliver	their	final	report	by	mid-January	2011	to	ASEP	but	as	of	mid-February	2011	the	consultants	have	not	delivered	the	report.	Once	ASEP	receives	the	report	it	is expected	to	present	the	amendments	to	the	current	transmission	rates	for	public	comment	and	the	amendments	are	expected	to	take	effect	on	July	1,	2011.	This	could result	in	a	possible	reduction	of	the	amounts	currently	being	paid	by	AES	Panama	in	transmission	rates.

On	October	13,	2010,	ASEP	requested	the	CND	to	make	an	amendment	to	the	weekly	programming	methodology	so	that	the	hydroelectric	dams	with	a	reservoir regulation	equal	to	or	less	than	ninety	(90)	days	should	be	modeled	as	run-of-the-river	units	with	zero	variable	cost.	Under	the	current	regulations,	the	Changuinola	I Plant	is	defined	as	a	hydro	plant	with	a	reservoir	regulation	of	7.26	days.	The	proposed	modification	will	cause	the	Changuinola	I	Plant	to	be	considered	as	a	run-of-the- river	plant.	It	is	estimated	that	this	change	could	result	in	a	reduction	in	energy	generated	by	approximately	18	GWh/year	for	AES	Panama,	which	is	a	substantial	impact on	AES	Panama	and	could	have	an	adverse	impact	on	our	businesses	and	results	of	operations.	Furthermore,	this	proposal	could	change	the	firm	capacity	of Changuinola	II.	Currently,	the	proposal	is	under	analysis	by	ASEP.

# Mexico

Structure	of	Electricity	Market.	Mexico	has	a	single	national	electricity	grid	(referred	to	as	the	"National	Interconnected	System"),	covering	nearly	all	of	Mexico's territory.	The	only	exception	is	the	Baja	California	peninsula	which	has	its	own	separate	electricity	system.	Article	27	of	the	Mexican	Constitution	reserves	the generation,	transmission,	transformation,	distribution	and	supply	of	electric	power	exclusively	to	the	Mexican	State	for	the	purpose	of	providing	a	"public	service."

In	Mexico,	since	1995	the	power	sector	legal	framework	partially	opened	to	private	entities	under	the	following	schemes:	cogeneration;	self	supply;	IPP	exports; and	imports	for	self	consumption.	Private	investments	are	allowed	today	in	this	sector	in	the	following	areas:	transport,	storage,	and	distribution.	The	Energy	Regulatory Commission	("CRE")	is	in	charge	of	issuing	the	permits	related	to	the	activities	from	the	power	and	natural	gas	sectors	that	were	open	to	private	investment	since	1995.

Principal	Regulators.	The	Federal	Electricity	Commission	("CFE"),	by	virtue	of	Article	1	of	the	Energy	Law,	is	granted	sole	and	exclusive	responsibility	for providing	this	public	service	as	it	relates	to	the	supply,	transmission	and	distribution	of	electric	power.

Principal	Regulations.	In	1992,	the	Energy	Law	was	amended	to	allow	private	parties	to	invest	in	certain	activities	in	the	Mexico	electrical	power	market,	under the	assumption	that	"self-supply"	generation	of	electric	power	is	not	considered	a	public	service.	These	reforms	allowed	private	parties	to	obtain	permits	from	the Ministry	of	Energy	for	(i)	generating	power	for	self-supply;	(ii)	generating	power	through	co-generation	processes;	(iii)	generating	power	through	independent production;	(iv)	small-scale	production;	and	(v)	importing	and	exporting	electrical	power.	Beneficiaries	holding	any	of	the	permits	contemplated	under	the	Energy	Law are	required	to	enter	into	PPAs	with	the	CFE	with	regard	to	all	surplus	power	produced.	It	is	under	this	basis	that	AES'	Mérida	and	TEG/TEP	facilities	operate.	Mérida provides	power	exclusively	to	CFE	under	a	long-term	contract.	TEG/TEP	provides	the	majority	of	its	output	to	two	offtakers	under	long-term	contracts,	and	can	sell	any excess	or	surplus	energy	produced	to	CFE	at	a	predetermined	day-ahead	price.

Environmental	Impact.	When	works	or	activities	that	may	disrupt	the	ecological	balance	or	exceed	the	limits	and	conditions	established	in	the	applicable	laws	or the	regulations	are	proposed,	these	activities	shall	be	subject

to	the	conditions	established	by	regulatory	authorities,	for	the	purposes	of	reducing	to	a	minimum	the	negative	effects	on	the	environment.	In	these	cases,	it	is	necessary to	first	obtain	the	authorization	on	environmental	impact	matters	from	the	regulatory	authorities.

In	addition,	high	risk	activities	are	also	regulated	even	though	they	do	not	define	specifically	what	is	meant	by	"high	risk."	The	Mexican	Department	of	the Interior	issued	two	lists	defining	high	risk	substances.	The	criteria	used	to	determine	whether	an	activity	is	of	high	risk,	is	based	in	the	characteristics	or	volume	of	the substance	used,	where	relevant.	If	in	the	event	of	being	spilt	or	released	it	is	liable	to	cause	an	explosion	or	significantly	affect	the	environment,	people	or	property,	it will	be	considered	as	of	'high	risk'.	Further,	if	a	project	contemplates	the	use	of	a	compound	included	in	the	lists	issued	by	the	regulator,	in	the	necessary	volumes,	the interested	Party	must	present	a	Risk	Evaluation	before	the	regulator.

Environmental	Sanctions.	The	Attorney	General's	Office	for	the	Protection	of	the	Environment	is	in	charge	of	enforcing	environmental	legal	provisions	in Mexico.	The	sanctions	that	may	be	imposed	depend	on	the	environmental	obligations	that	are	not	observed	by	individuals	or	corporations,	and	vary	from	fines	ranging from	the	equivalent	of	50	and	up	to	50,000	days	of	minimum	wage.	Additional	sanctions	may	also	be	imposed,	including	the	annulment	of	environmental	permits	and authorizations,	partial	or	total	closures	of	a	facility,	and	administrative	arrest.

Mexican	Legislation	provides	that	the	energy	sector	is	integrated	by	the	Electrical	and	Petroleum	sectors.	Federation	is	the	only	one	entitled	to	extract	and	process fossil	fuels,	as	well	as	to	generate	electricity;	however,	certain	exceptions	apply.

Renewable	Energy.	On	October	23,	2008,	a	proposal	for	the	approval	of	the	Renewable	Energies	and	Financing	of	the	Energy	Transition	Law	was	sent	for	the approval	of	the	Mexican	House	of	Representatives,	and	on	October	25,	2008,	this	same	proposal	was	approved	by	the	Energy	Committee	of	the	same	House.	The	law encourages	generation	and	transportation	of	energy	generated	by	renewable	sources,	giving	certainty	and	lower	costs	to	provide	incentives	to	participate	in	the	private sector	of	this	field.

In	addition,	the	Federal	government's	all-encompassing	Special	Program	on	Climate	Change	("SPECC")	was	formally	approved.	The	SPECC	provides	a	program to	reduce	the	alleged	effects	of	climate	change.	The	principal	actions	proposed	to	achieve	competitive	levels,	include	the	gradual	substitution	of	oil	for	natural	gas	in	the national	energy	mix,	stimulating	the	implementation	of	cogeneration	and	other	efficiency	saving	technologies	and	strongly	stimulating	the	development	of	renewable energies.

Priority	will	be	given	to	electricity	generation	from	wind	(up	to	507	MW	installed	by	2012),	geothermal	energy	(153	MW	installed	by	2012),	hydroelectric	and solar	power.	The	SPECC	proposes	a	joint	program	between	public	bodies	and	private	investors	in	order	to	increase	the	amount	of	electricity	generation	capacity	from renewable	sources	up	to	1,957	MW	by	2012.

The	SPECC	makes	it	clear	that	many	of	its	objectives	will	be	achieved	through	the	following	normative,	economic	and	market	instruments:	accessible	financing mechanisms;	simplification	procedures	for	permitting;	facilitation	of	electrical	grid	interconnection	and	transmission	contracts;	and	stimulus	for	private	investment	in energy	infrastructure.	Our	businesses	in	Mexico	are	still	reviewing	the	impact	of	these	developments	on	their	operations;	however,	they	could	be	material	to	the	business and	results	of	operations.

Structure	of	Electricity	Market.	The	United	States	wholesale	electricity	market	consists	of	multiple	distinct	regional	markets	that	are	subject	to	both	federal regulation,	as	implemented	by	the	FERC,	and	regional	regulation	as	defined	by	rules	designed	and	implemented	by	the	Independent	System	Operators	("ISO").	These rules	for	the	most	part	govern	such	items	as	the	determination	of	the	market	mechanism	for	setting	the	system	marginal	price

for	energy	and	the	establishment	of	guidelines	and	incentives	for	the	addition	of	new	capacity.	The	current	regulatory	framework	in	the	United	States	is	the	result	of	a series	of	regulatory	actions	that	have	taken	place	over	the	past	two	decades,	as	well	as	numerous	policies	adopted	by	both	the	federal	government	and	the	individual states	that	encourage	competition	in	wholesale	and	retail	electricity	markets.

Principal	Regulators.	The	federal	government,	through	regulations	promulgated	by	FERC,	has	primary	jurisdiction	over	wholesale	electricity	markets	and transmission	services.	While	there	have	been	numerous	federal	statutes	enacted	during	the	past	32	years,	including	the	Public	Utility	Regulatory	Policy	Act	of	1978 ("PURPA"),	the	Energy	Policy	Act	of	1992	("EPAct	1992")	and	the	Energy	Policy	Act	of	2005	("EPAct	2005"),	there	are	two	fundamental	regulatory	initiatives implemented	by	FERC	during	that	time	frame	that	directly	impact	our	United	States	businesses:

•FERC	approval	of	market-based	rate	authority	beginning	in	1986	for	many	providers	of	wholesale	generation;	and

•FERC	issuance	of	Order	#888	in	1996	mandating	the	functional	separation	of	generation	and	transmission	operations	and	requiring	utilities	to	provide	open access	to	their	transmission	systems.

FERC	has	civil	penalty	authority	over	violations	of	any	provision	of	Part	II	of	the	Federal	Power	Act	("FPA")	which	concerns	wholesale	generation	or transmission,	as	well	as	any	rule	or	order	issued	thereunder.	FERC	is	authorized	to	assess	a	maximum	civil	penalty	of	$1	million	per	violation	for	each	day	that	the violation	continues.	The	FPA	also	provides	for	the	assessment	of	criminal	fines	and	imprisonment	for	violations	under	Part	II	of	the	FPA.	This	penalty	authority	was enhanced	in	EPAct	2005.	With	this	expanded	enforcement	authority,	violations	of	the	FPA	and	FERC's	regulations	could	potentially	have	more	serious	consequences than	in	the	past.

Pursuant	to	EPAct	2005,	the	North	America	Reliability	Corporation	("NERC")	has	been	certified	by	FERC	as	the	Electric	Reliability	Organization	("ERO")	to develop	mandatory	and	enforceable	electric	system	reliability	standards	applicable	throughout	the	United	States	to	improve	the	overall	reliability	of	the	electric	grid. These	standards	are	subject	to	FERC	review	and	approval.	Once	approved,	the	reliability	standards	may	be	enforced	by	FERC	independently,	or,	alternatively,	by	the ERO	and	regional	reliability	organizations	with	responsibility	for	auditing,	investigating	and	otherwise	ensuring	compliance	with	reliability	standards,	subject	to	FERC oversight.	Monetary	penalties	of	up	to	$1	million	per	day	per	violation	may	be	assessed	for	violations	of	the	reliability	standards.

Principal	Regulations	for	Generation	Businesses.	Several	of	our	generation	businesses	in	the	United	States	currently	operate	as	Qualifying	Facilities	("QFs")	as defined	under	PURPA.	These	businesses	entered	into	long-term	contracts	with	electric	utilities	that	had	a	mandatory	obligation	at	that	time,	as	specified	under	PURPA, to	purchase	power	from	QFs	at	the	utility's	avoided	cost	(i.e.,	the	likely	costs	for	both	energy	and	capital	investment	that	would	have	been	incurred	by	the	purchasing utility	if	that	utility	had	to	provide	its	own	generating	capacity	or	purchase	it	from	another	source).	EPAct	2005	later	amended	PURPA	to	provide	for	the	elimination	of the	mandatory	purchase	obligation	in	certain	markets,	but	did	so	only	on	a	prospective	basis.	Cogeneration	facilities	and	small	power	production	facilities	that	meet certain	criteria	can	be	QFs.	To	be	a	QF,	a	cogeneration	facility	must	produce	electricity	and	useful	thermal	energy	for	an	industrial	or	commercial	process	or	heating	or cooling	applications	in	certain	proportions	to	the	facility's	total	energy	output,	and	must	meet	certain	efficiency	standards.	To	be	a	QF,	a	small	power	production	facility must	generally	use	a	renewable	resource	as	its	energy	input	and	meet	certain	size	criteria.

Our	non-QF	generation	businesses	in	the	United	States	currently	operate	as	Exempt	Wholesale	Generators	("EWGs")	as	defined	under	EPAct	1992.	These businesses	were	historically	exempt	from	the	Public	Utility	Holding	Company	Act	of	1935	and	are	also	exempt	from	the	Public	Utility	Holding	Company	Act	of	2005 ("PUHCA	2005"),	and,	subject	to	FERC	approval,	have	the	right	as	public	utilities	under	the	FPA	to	sell	power	at	market-based	rates,	either	directly	to	the	wholesale market	or	to	a	third-party	offtaker	such	as	a	power	marketer	or	utility/industrial	customer.	Under	the	FPA	and	FERC's	regulations,	approval	from	FERC	to	sell

wholesale	power	at	market-based	rates	is	generally	dependent	upon	a	showing	to	FERC	that	the	seller	lacks	market	power	in	generation	and	transmission,	that	the	seller and	its	affiliates	cannot	erect	other	barriers	to	market	entry	and	there	is	no	opportunity	for	abusive	transactions	involving	regulated	affiliates	of	the	seller.	To	prevent market	manipulation,	FERC	requires	sellers	with	market-based	rate	authority	to	file	certain	reports,	including	a	triennial	updated	market	power	analysis	for	markets	in which	they	control	certain	threshold	amounts	of	generation.

Principal	Regulations	for	Traditional	Utility	Business.	In	addition	to	our	generation	businesses,	we	also	own	IPL,	a	vertically	integrated	utility	located	in	Indiana. A	description	of	the	regulatory	environment	under	which	IPL	operates	is	provided	below:

IPL.	As	a	regulated	electric	utility,	IPL	is	subject	to	regulation	by	the	FERC	and	the	Indiana	Utility	Regulatory	Commission	("IURC").	As	indicated	below,	the financial	performance	of	IPL	is	directly	impacted	by	the	outcome	of	various	regulatory	proceedings	before	the	IURC	and	FERC.

IPL	is	subject	to	regulation	by	the	IURC	with	respect	to	the	following:	its	services	and	facilities;	the	valuation	of	property;	the	construction,	purchase	or	lease	of electric	generating	facilities;	the	classification	of	accounts;	rates	of	depreciation;	retail	rates	and	charges;	the	issuance	of	securities	(other	than	evidences	of	indebtedness payable	less	than	twelve	months	after	the	date	of	issue);	the	acquisition	and	sale	of	some	public	utility	properties	or	securities;	and	certain	other	matters.

IPL's	tariff	rates	for	electric	service	to	retail	customers	(basic	rates	and	charges)	are	set	and	approved	by	the	IURC	after	public	hearings	("general	rate	cases"). General	rate	cases,	which	have	occurred	at	irregular	intervals,	include	the	participation	of	consumer	advocacy	groups	and	certain	customers.	The	last	general	rate	case for	IPL	was	completed	in	1995.	In	addition,	pursuant	to	statute,	the	IURC	is	to	conduct	a	periodic	review	of	the	basic	rates	and	charges	of	all	Indiana	utilities	at	least once	every	four	years,	but	the	IURC	has	the	authority	to	review	the	rates	of	any	Indiana	utility	at	any	time	it	chooses.	Such	reviews	have	not	been	subject	to	public hearings.

The	majority	of	IPL	customers	are	served	pursuant	to	retail	tariffs	that	provide	for	the	monthly	billing	or	crediting	to	customers	of	increases	or	decreases, respectively,	in	the	actual	costs	of	fuel	(including	purchased	power	costs)	consumed	from	estimated	fuel	costs	embedded	in	basic	rates,	subject	to	certain	restrictions	on the	level	of	operating	income.	These	billing	or	crediting	mechanisms	are	referred	to	as	"trackers."	This	is	significant	because	fuel	and	purchased	power	costs	represent	a large	and	volatile	portion	of	IPL's	total	costs.	In	addition,	IPL's	rate	authority	provides	for	a	return	on	IPL's	investment	and	recovery	of	the	depreciation	and	operation and	maintenance	expenses	associated	with	certain	IURC-approved	environmental	investments.	The	trackers	allow	IPL	to	recover	the	cost	of	qualifying	investments, including	a	return	on	investment,	without	the	need	for	a	general	rate	case.

IPL	may	apply	to	the	IURC	for	a	change	in	its	fuel	charge	every	three	months	to	recover	its	estimated	fuel	costs,	including	the	energy	portion	of	purchased	power costs,	which	may	be	above	or	below	the	levels	included	in	its	basic	rates	and	charges.	IPL	must	present	evidence	in	each	fuel	adjustment	charge	("FAC")	proceeding that	it	has	made	every	reasonable	effort	to	acquire	fuel	and	generate	or	purchase	power,	or	both,	so	as	to	provide	electricity	to	its	retail	customers	at	the	lowest	cost reasonably	possible.

Independent	of	the	IURC's	ability	to	review	basic	rates	and	charges,	Indiana	law	requires	electric	utilities	under	the	jurisdiction	of	the	IURC	to	meet	operating expense	and	income	test	requirements	as	a	condition	for	approval	of	requested	changes	in	the	FAC.	Additionally,	customer	refunds	may	result	if	IPL's	rolling	twelve- month	operating	income,	determined	at	quarterly	measurement	dates,	exceeds	IPL's	authorized	annual	jurisdictional	net	operating	income	and	there	are	not	sufficient applicable	cumulative	net	operating	income	deficiencies	against	which	the	excess	rolling	twelve-month	jurisdictional	net	operating	income	can	be	offset.

In	IPL's	ten	most	recently	approved	FAC	filings	(FAC	81	through	90),	the	IURC	found	that	IPL's	rolling	annual	jurisdictional	retail	electric	net	operating	income was	lower	than	the	authorized	annual	jurisdictional	net

operating	income.	FAC	90	includes	the	twelve	months	ended	October	31,	2010.	In	IPL's	FAC	76	through	80	filings,	the	IURC	found	that	IPL's	rolling	annual jurisdictional	retail	electric	net	operating	income	was	greater	than	the	authorized	annual	jurisdictional	net	operating	income.	Because	IPL	has	a	cumulative	net	operating income	deficiency,	IPL	was	not	required	to	make	customer	refunds	in	its	FAC	proceedings.

In	December	2007,	IPL	received	a	letter	from	the	staff	of	the	IURC	requesting	information	relevant	to	the	IURC's	periodic	review	of	IPL's	basic	rates	and charges	and	IPL	subsequently	provided	information	to	the	staff.	Since	IPL's	cumulative	net	operating	income	deficiency	(described	above)	requires	no	customer	refunds in	the	FAC	process,	the	IURC	staff	was	concerned	that	the	higher-than-usual	2007	earnings	may	continue	in	the	future.	In	response	to	the	inquiry,	IPL	provided voluntary	credits	to	its	retail	customers	totaling	$32	million.	IPL	recorded	a	$30	million	deferred	fuel	regulatory	liability	in	March	2008	and	a	$2	million	deferred	fuel regulatory	liability	in	June	2008,	with	corresponding	and	respective	reductions	against	revenues	for	these	voluntary	credits.	All	of	these	credits	have	been	applied	in	the form	of	offsets	against	fuel	charges	that	customers	would	have	otherwise	been	billed	during	June	1,	2008	through	February	28,	2009.

Over	the	past	few	years,	IPL	has	received	correspondence	from	the	IURC	on	a	few	occasions	expressing	concern	for	IPL's	level	of	earnings	and	inquiring	about IPL's	depreciation	rates.	In	response,	IPL	provided	additional	information	to	the	IURC	relevant	to	IPL's	earnings	as	well	as	the	results	of	a	depreciation	analysis	that	IPL conducted.	In	the	fourth	quarter	of	2010,	IPL	received	a	letter	from	the	IURC	stating	that	they	did	not	have	any	additional	questions.

IPL	is	a	member	of	the	Midwest	Independent	System	Operator,	Inc.	("Midwest	ISO").	Midwest	ISO	serves	as	the	third-party	operator	of	IPL's	transmission system	and	runs	the	day-ahead	and	real-time	Energy	Market	and,	beginning	in	January	2009,	the	Ancillary	Services	Market	for	its	members.

IPL	transferred	functional	control	of	its	transmission	facilities	to	the	Midwest	ISO	and	its	transmission	operations	were	integrated	with	those	of	the	Midwest	ISO. IPL's	participation	and	authority	to	sell	wholesale	power	at	market-based	rates	are	subject	to	the	FERC	jurisdiction.	Transmission	service	over	IPL's	facilities	is	now provided	through	the	Midwest	ISO's	tariff.

As	a	member	of	the	Midwest	ISO,	IPL	offers	its	generation	and	bids	its	demand	into	the	markets	operated	by	the	Midwest	ISO	on	an	hourly	basis.	The	Midwest ISO	settles	energy	hourly	offers	and	bids	based	on	locational	marginal	prices,	which	is	pricing	for	energy	at	a	given	location	based	on	a	market	clearing	price	that	takes into	account	physical	limitations,	generation	and	demand	throughout	the	Midwest	ISO	region.	The	Midwest	ISO	evaluates	the	market	participants'	energy	offers	and demand	bids	optimizing	for	energy	products	to	economically	and	reliably	dispatch	the	entire	Midwest	ISO	system.	The	Company	has	certain	regulatory	assets	on	its balance	sheet	relating	to	IPL's	participation	in	the	Midwest	ISO.	The	IURC	has	authorized	IPL	to	recover	the	fuel	portion	of	its	costs	from	the	Midwest	ISO,	to	defer certain	operational,	administrative	and	other	costs	from	the	Midwest	ISO	and	seek	recovery	in	IPL's	next	basic	rate	case	proceeding.	Total	Midwest	ISO	costs	deferred by	IPL	as	long-term	regulatory	assets	were	$71.0	million	and	$62.8	million	as	of	December	31,	2010	and	December	31,	2009,	respectively.	IPL	will	seek	to	recover	the deferred	costs	in	its	next	basic	rate	case	proceeding;	however,	there	can	be	no	assurance	that	IPL	would	be	successful	in	that	regard.

Beginning	in	2007,	Midwest	ISO	transmission	owners,	including	IPL,	began	to	share	the	costs	of	transmission	expansion	projects	with	other	transmission	owners after	such	projects	were	approved	by	the	Midwest	ISO	Board	of	Directors.	Upon	approval	by	the	Midwest	ISO	Board	of	Directors,	the	transmission	owners	must	make	a good-faith	effort	to	build	the	projects.	Costs	allocated	to	IPL	for	the	projects	of	other	transmission	owners	are	collected	by	the	Midwest	ISO	per	their	tariff.	We	believe	it is	probable,	but	not	certain,	that	IPL	will	ultimately	be	able	to	recover	from	its	customers	the	money	it	pays	to	the	Midwest	ISO	for	its	share	of	transmission	expansion projects	of	other	utilities,	but	such	recovery	is	subject	to	IURC	approval	in	IPL's	next	basic	rate	case.	Therefore,	such	costs	to	date	have	been	deferred	as	long-term regulatory	assets.	To	date,	such	costs	have	not	been	material	to	IPL.	However,	given	the	magnitude	of	the	costs	anticipated	to	enable	conformance	with	renewables mandates	in	the	Midwest	ISO	footprint,	it	is	probable	that	such	costs	will	become

material	in	the	next	few	years.	Our	current	estimates	are	that	IPL's	share	of	such	costs	could	be	more	than	$50	million	annually	by	2020	and	continue	increasing	after that.

In	2004,	the	IURC	initiated	an	investigation	to	examine	the	overall	effectiveness	of	Demand-Side	Management	("DSM")	programs	throughout	the	State	of Indiana	and	to	consider	any	alternatives	to	improve	DSM	performance	statewide.	On	December	9,	2009,	the	IURC	issued	a	Generic	DSM	Order	that	found	that	electric utilities	subject	to	its	jurisdiction	must	meet	an	overall	goal	of	annual	cost-effective	DSM	programs	that	reduce	retail	kWh	sales	(as	compared	to	what	sales	would	have been	excluding	the	DSM	programs)	of	2%	per	year	by	2019	(beginning	in	2010	at	0.3%	and	growing	to	2.0%	in	2019	subject	to	certain	adjustments).	The	IURC	also found	that	all	jurisdictional	electric	utilities	have	to	participate	in	five	initial,	statewide	core	DSM	programs,	which	will	be	administered	by	a	Third-Party	Administrator. Consequently,	IPL's	DSM	spending,	both	capital	and	operating,	will	increase	significantly	going	forward,	which	will	likely	reduce	IPL's	retail	energy	sales	and	the associated	revenues.

Prior	to	the	issuance	of	the	Generic	DSM	Order,	IPL	filed	a	petition	seeking	relief	for	substantive	DSM	programs.	IPL	proposed	a	DSM	plan	to	be	considered	in two	phases.	The	first	phase	("Phase	I")	sought	recovery	for	traditional-type	DSM	programs,	such	as	residential	home	weatherization	and	energy	efficiency	education programs,	with	additional	offerings.	The	IURC	issued	an	Order	in	February	2010	that	approved	the	programs	included	in	IPL's	Phase	I	request.	In	addition	to	IPL's traditional	recovery	of	the	direct	costs	of	the	DSM	program,	the	Order	also	included	performance-based	incentives.	The	second	phase	("Phase	II")	sought	recovery	for "Advanced"	DSM	programs	and	was	coincident	with	IPL's	application	for	a	smart	grid	funding	grant	from	the	Department	of	Energy.	The	"Advanced"	DSM	programs included	an	Advanced	Metering	Infrastructure	communication	backbone	as	well	as	two-way	meters	and	home	area	network	devices	for	certain	of	IPL's	customers.	In February	2010,	the	IURC	issued	an	Order	that	approved	IPL's	Phase	II	program,	but	denied	IPL's	request	to	timely	recover	its	expenditures.	Instead,	IPL	would	need	to seek	recovery	of	the	costs	incurred	under	its	Phase	II	program	during	its	next	basic	rate	case	proceeding.

In	June	2010,	IPL	filed	a	petition	with	the	IURC	seeking	authority	for	an	additional	DSM	program	and	to	recover	the	lost	revenue	resulting	from	decreased	kWh consumption	and	kW	demand	beginning	on	June	11,	2010	as	a	result	of	the	implementation	of	all	approved	DSM	programs.	The	IURC	granted	IPL's	request	related	to the	additional	DSM	program,	but	denied	the	request	to	recover	lost	revenue.	Additionally,	in	October	2010,	IPL	filed	a	petition	with	the	IURC	for	approval	of	its	plan	to comply	with	the	IURC's	Generic	DSM	Order,	which	petition	includes	estimated	DSM	spending	of	approximately	$65	million	from	2011	to	2013.	It	is	not	possible	to predict	at	this	time	what	the	IURC's	response	will	be	to	this	petition.

The	American	Recovery	and	Reinvestment	Act	of	2009	includes	various	provisions	that	fund	the	development	of	the	electric	power	industry	at	the	federal	and state	level.	These	provisions	include,	but	are	not	limited	to,	improving	energy	efficiency	and	reliability;	electricity	delivery	(including	smart	grid	technology);	energy research	and	development;	renewable	energy;	and	demand	response	management.	IPL	submitted	a	Smart	Grid	Investment	Grant	for	$20	million	to	provide	its	customers with	tools	to	help	them	more	efficiently	use	electricity	and	also	to	upgrade	its	delivery	system	infrastructure.	IPL's	application	was	approved	and	the	agreement	with	the United	States	Department	of	Energy	was	executed	in	April	2010.

Environmental	Regulations.	See	"Environmental	and	Land	Use	Regulations"	below	for	a	description	of	the	United	States	Environmental	Regulations.

# Europe,	Middle	East	&	Asia

# European	Union

Structure	of	Electricity	Market.	All	European	Union	("EU")	member	states	are	required	to	implement	EU	legislation,	although	there	is	a	degree	of	disparity	as	to how	such	legislation	is	implemented	and	the	pace	of	implementation	in	the	respective	member	states.	EU	legislation	covers	a	range	of	topics	which	impact	the	energy sector,	including	market	liberalization	and	environmental	legislation.

The	Company	has	subsidiaries	which	operate	existing	generation	businesses	in	a	number	of	countries	which	are	member	states	of	the	EU,	including	the	Czech Republic,	Hungary,	the	Netherlands,	Spain	and	the	United	Kingdom.	The	Company	also	has	subsidiaries	which	are	in	the	process	of	commissioning	a	generation	plant	in Bulgaria.	Bulgaria	became	a	member	state	of	the	EU	as	of	January	1,	2007.

Principal	Regulations.	The	principles	of	market	liberalization	in	the	EU	electricity	and	gas	markets	were	introduced	under	the	2003	Electricity	and	Gas	Directives. In	2005,	the	European	Commission	(the	"Commission")	launched	a	sector-wide	inquiry	into	the	European	gas	and	electricity	markets.	To	tackle	the	issues	identified	in the	inquiry	and	to	further	improve	the	regulatory	framework	for	energy	liberalization,	the	Commission	launched	the	Third	Energy	Package	in	2007.	In	the	context	of	the electricity	market,	the	inquiry	has	to	date	focused	on	identifying	issues	related	to	price	formation	in	the	electricity	wholesale	markets	and	the	role	of	long-term agreements	as	a	possible	barrier	to	entry	with	a	view	to	improving	the	competitive	situation.	In	January	2007,	the	Commission	published	a	proposal	for	a	new	common energy	policy	for	Europe.	In	November	2008,	the	Commission	published	a	non-binding	second	Strategic	Energy	Review	aimed	at	developing	the	concept	of	a	common European	energy	policy.	It	focused	mainly	on	security	of	supply	and	infrastructure	development.	The	Strategic	Energy	Review	proposed	reviews	of	the	Gas	Storage Directive	in	2010	and	an	update	of	the	Oil	Stocks	Directives.

In	October	2008,	the	Energy	Ministers	reached	political	agreement	on	the	"Third	Liberalization	Package,"	which	includes	five	pieces	of	legislation,	Electricity and	Gas	Directives,	Electricity	and	Gas	Regulations	and	a	Regulation	creating	a	new	Agency	for	the	Coordination	of	Energy	Regulators,	which	will	have	limited	powers to	deal	with	cross-border	interconnectors	and	related	issues.	This	legislation	was	formally	adopted	in	August	2009	and	must	be	implemented	on	a	national	level	by March	2011.

Environmental	Regulations.	See	"Environmental	and	Land	Use	Regulations—International"	below	for	a	description	of	these	directives.

# Bulgaria

Structure	of	Electricity	Market.	The	Bulgarian	energy	sector	model	allows	for	trading	at	regulated	prices,	at	freely	negotiated	prices	between	parties	or	on	the organized	market.	Since	an	organized	market	has	not	evolved	yet	despite	the	availability	of	adequate	legislative	framework	for	it,	the	primary	means	for	wholesale trading	is	the	regulated	market,	the	bilateral	transactions	market	and	the	Electricity	Balancing	Mechanism.	These	arrangements	are	also	supplemented	by	an	imbalance settlement	regime.

The	Bulgarian	power	market	has	evolved	from	a	system	where	the	National	Electricity	Company	("NEK"),	established	in	November	1991	as	a	fully	state-owned vertically	integrated	utility,	was	responsible	for	the	entire	cycle	of	generation,	transmission	and	distribution.	After	a	decade	of	functioning	in	this	role,	NEK	was vertically	unbundled	with	a	resulting	legal	separation	of	generation,	transmission	and	distribution	assets	into	different	operating	entities.	While	these	structural	reforms greatly	helped	create	a	competitive	electricity	sector,	there	are	no	actual	trading	rules	to	enable	the	market	to	operate	freely.	To	ensure	accessible	customer	prices	and support	to	renewable	energy	supply	("RES")	producers	and	the	highly	efficient	cogeneration	assets,	NEK	is	still	acting	as	single	buyer,	purchasing	the	majority	of	power generated	in	Bulgaria	and	then	selling	the	power	to	distribution	companies	or	to	transmission	network-connected	consumers	or	to	export	across	interconnectors	(as	the sole

licensed	Bulgarian	power	exporter).	NEK	also	owns	the	biggest	hydro-electric	and	pump	storage	generation	facilities	in	Bulgaria.

While	the	transmission	system	in	Bulgaria	remains	under	NEK's	formal	ownership,	to	comply	fully	with	EU	legislation,	NEK	has	spun-off	transmission operations	(i.e.,	system	operation,	balancing	market	administration	and	systems'	operation	and	maintenance)	to	the	Electricity	System	Operator.	The	system	also	allows for	a	regulated	third-party	access.

Principal	Regulators.	The	State	Energy	and	Water	Regulatory	Commission	("SEWRC")	established	in	1999	is	the	independent	regulator	for	both	the	energy	and water	markets.	SEWRC's	key	responsibilities	are:

•Licensing	activities	in	the	electricity,	heat	and	natural	gas	sectors;

•	 Regulating	electricity,	heat	and	natural	gas	prices	(including	those	from	RES	and	CHP	power	sources);

•	 Regulating	interconnection	to	distribution	and	transmission	networks;	and

•Issuing	of	certificates	of	origin	and	green	certificates	for	the	electricity	produced	from	RES	and	co-generation.

Principal	Regulations.	Bulgaria	is	at	a	juncture	of	adopting	legislative	packages	that	cover	three	key	European	policy	goals—energy	independence	(Directive 2009/28/EC),	environmental	sustainability	through	GHG	emissions	control	(Directive	2009/29/EC)	and	market	liberalization	(Directive	2009/72/EC).	In	line	with	these EU-mandated	goals,	the	government	of	Bulgaria	has	set	the	following	key	priorities:	a	20%	reduction	of	the	energy	intensity	of	GDP	by	2013	and	a	50%	reduction	by 2020;	increased	renewables	share	of	the	total	energy	consumption	to	12%	by	2013	and	to	a	minimum	of	16%	by	2020;	and	competitive	energy	market	through promoting	new	generation	entry,	security	of	supply,	and	sustainable	development.	A	key	milestone	would	be	a	30%	increase	of	bilateral	contracts	in	the	electricity market	by	2013.

A	key	law	that	sets	the	stage	for	the	above	priorities	is	the	Bulgarian	Energy	Act	developed	in	2004	(the	"BEA")	with	a	view	to	a	transparent	and	predictable regulatory	environment	to	promote	further	liberalization	through	an	independent	regulatory	authority.	The	BEA	creates	a	framework	for	viable	commercial	companies	in the	sector	through	more	investment,	greater	autonomy	of	SERWC	and	more	effective	commercial	restructuring.	The	BEA	is	structured	so	that	the	market	can	shift	away from	the	single-buyer	model	into	a	more	market-oriented	third-party	network	access	model	that	allows	for	trading	at	regulated	or	freely	negotiated	prices,	as	well	as	at	a free	market	exchange.	To	be	in	full	compliance	with	the	EU	Third	Energy	Package,	the	BEA	is	being	amended	in	order	for	the	electricity	market	to	be	fully	liberalized under	clear	regulatory	rules	and	sustainable	market	mechanisms.	Recent	amendments	to	the	BEA	are	making	clear	the	commitment	of	the	government	to	honoring	long- term	contracts	for	power	purchasing	with	generators	whose	investments	have	helped	upgrade	the	national	asset	base.

To	help	further	develop	the	energy	market,	the	SERWC	developed	new	Trading	Rules,	adopted	in	the	summer	of	2010,	where	generators,	consumers	and	grid operators	are	organized	in	balancing	groups	for	the	most	cost-effective	balance	between	energy	supply	and	consumption.	An	underlying	principle	of	the	Trading	Rules will	be	the	presence	of	a	"Day-ahead"	market	(a	departure	from	the	existing	practice	of	weekly	notification	schedules).	Importantly,	the	Trading	Rules	will	also	establish the	principles	for	the	Bulgarian	power	exchange,	all	in	line	with	the	EU's	Third	Energy	Liberalization	legislation.

Environmental	Regulations.	The	main	environmental	regulations	reflect	the	implementation	of	EU	environmental	directives.	As	of	January	2007,	Bulgaria	is introducing	EU	Emissions	Trading	Scheme	("ETS")	as	the	main	mechanism	for	meeting	Kyoto	Protocol	GHG	reduction	commitments.	The	Bulgarian	Environmental Protection	Act	amended	on	September	27,	2005,	and	all	secondary	legislation	following	from	it,	have	incorporated	all	EU	and	Kyoto	emission	reduction	commitments. The	Bulgarian	National	Allocation	Plan	("NAP")	allows	a	total	of	42.3	million	tonnes	of	CO 	for	the	whole	volume	of	fossil	fuel-based	generation	in	the	country.	The AES	Galabovo	coal-based	power	plant	will	be	covered	by	the	NAP	at	80%	of	its	projected

generation	for	2011	and	2012.	The	portion	of	CO 	allowances	which	are	not	covered	by	NAP	will	be	billed	directly	to	NEK.

Bulgaria	is	also	subject	to	the	Large	Combustion	Plant	Directive	(2001/80/EC)	("LCPD"),	which	aims	to	reduce	particulate	emissions	by	controlling	SO,	NO^X and	dust	from	large	combustion	plants.	The	LCPD	allows	for	existing	plants	to	opt	for	exemption	from	the	emission	level	values,	as	long	as	the	operator	undertakes	not to	operate	for	more	than	20,000	hours	starting	from	January	1,	2008	and	ending	no	later	than	December	31,	2015.	Major	rehabilitation	work	has	been	taking	place across	units	of	various	Bulgarian	thermal	power	plants	in	the	last	decade.	The	rehabilitated	Maritza	East	2	complex	is	now	fitted	with	electrical	filters	for	capturing	dust and	Flue	Gas	Desulphurisation	("FGD")	units	(more	than	94%	efficiency).	The	AES	Galabovo	power	plant,	which	is	currently	in	the	process	of	commissioning,	is equipped	with	a	state-of-the-art	wet	FGD	system	that	ensures	98%	of	SO 	removal.

Bulgaria	is	dependent	on	foreign	imports	for	70%	of	its	primary	fuel	sources,	which	makes	exploration	of	renewable	energy	sources	paramount	for	the	country's achievement	of	energy	independence	and	environmental	objectives.	Bulgaria's	EU-mandated	renewable	targets	have	been	met	mostly	by	hydro	power	plants	with limited	contribution	to	the	fuel	mix	by	wind	energy	and	even	less	from	biomass.	The	main	goal	of	the	Renewable	and	Alternative	Energy	Sources	and	Biofuels	Act	of 2007	is	to	encourage	generation	from	and	grid	interconnection	of	installations	utilizing	renewable	energy	sources.

Material	Regulatory	Actions.	In	connection	with	Bulgaria's	accession	into	the	EU,	the	European	Commission	(the	"Commission")	has	opened	an	investigation into	alleged	anti-competitive	behavior	and	possible	restrictions	of	competition	in	the	Bulgarian	electricity	markets.	The	current	focus	of	the	Commission's	investigation is	NEK.	As	part	of	its	investigation,	the	Commission	is	attempting	to	determine	whether	NEK's	long-term	contracts	are	anti-competitive,	including	its	long-term	PPAs with	AES'	Bulgarian	entities,	AES	Maritza	East	and	AES	Geo	Energy.	Accordingly,	the	Commission	has	issued	separate	information	requests	to	AES	Maritza	and	AES Geo	Energy	about	their	respective	PPAs	with	NEK.	While	these	particular	requests	were	voluntary,	both	AES	Maritza	and	AES	Geo	Energy	have	cooperated	in	good faith	with	the	Commission,	have	provided	the	requested	information	and	have	met	with	the	Commission	in	order	to	provide	background	and	any	further	required information	about	the	projects.	The	Commission	has	clearly	specified	that	neither	AES	Maritza	nor	AES	Geo	Energy	were	the	target	of	the	investigation.	We	believe	the Commission	is	partly	concerned	that	long-term	PPAs	could	pose	a	problem	with	respect	to	the	liberalization	of	Bulgaria's	electricity	markets	but	we	believe	that	the projects	and	their	respective	PPAs	did	not	tie	up	capacity	but	created	capacity	that	would	not	otherwise	exist.	However,	if	the	Commission	determined	that	PPAs	are anti-competitive,	they	could	take	actions	up	to	and	including	termination	of	our	PPA,	which	could	have	a	material	adverse	impact	on	AES	Maritza	and	our	results	of operations	and	financial	condition.

Potential	or	Proposed	Regulations.	The	AESB	Act	referred	to	above	is	currently	being	amended	in	order	to	better	incorporate	the	EU	principles	set	forth	in Directive	2009/29/EC.	Recent	draft	amendments	to	the	AESB	Act	ensure	predictability	for	off-take	tariffs	for	wind	project	investments	that	have	been	undertaken	in	the last	several	years	(including	the	AES-owned	Saint	Nikola	Wind	Farm)	as	well	as	create	new	development	opportunities	for	solar	power,	including	the	new	solar	power projects	in	the	Bulgaria	pipeline	of	AES	Solar.

# Czech	Republic

Structure	of	Electricity	Market.	In	accordance	with	EU	directives	regarding	market	liberalization,	all	electricity	customers	in	the	Czech	Republic	are	able	to	select their	energy	supplier.	Since	August	2007,	the	Prague	Energy	Exchange	has	been	trading	energy	in	the	form	of	base	load	and	peak	load	on	a	monthly,	quarterly	and annual	basis.	The	majority	of	electricity	is,	however,	still	traded	on	a	bilateral	contract	basis	between	generators	and	distributors,	independent	traders	and	also	between generators	and	final	customers.	In	February	2008,	a	day-ahead	spot	market	was	incorporated	into	the	Prague	Energy	Exchange.	Another	important	entity	active	in	the energy	sector	is	OTE,	which	is	responsible	for:	processing	and	reporting	business	balance	of	electricity	according	to	data	supplied	by	electricity	market	participants; organization	of	short-term	markets	and

the	balancing	market	by	regulating	energy	in	cooperation	with	transmission	system	operator;	and	evaluation	and	settlement	of	imbalances	between	the	agreed	and	actual electricity	supplies	and	consumption.

Principal	Regulators.	The	Energy	Regulatory	Office	regulates	the	energy	sector	by	granting	permits	for	businesses	in	the	energy	sector.	The	main	tasks	of	the Energy	Regulatory	Office	are:	supporting	competition,	supporting	the	use	of	renewable	and	secondary	energy	resources,	and	protection	of	consumer	interests	in monopolistic	markets.

Principal	Regulations.	The	principal	regulations	are	those	which	implement	EU	regulations.	The	energy	activities	are	regulated	mainly	by	Act	No.	458,	as amended,	which	provides	the	conditions	for	business	activity,	the	exercise	of	public	administration	and	nondiscriminatory	regulation	in	the	energy	sectors,	including	the electricity,	gas	and	heat	sectors,	as	well	as	the	rights	and	obligations	of	individuals	and	legal	entities	related	thereto,	in	compliance	with	the	law	of	the	European Communities.	The	other	principal	law	is	Act	No.	180/2005	Coll.,	as	amended,	on	the	promotion	of	electricity	production	from	renewable	energy	sources	which regulates,	in	accordance	with	the	legislation	of	the	European	Communities,	the	method	of	promoting	the	production	of	electricity	from	renewable	energy	sources	and from	mining	gas	from	closed	mines,	the	performance	of	state	administration	and	the	rights	and	obligations	of	natural	and	legal	persons	connected	therewith.	The methodology	of	price	control	in	each	line	of	business	is	governed	by	Regulation	No.	438/2001	(as	amended)	which	regulates	the	procedures	for	price	control	in	the energy	sector.	The	revenue	cap	regulatory	method	has	been	selected	for	electricity	transmission	and	distribution	activities.	Actual	regulated	fees	associated	with transmission	and	distribution	as	fees	for	capacity	payments,	network	usage,	renewable	subsidies	in	the	form	of	feed-in	tariffs	or	green	bonuses	and	system	services charges,	are	actualized	annually	in	the	relevant	price	decision	issued	by	the	Energy	Regulatory	Office.	The	gradual	liberalization	of	the	electricity	market	made	all customers	eligible	customers	and	trading	is	not	subject	to	regulation.	Energy	activities	are	also	governed	by	the	corresponding	technical	regulations	and	standards.

Environmental	Regulations.	The	principal	environmental	regulations	are	the	Pollution	Prevention	and	Control	Regulations	76/2002	Coll.	These	regulations introduce	a	pollution	control	system	known	as	Pollution	Prevention	and	Control	("PPC").	AES	Bohemia	is	subject	to	air	pollution	control	and	is	regulated	by	the Regional	Environmental	Authority.	The	key	concept	of	the	regulations	concerns	the	application	of	Best	Available	Techniques	("BAT")	in	order	to	prevent	pollution.	The PPC	regime	requires	installations	operating	certain	activities	to	apply	for	a	permit	to	operate.	The	PPC	permit	contains	conditions	on:	waste	management;	material storage	and	handling;	releases	to	air,	water	and	land;	environmental	management	techniques;	accident	prevention	and	control;	monitoring,	reporting	and	record-keeping; and	site	decommissioning.

Material	Regulatory	Actions.	During	2010,	as	a	result	of	a	feed-in	tariff	for	solar	plants,	the	Czech	Republic	experienced	a	boom	in	solar	installation	tripling installed	capacity	from	January	1,	2010.	This	forced	the	government	to	introduce	new	measures	for	solar	plants	to	limit	the	future	support	to	only	smaller	installations, reduce	feed-in	tariffs	and	implement	a	new	tax	regime.	However,	solar	installation	has	already	significantly	affected	the	grid	by	making	any	development	of	new projects	more	difficult	due	to	limited	free	capacity	in	the	grid.	In	addition,	the	government	decided	to	introduce	a	gift	tax	on	free	allocated	CO 	credits	to	electricity generators	to	generate	additional	resources	for	financing	renewable	electricity	in	the	future	and	to	protect	electricity	customers,	at	least	partly,	from	a	major	increase	in the	regulated	fee	for	the	support	of	renewable	electricity.	Although	the	law	stipulates	that	the	CO 	gift	tax	should	not	be	paid	from	cogeneration	electricity,	it	is	assumed now	that	the	AES	Bohemia	tax	duty	may	exceed	$1.5	million	payable	in	the	first	quarter	of	2011.	The	final	regulation,	which	will	provide	calculations	of	the	gift	tax	for cogeneration	producers	has	not	been	issued	yet.

# Hungary

Structure	of	Electricity	Market.	The	Hungarian	market	has	one	main	interconnected	system.	The	state-owned	electricity	wholesaler,	MVM,	is	the	dominant exporter,	importer	and	wholesaler	of	electricity.	MVM's	affiliated	company,	MAVIR,	is	the	Hungarian	transmission	system	operator.	Currently,	Hungary	is	dependent on

energy	imports	(mainly	from	Russia)	since	domestic	production	only	partially	covers	consumption.	The	wholesale	market	is	legally	liberalized,	although	it	remains dominated	by	MVM	due	to	MVM's	access	to	and	control	over	a	significant	portion	of	the	Hungarian	generating	facilities.	The	spot	market	is	relatively	illiquid	with trading	dominated	by	over-the-counter	or	bilateral	contracts.	Relative	to	more	western	parts	of	Europe,	the	volumes	traded	are	smaller	and	typically	for	shorter	durations, although	contracts	with	a	duration	that	is	greater	than	one	year	are	available.

Principal	regulators.	Magyar	Energia	Hivatal	("MEH")	is	the	government	entity	responsible	for	regulation	of	the	electricity	industry	in	Hungary.	The	Ministry	of National	Development	oversees	the	activities	of	the	MEH.

Principal	Regulations.	The	main	regulations	in	Hungary	are	those	being	implemented	under	EU	directives,	the	adoption	of	the	Hungarian	Electricity	Act	in	2007, which	became	effective	January	1,	2008,	was	the	final	legislative	step	to	implement	a	fully	liberalized	electricity	market.	By	virtue	of	the	Hungarian	Electricity	Act,	all customers	are	eligible	to	choose	their	electricity	supplier.	In	the	competitive	market,	generators	sell	capacity	to	wholesale	traders,	distribution	companies,	other generators,	electricity	traders	and	eligible	customers	at	an	unregulated	price.	In	the	light	of	the	third	energy	liberalization	package	issued	by	the	EU	in	2009,	Hungary	is planning	to	implement	a	major	amendment	of	the	Electricity	Act	and	the	Gas	Act	which	will	conform	to	the	EU	package.

Environmental	Regulations.	The	main	environmental	permit	is	the	Integrated	Pollution	Prevention	Control	("IPPC").	The	IPPC	Directive	is	based	on	several principles,	namely	(i)	an	integrated	approach,	(ii)	BAT,	(iii)	flexibility	and	(iv)	public	participation.	The	integrated	approach	means	that	the	permits	must	take	into account	the	whole	environmental	performance	of	the	plant,	covering,	e.g.,	emissions	to	air,	water	and	land,	generation	of	waste,	use	of	raw	materials,	energy	efficiency, noise,	prevention	of	accidents	and	restoration	of	the	site	upon	closure.	The	purpose	of	the	Directive	is	to	ensure	a	high	level	of	protection	of	the	environment	taken	as	a whole.	The	permit	conditions	including	emission	limit	values	must	be	based	on	Best	Available	Techniques	("BAT")	as	defined	in	the	IPPC	Directive.	To	assist	the licensing	authorities	and	companies	to	determine	BAT,	the	Commission	organizes	an	exchange	of	information	between	experts	from	the	EU	Member	States,	industry and	environmental	organizations.	This	work	is	coordinated	by	the	European	IPPC	Bureau	of	the	Institute	for	Prospective	Technology	Studies	at	the	EU	Joint	Research Centre	in	Seville,	Spain.	This	results	in	the	adoption	and	publication	by	the	Commission	of	the	BAT	Reference	Documents	(the	"BREFs").	The	IPPC	Directive	contains elements	of	flexibility	by	allowing	the	licensing	authorities,	in	determining	permit	conditions,	to	take	into	account	the	technical	characteristics	of	the	installation,	its geographical	location	and	the	local	environmental	conditions.	Finally,	the	Directive	ensures	that	the	public	has	a	right	to	participate	in	the	decision-making	process,	and to	be	informed	of	its	consequences,	by	giving	the	public	access	to	permit	applications	in	order	to	provide	their	opinions,	permits,	results	of	the	monitoring	of	releases	and the	European	Pollutant	Release	and	Transfer	Register	("E-PRTR").	E-PRTR	provides	emission	data	reported	by	Member	States	accessible	in	a	public	register,	which	is intended	to	provide	environmental	information	on	major	industrial	activities.	E-PRTR	has	replaced	the	previous	EU-wide	pollutant	inventory,	the	so-called	European Pollutant	Emission	Register.

Material	Regulatory	Actions.	Shortly	before	its	accession	to	the	EU,	the	Hungarian	government	notified	the	Commission	of	arrangements	concerning compensation	to	the	state-owned	electricity	wholesaler	MVM.	The	Commission	decided	to	open	a	formal	investigation	in	2005	to	determine	whether	any	government subsidies	were	provided	by	MVM	to	its	suppliers	which	were	incompatible	with	the	common	market.	In	June	2008,	the	Commission	reached	its	decision	that	these PPAs,	including	AES	Tisza's	PPA,	contain	elements	of	illegal	state	aid.	The	decision	required	MVM	to	terminate	the	PPAs	within	six	months	of	the	June	2008	decision, and	to	recover	the	alleged	illegal	state	aid	from	the	generators	by	April	2009.	AES	Tisza	is	challenging	the	Commission's	decision	in	the	Court	of	First	Instance	of	the European	Communities.	Referring	to	the	Commission's	decision,	Hungary	adopted	act	number	LXX	of	2008	which	terminates	all	long-term	PPAs	in	Hungary,	including AES	Tisza's	PPA,	as	of	December	31,	2008,	and	requires	generators	to	repay	the	alleged	illegal	state	aid	that	was	allegedly	received	by	the	generators	through	the	PPAs, and	provides	for	the	possibility	to	offset	the	generators	stranded	costs	from	the	repayable	state	aid.	The	MEH	issued	its	Resolution	No.	342/2010	pursuant	to	which	it stated	AES	Tisza	did	not	receive	illegal	state	aid.

At	the	end	of	2006	and	for	all	of	2007,	the	Hungarian	government	reintroduced	administrative	pricing	for	all	electricity	generators,	overriding	PPA	pricing, including	the	pricing	in	AES	Tisza's	PPA.	In	January	2007,	AES	Summit	Generation	Limited	("AES	Summit"),	a	holding	company	associated	with	AES	Tisza's operations	in	Hungary,	and	AES	Tisza	notified	the	Hungarian	government	of	a	dispute	concerning	its	acts	and	omissions	related	to	AES'	substantial	investments	in Hungary	in	connection	with	the	reintroduction	of	the	administrative	pricing	for	Hungarian	electricity	generators.	In	conjunction	with	this,	AES	Summit	and	AES	Tisza have	commenced	International	Centre	for	Settlement	of	Investment	Disputes	("ICSID")	arbitration	proceedings	against	Hungary	under	the	Energy	Charter	Treaty	in connection	with	Hungary's	reintroduction	of	the	administrative	pricing	for	Hungarian	electricity	generators.	In	the	meantime,	pursuant	to	the	new	Electricity	Act	in	force from	January	1,	2008,	administrative	pricing	for	electricity	generators	was	subsequently	abolished.	The	ICSID	arbitration	panel	issued	the	final	determination	on September	23,	2010	pursuant	to	which	AES'	claim	was	dismissed.	AES	is	in	the	process	of	analyzing	the	determination	and	the	potential	legal	remedies.

In	2008,	Hungary	introduced	a	special	tax	to	be	levied	on	energy	companies	including	companies	such	as	AES	Tisza.	The	rate	of	the	special	tax	was	8%	and,	in 2010,	was	extended	until	2013.	Hungary	also	introduced	a	further	tax	on	certain	industries,	including	energy	companies	(the	"Crisis	Tax").	The	rate	of	the	Crisis	Tax	for energy	companies	is	1.05%	of	the	net	sales	revenues.

# Spain

Structure	of	Electricity	Market.	Spain	is	a	member	of	the	EU	and,	as	such,	the	Spanish	Government	has	been	taking	steps	to	liberalize	the	country's	electricity sector	in	accordance	with	EU	directives.	Since	January	1,	2003,	all	customers	have	been	eligible	to	choose	their	electricity	supplier.

AES	currently	operates	and	holds	a	71%	ownership	interest	in	a	1,199	MW	natural	gas-fired	plant	located	in	Cartagena	on	the	southeast	coast	of	Spain.	The	plant sells	energy	into	the	Pan-Iberian	electricity	market	("MIBEL").	The	MIBEL	market	was	created	in	January	2004	when	Spain	and	Portugal	signed	a	formal	agreement. This	new	market	allows	generators	in	the	two	countries	to	sell	their	electricity	on	both	sides	of	the	Spanish-Portuguese	border	as	one	single	market.	OMEL,	Spain's energy	market	operator	and	Portugal's	equivalent,	OMIP,	exchanged	stakes	in	April	2006,	and	were	reorganized	such	that	an	electricity	forwards	market	was	created	in Lisbon	and	a	spot	market	was	created	in	Madrid.

The	main	transmission	company,	Red	Eléctrica	de	España	("REE"),	owns	99%	of	the	400	kV	grid	and	98%	of	the	220	kV	network.	The	law	has	been	changed	to ensure	that	REE	will	become	the	sole	transmission	company	in	Spain.	REE	is	also	the	system	operator	and	is	responsible	for	technical	management	of	the	system	and	for monitoring	transmission.	Under	the	country's	energy	infrastructure	plan,	REE	plans	to	invest	in	strengthening	the	mainland	grid,	connecting	new	plants	and	improving interconnection	throughout	the	country.	In	due	course,	AES	Cartagena	entered	into	an	agreement	with	REE	for	the	construction	of	the	interconnection	facilities.	The	use of	such	facilities	is	the	subject	of	another	standard	regulated	contract	stating	the	specific	terms	and	conditions	of	access.

Principal	Regulations.	On	December	23,	2010,	the	Spanish	Government	implemented	the	RDL	14/2010	which,	among	other	things,	limits	the	numbers	of	hours and	amount	of	feed-in-tariff	available	for	photovoltaic	power	plants.

•The	law	that	was	passed	on	December	23,	2010	forms	part	of	the	government's	policy	aimed	at	rationalizing	and	delimiting	the	legally	regulated	costs	in the	electricity	network,	while	searching	for	new	sources	of	income	and	protecting	the	most	vulnerable	consumers.	It	is	the	latest	law	of	those	passed	in	the legislative	year	of	2010.

•	 Companies	will	finance	the	"Bono	Social"	(income-based	subsidy)	until	2013	and	they	will	assume	the	costs	involved	in	the	energy	savings	and	efficiency policies	for	the	period	of	2011-2013.

•	 All	the	companies	generating	electrical	power,	both	those	that	operate	under	the	ordinary	regime	as	well	as	those	related	to	renewable	energy	and cogeneration,	will	be	paying	an	access	tariff	that	amounts	to	€0.50/MWh.

•The	hours	that	are	entitled	to	premiums	in	the	power	plants	using	photovoltaic	technology	will	be	limited	for	a	period	of	three	years	and	in	addition,	a further	cap	on	hours	is	introduced	for	the	duration	of	the	FIT	scheme	as	is	the	case	in	the	other	sectors	using	wind-powered	and	thermo-solar	technology.

•The	maximum	limits	for	the	tariff	deficit	in	2010,	2011	and	2012	have	been	amended	to	better	adapt	to	the	deviations	that	arose,	and	the	year	2013	has	been kept	as	the	point	in	time	when	self-sufficiency	will	be	reached	with	regard	to	tariffs.

This	Decree	could	have	a	material	impact	on	AES	Cartagena	and	AES	Solar's	business	in	Spain.

In	September	2002,	the	Spanish	Cabinet	approved	a	ten-year	energy	plan	which	focuses	on	meeting	the	country's	future	energy	requirements.	The	plan	also reflects	reliance	on	renewable	energy	sources	and	cogeneration.	The	Spanish	electricity	system	has	seen	a	steady	increase	in	the	new	generation	capacity	from	renewable energy	sources	for	many	years,	particularly	as	a	result	of	attractive	feed-in	tariffs	(approved	by	Royal	Decree	661/207).	Solar	photovoltaic	installed	capacity	in	the	region is	estimated	at	3.8	GW.	The	increase	in	renewable	energy	generation	capacity	supported	by	generous	feed-in	tariffs	has	led	to	major	changes	in	the	regulations	with	the aim	of	reducing	the	total	cost	of	the	feed-in	tariffs	for	the	Spanish	electricity	system.	Partly	as	a	result	of	that	and	also	as	a	result	of	the	tariff	deficit	already	accumulated, Royal	Decree-Law	6/2009	has	introduced	new	measures	that	affect	AES	Cartagena.	Primarily,	the	creation	of	a	new	obligation	on	AES	Cartagena	(and	certain	other generation	companies)	requires	them	to	pay	for	a	portion	of	the	cost	of	providing	a	social	subsidy	to	groups	of	economically	vulnerable	electricity	consumers.	The liability	for	this	cost,	under	the	AES	Cartagena	Energy	Agreement,	is	currently	the	subject	of	a	dispute	with	the	Energy	Manager,	which	has	been	referred	to	arbitration.

In	February	2006,	Spain	introduced	a	law	(Article	2	of	Royal	Decree	Law	3/2006),	which	became	effective	March	2,	2006,	that	an	amount	equivalent	to	the	value of	the	CO 	emission	allowances	allocated	free	of	charge	to	electricity	generators	will	be	netted	from	electricity	sales	proceeds	obtained	by	Ordinary	Regime	electricity generation	such	as	the	AES	Cartagena	plant.	The	parties	obliged	to	pay	these	sums	are	the	owners	of	generation	facilities.	For	the	years	2008,	2009,	and	2010	the number	of	"CO 	credits"	required	to	be	surrendered	by	AES	Cartagena	under	the	ETS	has	been	greater	than	the	number	of	free	credits	allocated	to	it.	Liability,	under	the AES	Cartagena	Energy	Agreement,	for	the	cost	of	the	shortfall	in	CO 	emissions	credits	is	currently	in	dispute,	and	is	also	the	subject	of	the	above-mentioned	arbitration proceedings.	For	a	further	discussion	see	Item	3.—Legal	Proceedings.

The	Spanish	Government	implemented	Orders	(Order	ITC/3315/2007,	introduced	on	December	15,	2007,	and	Orders	ITC/1721/2009	and	ITC/1722/2009, introduced	on	June	26,	2009)	which	developed	the	principles	set	out	in	Article	2	and	set	the	rules	applicable	for	2006,	2007	and	January	1,	2008	–	June	30,	2009, respectively.	The	effect	of	these	legislative	provisions	is	that	all	owners	of	Ordinary	Regime	generation	facilities	in	Spain	are	required	to	pay	sums	equivalent	to	the value	of	the	CO 	emissions	allowances	allocated	free	of	charge	for	2006,	2007,	2008	and	the	first	six	months	of	2009.	Liability,	under	the	AES	Cartagena	Energy Agreement,	for	these	costs	is	currently	in	dispute	and	is	the	subject	of	the	above-mentioned	arbitration	proceedings.	For	a	further	discussion	see	Item	3.	—Legal Proceedings.	As	for	the	periods	after	2012,	Directive	2003/87/EC	establishes	that	power	generation	facilities	will	not	be	issued	with	allowances	free	of	charge.

On	December	23,	2002,	Cadastral	Law	48/2002	was	enacted,	which	created	a	new	category	of	property	identified	as	Special	Real	Estate.	This,	together	with further	legislative	changes	(i.e.,	Law	51/2002	and	Law	16/2007),	led	to	the	Municipality	of	Cartagena	increasing	the	relevant	tax	rate	and	the	issuance	by	the	Cadastral authorities	of	a	new	property	value	assessment	on	November	21,	2007,	which	resulted	in	an	increase	in	the

amount	of	Spanish	property	tax	that	is	payable	by	AES	Cartagena	in	respect	of	the	plant.	Liability	under	the	Energy	Agreement	for	this	increase	in	tax	is	currently	in dispute	and	is	the	subject	of	the	above-mentioned	arbitration	proceedings.

# Turkey

Structure	of	Electricity	Market.	The	wholesale	generation	and	distribution	market	in	Turkey	is	primarily	a	bilateral	market	dominated	by	state-owned	entities.	The state-owned	Electricity	Generation	Company	("EUAS")	and	its	subsidiaries	comprise	approximately	24	GW	of	generation	capacity	and	represent	approximately	48%	of the	market.	Private	producers	(with	public	offtake)	account	for	another	35%,	and	auto	producers	and	merchant	power	plants	the	remaining	17%.

Principal	Regulators.	The	transmission	network	is	owned	and	controlled	by	TEIAS,	the	State	Transmission	Company.	TETAS,	the	Wholesale	Trading	Company, sets	wholesale	prices	based	on	average	procurement	costs	from	EUAS,	auto-producers	and	Build	Operate/Build	Own	Transfer/Transfer	of	Operating	Rights	producers. This	wholesale	price	represents	the	buying	price	for	21	distribution	companies.	Under	TEDAS,	there	were	20	regional	distribution	companies.	In	2006,	four	of	them	were privatized	and	transferred	to	the	new	owners	in	2008.	Another	five	of	them	have	been	privatized	in	2009	and	transferred	to	the	new	owners	in	2010.	In	2010,	the remaining	ones	were	privatized	and	are	awaiting	approval	for	handover.	In	2010,	the	Turkish	Privatization	Administration	finished	privatizing	all	regional	distribution companies.	There	is	also	an	hourly	balancing	spot	market,	with	prices	typically	differing	from	hour	to	hour,	which	is	growing	and	has	a	capacity	of	50	Gigawatt	hours ("GWh")	of	daily	trade.	The	automatic	price	mechanism,	which	is	meant	to	halt	the	government	subsidization,	has	been	approved	and	implementation	commenced	in July	2008.	With	this	mechanism,	all	major	cost	items	(foreign	exchange,	gas	price	increases,	inflation,	among	others)	are	expected	to	be	reflected	in	the	tariff.	As	a result,	mid-term	market	wholesale	prices	are	expected	to	converge	to	the	current	spot	market	prices.	Distribution	companies	can	procure	80-90%	of	their	needs	from TETAS	and	EUAS,	but	can	also	source	up	to	10-20%	from	other	sources.	Additionally,	eligible	customers,	using	greater	than	100	MWh	annually,	can	contract	with	the private	wholesale	companies	and	private	power	plants.	Retail	electricity	prices	are	calculated	and	proposed	by	the	distribution	companies	and	then	approved	by	the electricity	market	regulatory	authority,	EMRA.

Environmental	Regulations.	Turkey	has	introduced	a	"renewable"	feed-in	tariff	that	sets	a	floor	for	renewable	generation	(geothermal,	wind	and	small-scale hydro)	for	the	first	ten	years	of	operation.	The	floor	is	between	€0.050	and	€0.055	per	kWh	and	decreed	by	EMRA	each	year.	AES'	Turkey	hydro	assets	fall	under	the renewable	feed-in	tariffs.

The	Turkish	Government	has	also	announced	plans	to	privatize	all	the	state-owned	generation	assets,	other	than	certain	large	hydro-electric	plants,	in	2011.

# Ukraine

Structure	of	Electricity	Market.	The	electricity	sector	in	Ukraine	is	regulated	by	the	National	Energy	Regulatory	Commission	("NERC").	Electricity	costs	to	end- users	in	Ukraine	consist	of	three	main	components:	(1)	the	wholesale	market	tariff	is	the	price	at	which	the	distributor	purchases	energy	on	the	wholesale	market,	(2)	the distribution	tariff	covers	the	cost	of	transporting	electricity	over	the	distribution	network,	and	(3)	the	supply	tariff	covers	the	cost	of	supplying	electricity	to	an	end-user. The	total	cost	permitted	by	the	regulator	under	the	distribution	and	supply	tariff	each	year	is	referred	to	as	the	DVA.	The	distribution	and	supply	tariffs	for	all	distribution companies	in	Ukraine	are	established	by	the	NERC	on	an	annual	basis,	at	which	time	DVA	and	electricity	distribution	volumes	in	the	tariff	are	adjusted.	A	change	in	the DVA	methodology	was	effected	at	the	end	of	2007	with	respect	to	the	treatment	of	wages	and	salaries	such	that	the	adjustment	for	inflation	was	replaced	by	an allowance	based	on	the	average	industrial	wage	in	the	country	and	normative	quantity	of	personnel.

Principal	Regulations.	In	2006,	NERC	authorized	two	25%	increases	in	end-user	tariffs	for	residential	customers.	Since	2006,	there	have	been	no	further	changes in	residential	end-user	tariffs.	In	2010,	the	level	of	end-user	residential	tariff	covered	approximately	30%	of	real	energy	costs.	A	moratorium	on	end-user	tariff	increases was	introduced	by	Presidential	decree	for	non-residential	customers,	effective	from	December	1,	2008,	which	resulted	in	the	freezing	of	retail	tariffs	for	the	greater	part of	2009.	In	2010,	the	retail	tariffs	have	slightly	increased	but	legally	the	moratorium	is	still	in	force.	The	wholesale	electricity	market	price	increased	by	49%	in	2008,	by 8.5%	in	2009,	and	by	18%	in	2010.	In	the	course	of	2010,	a	simultaneous	increase	in	wholesale	market	price	and	pressure	on	the	end-user	tariff	growth	resulted	in	an increase	of	the	debt	to	distribution	companies	by	NERC	on	compensation	of	losses	for	supplying	energy	to	residential	customers	at	privileged	tariffs.

A	comprehensive	review	of	the	distribution	tariff	methodology	addressing	issues	of	revaluation	of	the	rate	base,	operational	expenses	coverage	on	tariffs,	the	rate of	return	and	introduction	of	regulatory	incentives	to	increase	the	quality	of	service	was	initially	expected	to	take	place	at	the	end	of	2008.	However,	since	late	2008	and then	on	an	annual	basis,	NERC	has	been	introducing	minimal	changes	into	the	tariff	methodology	to	be	valid	for	just	one	year,	including	for	2010,	setting	the	rate	of return	on	initial	investment	at	the	level	of	15%	after	tax,	wages	and	salaries	treatment	remaining	as	per	the	mechanism	introduced	in	2007,	and	material	operational expenses	subject	to	indexation	by	inflation.	A	similar	extension	of	provisions	for	2011	has	been	effected	in	late	2010.	Development	and	approval	of	a	comprehensive methodology	is	expected	to	take	place	during	2011	to	be	introduced	in	2012.

In	2010,	the	President	of	Ukraine	announced	the	list	of	reforms	for	implementation	up	through	2014	in	all	sectors	of	the	economy,	including	the	electric	industry. According	to	such	reforms,	there	are	plans	to	(i)	develop	new	tariff	methodology	in	2011;	(ii)	increase	tariffs	for	residential	customers;	(iii)	commence	elimination	of cross	subsidies;	(iv)	make	changes	to	legislation	to	improve	customers'	payment	discipline;	(v)	privatize	state-owned	distribution	companies	and	generation	companies; and	(vi)	introduce	a	new	market	structure	based	on	bilateral	agreements	and	balancing	market,	etc.

In	2009,	the	Supreme	Court	of	Ukraine	took	a	preliminary	position	affecting	distribution	companies	in	the	Ukraine,	including	AES	Kievoblenergo	and	AES Rivneoblenergo,	whereunder	it	required	that	certain	network	commercial	losses	of	power	that	were	previously	treated	as	tax	deductible	could	no	longer	be	treated	as such.	This	position,	if	maintained,	may	have	a	material	effect	on	AES	Kievoblenergo	and	AES	Rivneoblenergo.	The	Company	expects	that	the	Supreme	Court	of Ukraine	may	clarify	its	position	in	2011,	and	the	proceedings	in	respect	to	AES	Kievoblenergo	and	AES	Rivneoblenergo	are	not	likely	to	be	finally	resolved	for	another several	years.

# United	Kingdom

Structure	of	Electricity	Market.	On	March	21,	2007,	the	Electricity	(Single	Wholesale	Market)	(Northern	Ireland)	Order	2007	was	enacted,	which	provided	for	the introduction	and	regulation	of	a	single	wholesale	electricity	market	(the	"SEM")	for	Northern	Ireland	and	the	Republic	of	Ireland	that	began	operation	in	November	of 2007.	Revenue	from	the	SEM	includes	a	regulated	capacity	and	an	energy	payment	based	on	the	system	marginal	price.	Bidding	principles	insist	bids	are	cost-reflective and	are	based	on	short	run	marginal	cost.	Total	annual	capacity	payments	are	calculated	as	the	product	of	the	annualized	fixed	cost	of	a	best	new	entrant	peaking	plant multiplied	by	the	capacity	required	to	meet	the	security	standard.	This	accumulated	capacity	is	then	distributed	on	the	basis	of	plant	availability	throughout	the	year	on	a per	trading	period	basis.

Certain	generating	units	(Kilroot	GTs	1	and	2	and	Ballylumford	units	4,	CCGT	units	10	&	20	and	GTs	1	and	2)	are	contracted	under	long-term	PPAs	to	NIE Energy	Limited	terminating	on	various	dates.	The	CCGT	units	are	subject	to	extension	by	NIEE	between	March	2012	and	2024.	All	of	the	PPAs	can	be	cancelled	under direction	from	NIAUR	from	November	1,	2010	with	six	months'	notice	other	than	the	Ballylumford	10	and	20	units	which	can	be	cancelled	from	April	1,	2012.	All other	units	(Kilroot	units	K1	and	K2	whose	PPAs	terminated	in	November	2010,	GTs	3	and	4	and	Ballylumford	units	5	and	6)	participate	as	merchant	units	in	the	SEM as	described	above.

The	effect	of	this	on	the	Northern	Ireland	units	operated	as	merchant	plants	in	the	SEM	depends	largely	on	the	relative	costs	of	coal	and	gas.	The	relevant	units receive	capacity	payments	under	the	SEM.

For	the	units	with	PPAs	in	place,	Kilroot	and	Ballylumford	are	neutral	with	respect	to	the	cost	of	fuel	as	this	is	passed	through	to	its	PPA	counterparty	as	an element	of	the	payments	made	to	the	respective	units	based	on	their	availability.

Principal	Regulators.	Kilroot	and	Ballylumford	are	located	in	Northern	Ireland,	which	is	part	of	the	United	Kingdom,	and	are	subject	to	regulation	by	the Northern	Ireland	Authority	for	Utility	Regulation	("NIAUR").

Principal	Regulations.	The	principal	legislation	is	The	Electricity	(Northern	Ireland)	Order	1992	under	which	the	Generation	Licenses	of	Kilroot	and Ballylumford	are	granted.

Environmental	Regulations.	The	Kilroot	and	Ballylumford	plants	operate	under	permits	granted	under	the	Pollution	Prevention	Control	Regulations	(NI)	2003.

The	Industrial	Emissions	Directive	was	approved	by	the	European	Parliament	on	July	7,	2010	and	is	expected	to	become	law	by	2014.	The	Directive	sets	stricter limits	on	the	emissions	of	pollutants	such	as	NO ,	SO 	and	particulate	and	requires	further	reductions	in	such	emissions	by	January	2016.	The	combined	package	of	the Industrial	Emission	Directive,	National	Emissions	Ceiling	Directive	and	Best	Available	Technique	requirements	forms	a	Regulatory	Framework	for	all	electricity generation	Large	Combustion	Plants	for	the	period	from	2016	onwards,	principally	comprising	coal-fired,	gas-fired,	oil-fired	and	biomass-fired	plants.	The	following steps	may	be	required	in	respect	of	Kilroot:	(i)	fit	selective	catalytic	reduction	and	comply	with	the	new	limits	by	2023,	at	which	time	there	may	be	another	review; (ii)	opt	out	and	run	under	a	limited	life	derogation	for	a	maximum	of	17,500	hours;	and	(iii)	opt	into	a	Transitional	National	Plan	which	shall	apply	from	January	1,	2016 until	June	30,	2020	then	option	to	comply	with	Emission	Limit	Values	or	Closure.

Currently,	the	Ballylumford	units	4,	5	and	6	(the	B	Station)	are	scheduled	to	close	by	the	end	of	2015	under	the	Large	Combustion	Plant	Directive;	however,	there is	the	possibility	that	these	units	may	be	adapted	to	be	compliant	under	the	Industrial	Emissions	Directive.	The	exact	detail	will	not	be	known	until	the	Industrial Emissions	Directive	is	implemented.

With	regard	to	the	C	Station	at	Ballylumford,	gas	turbines	using	light	oils	and	middle	distillates	as	liquid	fuels	shall	be	subject	to	an	emission	limit	value	for	NO of	90mg/Nm3.	GT10	(part	of	the	CCGT	plant)	is	currently	permitted	to	120mg/m3	on	distillate.	This	could	mean	that	possible	modifications	are	required	to	be	able	to continue	to	run	distillate	as	a	dual	fuel.

It	is	expected	that	there	will	be	transitionary	arrangements	within	the	Directive	to	allow	plants	to	manage	the	introduction	of	the	new	limits	and	it	has	been suggested	that	large	combustion	plants	may	have	until	July	2020	to	meet	the	requirements.	The	option	appears	attractive	to	AES	and	would	allow	the	units	to	operate without	substantial	capital	investment	on	a	restricted	load	factor	until	the	end	of	2020.	After	2020,	AES	would	be	required	to	comply	with	the	new	emissions	limits	in order	to	continue	operations.

The	Environmental	Liability	Directive	came	into	force	in	Northern	Ireland	on	June	24,	2009	and	is	aimed	at	the	prevention	and	remedying	of	environmental damage.	An	operator	will	be	held	financially	liable	if	is	carries	out	certain	activities	which	cause	environmental	damage,	or	where	there	is	an	imminent	threat	of	such damage,	regardless	of	whether	it	intended	to	cause	the	damage	or	was	negligent.	This	includes	IPPC	permitted	installations.	In	practice	there	should	be	no	real	change	to AES'	operations	as	a	result	of	the	coming	into	force	of	this	Directive.

Material	Regulatory	Actions.	On	November	25,	2009,	the	NIAUR	published	a	"Consultation	Paper	on	Relevant	Considerations	in	Relation	to	the	Possible Cancellation	of	Generating	Unit	Agreements	in	Northern

Ireland"	which	is	relevant	to	various	long-term	PPAs	in	Northern	Ireland	including	those	at	Kilroot	and	Ballylumford.	On	April	30,	2010,	NIAUR	made	notification	to Kilroot	that	it	intended	to	exercise	the	early	cancellation	provisions	of	the	GUAs	for	the	main	coal	units	(K1	and	K2)	effective	November	1,	2010.	The	formal cancellation	notices	were	received	on	October	28,	2010	instructing	NIEE	to	cancel	the	GUAs	for	units	K1	and	K2	effective	November	1,	2010.	All	remaining	units remain	contracted	but	are	kept	under	review.	Units	K1	and	K2	fully	operate	within	the	SEM	(as	mentioned	above).

Potential	or	Proposed	Regulations.	In	November	2010,	the	Council	of	the	EU	approved	a	revised	directive	on	industrial	emissions	so	as	to	reduce	emissions	of pollutants	that	are	harmful	to	the	environment	and	associated	with	cancer,	asthma	and	acid	rain.	The	industrial	emissions	directive	seeks	to	prevent	and	control	air,	water and	soil	pollution	by	industrial	installations.	It	regulates	emissions	of	a	wide	range	of	pollutants,	including	sulphur	and	nitrogen	compounds,	dust	particles,	asbestos	and heavy	metals.	The	directive	is	aimed	at	improving	local	air,	water	and	soil	quality,	not	at	mitigating	the	global	warming	effects	of	some	of	these	substances.	The	review integrates	seven	directives	into	a	single	legal	Framework	and	provides	for	a	more	harmonized	and	rigorous	implementation	of	emissions	limits	associated	with	the cleanest	available	technology,	so-called	BAT.	Deviations	from	this	standard	are	only	permitted	where	local	and	technical	characteristics	would	make	it disproportionately	costly.	The	recast	also	tightens	emission	limits	for	NO ,	SO 	and	dust	from	power	plants	and	large	combustion	installations	in	oil	refineries	and	the metal	industry.	New	plants	must	apply	the	cleanest	available	technology	from	2012,	four	years	earlier	than	initially	proposed.	Existing	plants	have	to	comply	with	this standard	from	2016,	though	a	transition	period	is	foreseen.	Until	June	30,	2020,	member	states	may	define	transitional	plans	with	declining	annual	caps	for	NO X,	SO 	or dust	emissions.	Where	installations	are	already	scheduled	to	close	by	the	end	of	2023	or	operate	less	than	17,500	hours	after	2016,	they	may	not	need	to	upgrade. Member	States	have	two	years	to	transpose	the	Directive.

# Middle	East	&	Asia

# China

In	2005,	the	National	Development	and	Reform	Commission	("NDRC")	released	interim	regulations	governing	on-grid	tariffs,	along	with	two	other	regulations governing	transmission	and	retail	tariffs.	The	On-Grid	Tariff	Measures	specify	different	rules	for	the	determination	of	on-grid	tariffs	before	and	after	the	implementation of	competitive	pricing.	Before	the	implementation	of	competitive	pricing,	the	on-grid	tariffs	shall	be	appraised	and	ratified	by	the	pricing	authorities	by	reference	to	the economic	life	of	power	generation	projects	and	determined	in	accordance	with	the	principle	of	allowing	IPPs	to	cover	reasonable	costs	and	to	obtain	reasonable	returns. Such	costs	were	defined	to	be	the	average	costs	in	the	industry	and	reasonable	returns	will	be	calculated	on	the	basis	of	the	interest	rate	of	China's	long-term	Treasury bond	plus	certain	percentage	points.	After	the	establishment	of	competitive	regional	power	markets,	the	on-grid	tariffs	of	electricity	generation	companies	which participate	in	the	competitive	market	shall	principally	consist	of	two	components:	the	capacity	charge,	which	is	to	be	determined	by	the	tariff	regulatory	authority,	and the	energy	charge,	which	is	to	be	determined	by	market	competition.	However,	no	implementation	rules	have	been	issued	to	introduce	the	competitive	pricing.	The Retail	Tariff	Measures	aim	to	reform	the	various	classes	of	tariff	for	end-users	into	three	categories:	residential	electricity,	electricity	used	in	agricultural	production	and electricity	used	in	industry,	commerce	or	for	other	purposes.	The	tariff	for	each	category	is	fixed	per	voltage	class.	The	tariffs	shall	be	determined	with	consideration	to the	fair	sharing	of	the	burden,	the	efficient	adjustment	of	the	demand	for	electricity	and	the	public	policy	objectives.

In	addition	to	the	foregoing	tariff-setting	mechanism,	China's	central	government	also	issued	a	tariff	adjustment	policy	allowing	the	on-grid	tariffs	to	be	pegged to	the	fuel	price	in	the	case	of	significant	fluctuations	in	fuel	price.	Seventy	percent	of	the	increase	in	fuel	costs	may	be	passed	through	in	the	tariff.	The	tariffs	of	coal- fired	facilities	in	China	were	increased	in	2005,	2006,	2008	and	2009	pursuant	to	this	policy	to	alleviate	the	escalation	of	fuel	price;	however,	such	adjustments	were obtained	from	the	regulatory	authorities	only	after	a	time	lag	and	fell	short	of	compensating	all	businesses	for	coal	price	increases	in	recent	years.	There	was	no	catch-up tariff	adjustment	in	2010	pursuant	to	the	foregoing	policy.

Pursuant	to	the	"Renewable	Energy	Law	of	China,"	which	came	into	effect	on	January	1,	2006	and	was	amended	on	December	26,	2009,	renewable	resources such	as	wind,	solar,	biomass,	geo-thermal	and	hydro	enjoy	complete	and	unrestricted	generation	and	dispatch,	and	local	grid	interconnection	is	mandated	to	such	plants. To	implement	the	Renewable	Energy	Law,	on	August	2,	2007,	various	central	government	agencies	jointly	issued	the	"Temporary	Measures	for	Dispatching	Electricity Generated	by	Energy	Conservation	Projects".	Under	this	regulation,	power	plants	are	categorized	into	various	groups	and	each	group	will,	under	certain	circumstances, enjoy	priority	dispatch	over	the	subsequent	groups.	The	first	group	is	renewable	energy	power	plants,	namely	wind,	hydro,	solar,	biomass,	tidal-wave,	geo-thermal	and landfill	gas	power	plants	that	satisfy	certain	environmental	standards.	The	second	group	is	nuclear	power	plants.	The	third	group	is	power	plants	using	"modern	coal" which	includes	cogeneration	power	plants,	and	power	plants	utilizing	residual	heat,	residual	gas,	coal-gangue	(or	waste	coal)	and	coal	mine	methane.	The	last	three groups	are	natural	gas,	conventional	coal	and	oil-fired	power	plants.	As	a	result,	power	plants	using	renewable	resources	will	enjoy	priority	dispatch	over	power	plants using	fossil	fuels.	The	amendment	to	the	Renewable	Energy	Law	requires	that	the	local	grid	companies	abide	by	the	periodic	targets	developed	by	the	government	on	the proportion	of	power	to	be	generated	by	renewable	energy	sources	as	compared	to	the	total	electricity	generation	and	to	purchase	the	entire	amount	of	electricity generated	by	renewable	resources.	This	is	in	line	with	the	requirement	that	renewable	energy	power	plants	will	enjoy	unrestricted	generation	and	dispatch	under	the Renewable	Energy	Law,	as	well	as	the	Chinese	government's	policy	objective	to	encourage	comprehensive	utilization	of	resources	in	an	energy	efficient	and environmentally	friendly	manner.

In	2007,	the	Chinese	government	issued	a	number	of	rules	and	procedures	that	govern	the	shutdown	of	small	coal	or	oil-fired	power	plants.	The	types	of	plants	to be	shut	down	include:	(i)	power	plants	with	a	capacity	under	50	MW;	(ii)	power	plants	with	a	capacity	of	up	to	100	MW	which	are	over	20	years	old;	(iii)	power	plants with	a	capacity	of	up	to	200	MW	whose	equipment	has	reached	the	end	of	its	useful	life;	and	(iv)	power	plants	that	have	coal	consumption	rates	that	are	higher	than either	10%	above	the	applicable	provincial	average	or	15%	above	the	national	average.	The	shutdown	procedures	have	been	set	in	place	to	ensure	that	certain	smaller power	plants	are	appropriately	shut	down	and	replaced	by	larger	and	more	efficient	power	plants.	The	purpose	of	such	rules	and	regulations	is	again	in	accordance	with China's	policy	to	achieve	energy	conservation	and	emissions	reductions.	China	Power	International	Holdings	Ltd.,	our	joint	venture	partner	in	Wuhu	IV,	intended	to construct	and	develop	a	2x600	MW	coal-fired	power	plant.	According	to	this	policy	and	the	ratification	for	the	unit	of	Wuhu	V	needs	to	obtain	the	corresponding	closing and	shut-down	capacity.	After	consultation	among	all	shareholders	of	Wuhu	IV,	the	shareholders,	including	AES,	agreed	to	transfer	their	respective	shares	to	the	owner of	Wuhu	V	and	to	shut	down	Wuhu	IV.	The	consideration	for	the	sale	of	our	25%	share	in	Wuhu	IV	is	Renminbi	50	million	($7.6	million).	The	deal	is	expected	to	be closed	by	the	end	of	March	2011.

On	July	20,	2009,	NDRC	issued	the	"Circular	on	Refining	the	Policy	for	On-Grid	Pricing	of	Wind	Power"	(NDRC	Price	2009	No.	1906),	which	introduces	a benchmark	system	for	on-grid	tariffs	for	wind	power	replacing	the	existing	public	bidding	and	concession	model	for	wind	projects.	The	circular	provides	that	on-grid tariffs	for	onshore	wind	power	projects	approved	from	August	1,	2009	onwards	are	fixed	using	a	centrally	controlled	price	determination	mechanism,	while	on-grid tariffs	for	offshore	wind	projects	will	be	determined	separately.	Under	the	circular,	China's	onshore	area	is	divided	into	four	different	types	of	wind-power	resource regions,	and	different	prices	are	set	for	each	of	these	regions	ranging	from	0.51	yuan/kWh	(US	cent	7.5/kWh)	for	wind	power	in	regions	with	the	best	wind	resources, such	as	Inner	Mongolia,	to	0.61	yuan/kWh	(US	cent	8.9/kWh)	for	regions	with	the	worst	wind	resources.	According	to	NDRC,	the	legislation's	intent	is	to	standardize the	wind	power	price	regulation	and	promote	healthy	and	sustainable	development	of	the	wind-power	industry.	Currently,	we	do	not	expect	that	this	newly	issued circular	will	have	a	material	adverse	impact	on	our	wind	power	businesses	in	China.

# India

Structure	of	Electricity	Market.	Pursuant	to	reforms	by	the	Government	of	India,	including	enactment	of	the	Electricity	Act	of	India	("EAI"),	the	electricity	market in	India	is	moving	towards	a	multi-buyer,	multi-seller	system	as	opposed	to	the	past	structure	which	permitted	a	single	buyer	to	purchase	power	from	power	generators.

This	legal	and	regulatory	framework	provides	flexibility	in	granting	electricity	regulatory	commissions	freedom	in	determining	tariffs	as	well	as	encouraging competition	with	regulatory	intervention.	Transmission,	distribution	and	trade	of	electricity	remain	regulated	activities	which	require	licenses	from	an	electricity regulatory	commission,	unless	exempted.	The	Central	Government,	through	the	Ministry	of	Power,	is	involved	in	the	power	sector	planning,	policy	formulation	and appointment	of	central	regulators.	State	governments	also	have	powers	to	appoint	or	remove	members	of	the	State	Regulatory	Commissions.	The	state	governments	set up	and	notify	the	state	load	dispatch	center.	Under	the	EAI,	the	state	governments	are	required	to	unbundle	the	State	Electricity	Boards	into	separate	generation, distribution	and	transmission	companies.

Principal	Regulators.	India's	power	sector	is	regulated	by	a	two-level	regulatory	system:	at	the	national	level,	the	Central	Electricity	Regulatory	Commission ("CERC");	and	at	the	state	level,	the	State	Electricity	Regulatory	Commissions	("SERC")	(together	the	"Regulatory	Commissions").	CERC	regulates	tariffs	of generating	stations	owned	by	the	Central	Government,	or	those	involved	in	generating	in	more	than	one	State,	and	regulating	interstate	transmission	of	electricity.	SERC regulates	intra-state	transmission	and	supply	of	electricity	within	each	state.	While	discharging	functions	under	the	EAI,	regulatory	commissions	are	guided	by	the National	Electricity	Policy,	the	Tariff	Policy	and	the	National	Electricity	Plan	and	directions	on	any	policy	involving	public	interest	issued	by	the	Central	Government	or state	government.	Regulatory	Commissions	are	quasi-judicial	authorities	entrusted	with	various	functions	including	determining	tariffs,	granting	licensees	and	settling disputes	between	the	generating	companies	and	the	licensees,	and	between	licensees.	An	Appellate	Tribunal	has	been	set	up	for	appeal	against	orders	of	Regulatory Commissions.	The	Appellate	Tribunal	has	quasi-judicial	powers	to	summon,	enforce	attendance,	require	discovery,	receive	evidence	and	review	decisions.	The	orders	of the	Appellate	Tribunal	are	executable	as	decrees	of	a	civil	court	and	can	be	challenged	in	the	Supreme	Court.

Principal	Regulations.	In	2003,	the	Government	of	India	enacted	the	EAI	to	establish	a	framework	for	a	multi-seller/multi-buyer	model	for	the	electricity industry,	introducing	significant	changes	to	India's	electricity	sector.	The	EAI	is	a	central	unified	legislation	relating	to	generation,	transmission,	distribution	trading	and use	of	electricity	that	replaced	multiple	legislations.	Pursuant	to	the	EAI,	the	Government	of	India	ratified	the	National	Electricity	Policy	in	2005	and	the	National	Tariff Policy	in	2006.	The	policies	established	deadlines	to	implement	different	provisions	of	the	EAI.	However,	the	pace	of	actual	implementation	of	the	reform	process	is contingent	on	the	respective	state	governments	and	SERCs,	as	electricity	is	a	"concurrent"	subject	in	India's	constitution.	There	is	no	license	required	to	set	up generation	plants	under	the	EAI	and	generators	are	allowed	to	sell	to	state	utilities,	traders	and	open-access	consumers.	The	access	to	consumers	is	subject	to	regulatory provisions	on	transmission	corridor	availability	and	payment	of	cross-subsidy	surcharge.

The	Central	Government	ratified	the	National	Electricity	Policy	in	2005,	which	includes	the	following	objectives:	access	to	electricity	for	all	households; availability	of	power	demand	to	be	met	by	2012;	energy	and	peaking	shortages	to	be	overcome	and	adequate	spinning	reserve	to	be	available;	supply	of	reliable	and quality	power	of	specified	standards	in	an	efficient	manner	and	at	reasonable	rates;	per	capita	availability	of	electricity	to	be	increased	to	over	1,000	units	by	2012; financial	turnaround	and	the	commercial	viability	of	electricity	sector;	and	the	protection	of	consumers'	interests.	The	"Policy	for	setting	up	of	Mega	Power	Projects" was	ratified	by	the	Ministry	of	Power	in	1995,	and	has	been	revised	from	time	to	time.	Conditions	required	to	be	fulfilled	by	a	developer	for	the	grant	of	Mega	Power Project	status	include	a	thermal	power	plant	with	a	capacity	of	700	MW	or	more	located	in	the	States	of	Jammu	&	Kashmir,	the	north	eastern	states	of	India;	a	thermal power	plant	of	a	capacity	of	1,000	MW	or	more	located	in	States	other	than	those	specified	above;	a	hydro	electricity	power	plant	of	a	capacity	of	350	MW	or	more located	in	the	States	of	Jammu	&	Kashmir,	the	northeastern	states	of	India;	or	a	hydro	electricity	power	plant	of	a	capacity	of	500	MW	or	more	located	in	states	other than	those	specified	above.	Mega	Power	Projects	would	be	required	to	secure	long-term	PPAs	with	distribution	companies	in	accordance	with	the	National	Electricity Policy	2005	and	the	National	Tariff	Policy	2006,	as	amended	from	time	to	time.	Fiscal	concessions	available	to	the	Mega	Power	Projects	include	the	import	of	capital equipment	free	of	customs	duty	and	export	benefits	are	available	to	domestic	bidders	for	projects	under	both	public	and	private	sectors	after	meeting	certain requirements.	Capital	goods	required	for	setting	up	any	mega	power	project	qualify	for	the	above

fiscal	benefits	after	it	is	certified	that:	(i)	the	power	purchasing	states	have	granted	to	the	Regulatory	Commissions	full	powers	to	fix	tariffs;	(ii)	the	power	purchasing states	undertake,	in	principle,	to	privatize	distribution	in	all	cities,	in	that	state,	which	has	a	population	of	more	than	one	million,	within	a	period	to	be	fixed	by	the Ministry	of	Power;	and	(iii)	the	income	tax	holiday	regime	as	per	Section	80-IA	of	the	Income	Tax	Act,	1961	is	also	available.

The	EAI	specifies	trading	in	electricity	as	a	licensed	activity.	The	license	for	electricity	trading	is	required	to	be	obtained	from	the	relevant	regulatory commission.	In	2009,	CERC	issued	regulations	for	the	grant	of	trading	licenses	to	regulate	the	interstate	trading	of	electricity.	Trading	license	regulations	set	out qualifications	for	the	grant	of	the	license	including	technical	and	professional	qualifications	and	net	worth	requirements.	Licensees	are	subject	to	conditions	specifying, among	other	things	the	extent	of	trading	margin,	maintenance	of	records	and	a	requirement	to	pay	a	license	fee,	as	specified	by	CERC.	The	Regulatory	Commissions have	the	right	to	fix	a	ceiling	on	trading	margins	in	intra-state	trading.	Two	power	exchanges	have	received	licenses	from	CERC	and	have	started	operations.	The volume	of	power	trading	on	the	power	exchanges	is	short-term	as	the	bulk	of	power	is	still	traded	through	long-term	bilateral	contracts.

Environmental	Regulations.	Compliance	with	relevant	environmental	laws	is	the	responsibility	of	the	occupier	or	operator	of	the	facilities.	Principal	regulations include	the	"Environment	(Protection)	Act,	1986"	("EPAct"),	an	umbrella	legislation	of	environmental	protection	laws.	The	EPAct	vests	the	Government	of	India	with the	power	to	take	measures	it	deems	necessary	for	protecting	and	improving	the	quality	of	the	environment	and	preventing	and	controlling	environmental	pollution.	This includes	rules	for	the	quality	of	the	environment,	standards	for	emission	of	discharge	of	environmental	pollutants	from	various	sources	and	inspection	of	any	premises, plant,	equipment,	machinery,	and	materials	likely	to	cause	pollution.	Penalties	for	violation	of	the	EPAct	include	fines	or	imprisonment.	"Environment	Impact Assessment	Notification	S.O.	1533(E),	2006"	issued	under	the	EPAct	and	the	Environment	(Protection)	Rules,	1986,	mandate	prior	approval	by	the	Ministry	of Environment	&	Forests	or	State	Environment	Impact	Assessment	Authority	for	establishing	a	new	project	or	expansion	or	modernization	of	existing	projects.	Projects that	require	preparation	of	an	environment	impact	assessment	report	involve	public	consultation	and	hearings.	Pursuant	thereto,	the	appropriate	authority	makes	an appraisal	of	the	project	after	a	final	environment	impact	assessment	report	is	submitted	addressing	the	questions	raised	in	the	public	consultation	process.	"The	Water (Prevention	and	Control	of	Pollution)	Cess	Act,	1977"	(the	"Water	Cess	Act")	mandates	levy	and	collection	of	a	tax	on	water	consumed	by	industries	calculated	on	the basis	of	the	amount	of	water	consumed	for	any	of	the	purposes	specified	under	the	Water	Cess	Act.	"The	Air	(Prevention	and	Control	of	Pollution)	Act,	1981"	(the	"Air Act")	requires	an	industrial	plant	to	obtain	consent	of	the	State	Pollution	Control	Board	("Board").	Similarly,	"The	Water	(Prevention	and	Control	of	Pollution)	Act, 1974"	(the	"Water	Act")	provides	provisions	for	making	an	application	to	the	Board	for	establishing	an	industry	which	may	cause	effluent	discharge	into	water	bodies. The	Board	may	impose	conditions	relating	to	pollution	control	equipment	to	be	installed	at	the	facilities.	Industrial	plants	in	any	air	pollution	control	area	are	not permitted	to	discharge	emissions/air	pollutants	in	excess	of	the	standards	laid	by	the	Board.	Under	the	Air	Act	and	the	Water	Act,	the	Central	Pollution	Control	Board has	powers	to	specify	standards	for	quality	of	air,	while	State	Boards	have	powers	to	inspect	any	control	equipment,	industrial	plant	or	manufacturing	process.

Material	Regulatory	Actions.	The	Electricity	Regulatory	Commission	("ERC")	is	empowered	to	determine	tariffs	for	supply	of	electricity	by	a	generating company	to	a	distribution	licensee,	transmission	of	electricity,	wheeling	of	electricity	and	retail	sale	of	electricity.	In	case	of	a	shortage	of	supply	of	electricity,	the	ERC may	fix	the	minimum	and	maximum	tariff	ceiling	for	sale	or	purchase	of	electricity	for	a	period	not	exceeding	one	year	to	ensure	reasonable	prices	of	electricity.	While determining	tariffs,	the	ERC	follows	principles	and	methodologies	specified	by	the	CERC	for	determination	of	tariffs,	including	the	principle	that	generation, transmission,	distribution	and	supply	of	electricity	should	be	conducted	on	commercial	principles	and	takes	into	account	factors	which	encourage	competition, efficiency	and	economical	use	of	resources.

The	EAI	provides	that	the	ERC	will	adopt	such	tariffs	determined	through	a	transparent	process	of	bidding	in	accordance	with	guidelines	issued	by	the	Central Government.	The	Central	Government,	through	the	Ministry

of	Power,	has	issued	guidelines	for	competitive	bidding	and	draft	documentation	(PPAs)	for	competitively	bid	projects.	The	determination	of	tariffs	for	a	power	project depends	on	the	mode	of	participation	in	the	project.	Tariffs	may	be	determined	in	two	ways:	(i)	based	on	tariff	principles	prescribed	by	CERC,	i.e.,	cost-plus	basis consisting	of	a	capacity	charge,	an	energy	charge,	an	unscheduled	interchange	charge	and	incentive	payments;	or	(ii)	a	competitive	bidding	process	where	the	tariff	is purely	market	based.

The	ERC	is	required	to	adopt	a	bid-based	tariff,	although	the	"Guidelines	for	Determination	of	Tariff	by	Bidding	Process	for	Procurement	of	Power	by Distribution	Licensees,	2005"	("Bidding	Guidelines")	permit	the	bidding	authority	to	reject	all	price	bids	received.	The	Bidding	Guidelines	recommend	bid	evaluation on	the	basis	of	levelized	tariff	and	include	two	types	of	bids:	Case	I	bids,	where	the	location,	technology	and	fuel	is	not	specified	by	the	procurers,	i.e.,	the	generating company	has	the	freedom	to	choose	the	site	and	the	technology	for	the	power	plant;	and	Case	II	bids,	where	the	projects	are	location-specific	and	fuel-specific.	Tariff rates	for	procurement	of	electricity	by	distribution	licensees	can	be	for	long-term	procurement	of	electricity	for	a	period	of	seven	years	and	above;	or	medium-term procurement	for	a	period	of	up	to	seven	years	but	exceeding	one	year.	For	long-term	procurement	under	tariff	bidding	guidelines,	a	two-stage	process	is	adopted	for	the bid	process	and	includes	a	request	for	qualification	and	request	for	proposal.	The	procurer	may	adopt	a	single-stage	tender	process	for	medium-term	procurement, combining	the	request	for	qualification	and	request	for	proposal	processes.	Under	this	route,	IPPs	can	bid	at	two	parameters,	i.e.,	the	fixed	or	capacity	charge	or	the variable	or	energy	charge,	which	comprises	the	fuel	cost	for	the	electricity	generated.	The	bidders	are	usually	permitted	to	quote	a	base	price	and	an	acceptable	escalation formula.	Bidding	Guidelines	include	a	two-step	process—pre-qualification	and	final	bid.	Bidders	are	required	to	submit	a	technical	and	financial	bid	at	the	RFP	stage. Power	purchase	and	distribution	licenses	are	increasing	through	the	competitive	bid	route.	The	Tariff	Policy	requires	all	procurement	of	power	after	January	6,	2006 (except	for	PPAs	approved	or	submitted	for	approval	before	January	6,	2006	or	projects	which	have	obtained	financing	prior	to	January	6,	2006)	by	distribution licensees	to	be	through	competitive	bidding.	Some	state	regulators	have	ratified	the	purchase	of	power	under	memorandums	of	understanding,	on	the	ground	that	the tariff	policy	discussed	above	is	merely	indicative	and	not	binding.

# Kazakhstan

Structure	of	Electricity	Market.	In	Kazakhstan,	the	electricity	sector	is	divided	into	wholesale	and	retail	markets.	The	wholesale	electricity	market	of	Kazakhstan	is based	on	bilateral	contracts	conducted	through	an	over-the-counter	market	and	KOREM's	centralized	trading	system.	In	the	retail	market,	the	power	distribution	and supply	functions	are	unbundled	and	retail	customers	with	consumption	of	one	MW	or	more	have	a	right	to	buy	the	electricity	directly	from	power	plants	or	retail	supply companies.

Principal	Regulators.	The	Government	of	Kazakhstan	approves	subordinate	acts	in	the	power	sector	(licensing	requirement,	technical	regulations,	market	rules, tariff	methodologies	for	natural	monopolies,	etc.)	and	determines	the	level	of	price	caps	for	groups	of	power	plants.

The	Ministry	of	Industry	and	New	Technologies	(the	"Ministry")	is	the	central	executive	body	responsible	for	developing	state	policy	in	the	power	sector	and conducting	technical	regulation.	As	a	part	of	price	cap	regulation,	the	Ministry	is	responsible	for	determining	groups	of	power	companies	for	each	price	cap,	annual adjustments	of	price	caps	and	signing	agreements	on	investment	obligations	with	power	plants.

The	Agency	for	Regulation	of	Natural	Monopolies	(the	"Regulator")	acts	as	a	regulator	of	industries	considered	to	be	"natural	monopolies"	(transmission	and distribution	of	oil,	gas,	electricity	and	heat,	railroads,	airports,	etc.).	In	the	power	industry,	the	Regulator	is	responsible	for	the	approval	of	tariffs	for	heat	generation, distribution	and	supply,	electricity	transmission	and	distribution	as	well	as	end-user	tariffs	for	dominant	companies	in	the	retail	power	market.	The	Regulator	grants different	licenses	in	the	power	sector	such	as	licenses	for	generation,	distribution	and	retail	activities.

The	Agency	for	Protection	of	Competition	(the	"AZK")	monitors	power	market	participants	to	determine	entities	with	a	dominant	position	and	detect	violations	of antimonopoly	legislation.

The	Ministry	of	Environmental	Protection	(the	"Environmental	Ministry")	is	responsible	for	environmental	policy,	grants	emissions	permits	and	evaluates	the environmental	impact	of	new	projects.

JSC	KEGOC	is	a	state-owned	electricity	transmission	company,	which	also	acts	as	the	system	operator	with	a	central	dispatch	management	function	and	as	the operator	of	the	balancing	market.

Principal	Regulations.	The	following	major	laws	and	regulations	govern	the	electricity	industry:

•Law	"On	the	Power	Industry"	(the	"Kazakhstan	Electricity	law");

•Law	"On	Natural	Monopolies	and	Regulated	Markets";

•Law	"On	Competition";

•Law	"On	Supporting	the	Use	of	Renewable	Energy	Sources";

•Environmental	Code;

•Law	"On	Licensing";

•	 Resolution	of	the	Government	of	the	Republic	of	Kazakhstan	"On	Approval	of	the	Price	Caps";	and

•The	state	program	of	power	industry	development	in	2010-2014.

Continuous	changes	in	the	law	and	regulations	result	in	contradictions	between	different	laws	and	regulations.	This	in	turn	results	in	an	uncertain	regulatory environment	in	the	power	sector.

The	key	elements	of	price	cap	regulation	of	power	plants	are	as	follows:	(i)	the	Ministry	has	determined	the	power	plant	grouping	based	on	the	plant	type, equipment,	fuel	and	distance	from	coal	mines	(thirteen	groups	of	power	plants	were	defined);	(ii)	the	Ministry	has	proposed	to	the	government	the	price	cap	for	each group	based	on	actual	prices	in	2008	and	the	level	of	investment	required	and	the	government	has	approved	price	caps	for	each	groups	of	power	plants	for	the	seven-year period	from	2009-2015;	(iii)	the	Ministry	may	propose	to	the	government	additional	annual	adjustments	to	price	caps	to	reflect	inflation	and	investment	requirements within	any	group	or	a	power	plant	may	apply	for	an	individual	investment	tariff	to	the	Ministry	and	the	Regulator;	(iv)	a	power	plant	determines	its	investment obligations	at	its	own	discretion	and	signs	an	agreement	with	the	Ministry	on	investment	obligations;	and	(v)	the	price	cap	and	individual	investment	tariff	regime	does not	constitute	a	price	guarantee	and	power	plants	should	sell	to	consumers	at	the	competitive	market	price	but	not	higher	than	their	group	price	cap	or	an	individual investment	tariff.	Only	exports	of	power	and	sale	of	ten	percent	of	generation	through	a	centralized	trading	system	are	exempt	from	this	restriction.	Power	trading activities	are	restricted	and	power	plants	are	allowed	to	conduct	trading	activities	to	provide	electricity	supply	to	their	consumers	during	emergency	shutdowns.

The	Regulator	approves	and	regulates	all	tariffs	for	heat	generation,	transmission	and	supply,	as	well	as	electricity	transmission	and	distribution	tariffs	on	a	cost- based	methodology.	Power	trading	companies,	which	the	AZK	considers	dominant	entities,	must	notify	the	Regulator	of	any	proposed	increase	in	their	tariffs	and	the Regulator	has	the	right	to	veto	such	proposed	tariff	increases.	Furthermore,	the	Regulator	has	the	right	to	request	a	decrease	in	the	applicable	tariffs.

The	AZK	determines	the	borders	of	electricity	markets	at	its	own	discretion,	which	does	not	correspond	with	the	provisions	of	the	Kazakhstan	Electricity	Law, and	designates	entities	with	dominant	market	power.	The	AZK	may	consider	the	tariff	of	a	power	plant	which	is	in	compliance	with	price	cap	regulation	to	be	an excessive	monopolistic	price	of	a	dominant	entity	and	impose	sanctions,	as	happens	from	time	to	time	to	AES'	generating	companies.

Environmental	regulations.	The	Environmental	Ministry	is	responsible	for	environmental	policy	and	environmental	regulations.	The	Environmental	Ministry issues	environmental	permits,	sets	emissions	limits	and

organizes	ecological	control	in	the	forms	of	state	environmental	impact	assessment	and	independent	ecological	audit.	The	Environmental	Ministry	reviews	applications of	power	plants	and,	after	conducting	the	environmental	impact	assessment,	grants	environmental	permits	for	industrial	waste,	air	and	water	pollutions	for	a	period	of	not more	than	three	years.

Material	Regulatory	Actions.	In	December	2010,	the	Ministry	refused	to	sign	agreements	on	investment	obligations	with	AES	UK	HPP	and	AES	UK	CHP	for 2011	and	has	requested	to	amend	the	existing	agreement	on	investment	obligation	from	AES	Shulbinsk	HPP	in	2011.	The	Ministry	has	demanded	that	AES	power	plants in	Kazakhstan	undertake	an	additional	obligation	to	spend	all	profits	in	new	investment	projects.	The	absence	of	signed	agreements	on	investment	obligations	may	lead to	further	sanctions	by	the	AZK	and	other	state	authorities	against	our	businesses.

The	AREM	has	refused	to	grant	a	necessary	tariff	increase	to	the	AES	retail	company	Shygysenergotrade	LLP	for	2011.	Contrary	to	applicable	law,	AREM	is requesting	that	Shygysenergotrade	LLP	confirm	the	existence	of	agreements	on	investment	obligations	between	the	AES	power	plants	and	the	Ministry	as	a	condition	for the	right	to	purchase	power	at	new	price	caps.	Increased	investment	costs	and/or	sanctions	could	have	a	material	impact	on	these	businesses,	require	additional	capital investment,	and	may	impact	our	results	of	operations.

The	AZK	has	designated	all	AES	power	plants	in	Kazakhstan	as	dominant	entities	in	the	Eastern	Kazakhstan	and	Pavlodar	regions.	Shygysenergotrade	LLP	has also	been	designated	by	the	AZK	as	a	dominant	entity	in	the	Eastern	Kazakhstan	retail	market.	AES	has	challenged	these	designations	but	so	far	has	been	unsuccessful in	having	the	designations	overturned.	The	AZK	is	conducting	other	investigations	into	alleged	violations	by	AES	businesses	in	Kazakhstan	of	antimonopoly	legislation such	as	excessive	monopolistic	prices	and	ungrounded	refusal	to	supply	power	to	certain	customers.	AES	believes	that	the	investigations	per	se	and	allegations	made	by the	AZK	in	the	course	of	investigations	are	without	merits,	and	AES	is	vigorously	challenging	the	unfounded	actions	of	the	AZK.	However,	if	AES	Kazakhstan	does	not prevail	in	these	proceedings,	there	could	be	a	material	impact	on	these	businesses	and	our	results	of	operations.

Potential	or	Proposed	Regulations.	The	Ministry	plans	to	introduce	a	capacity	market	starting	in	2015	to	support	new	investments	in	generating	assets.	The capacity	market	should	replace	price	cap	regulation.	Details	of	the	new	regulations	are	not	yet	publicly	available	and	the	regulations	are	still	under	review	by	the government.	The	capacity	market	regulations	could	be	unfavorable	to	our	businesses	in	Kazakhstan	and	may	have	a	material	impact	on	our	financial	results.

The	Ministry	and	the	Regulator	have	drafted	amendments	to	the	Kazakhstan	Electricity	Law	to	increase	sanctions	for	any	failure	to	implement	the	investment program	or	comply	with	the	price	cap	regulation.	The	absence	of	a	signed	agreement	on	investment	obligations	will	limit	a	power	plant's	right	to	apply	tariffs	up	to	the price	cap,	such	that	the	electricity	tariff	of	a	power	plant	cannot	not	exceed	its	2008	level.	It	is	expected	that	this	regulation	will	come	into	force	in	2011.	As	a	result,	we may	be	required	to	make	significant	capital	investments	and	to	incur	other	expenses	in	order	to	obtain	the	benefits	of	the	price	caps.

The	Regulator	plans	to	introduce	benchmarking	tariff	regulations	for	power	distribution	to	be	effective	in	2013.	The	Environmental	Ministry	plans	to	amend	the Ecological	Code	to	introduce	carbon	regulation	to	comply	with	the	Kyoto	Protocol,	which	was	ratified	by	Kazakhstan.	According	to	the	draft	regulation,	a	power	plant will	receive	carbon	emissions	allocations	and	a	carbon	trading	system	will	be	established.	In	addition,	a	violation	of	environmental	legislation	may	lead	to	criminal liability	and	fines.

# Philippines

Structure	of	Electricity	Market.	From	a	vertically	integrated	industry,	the	Philippines	has	unbundled	its	power	sector	into	generation,	transmission,	distribution	and supply.	The	enabling	law	for	this	restructuring	is	Republic	Act	No.	9136,	otherwise	known	as	the	Electric	Power	Industry	Reform	Act	of	2001	("EPIRA").	The

EPIRA	primarily	aims	to	increase	private	sector	participation	in	the	power	sector	and	to	privatize	the	Government's	generation	and	transmission	assets.	Generation	and supply	are	open	and	competitive	sectors,	while	transmission	and	distribution	are	regulated	sectors.	Sale	of	power	is	done	primarily	thorough	medium-term	contracts between	generation	companies	and	customers	specifying	the	volume,	price	and	conditions	for	the	sale	of	energy	and	capacity.	The	Energy	Regulatory	Commission ("ERC")	approves	the	said	contracts	for	supply	of	energy.	Power	is	also	traded	in	the	Wholesale	Electricity	Spot	Market	("WESM")	from	which	at	least	10%	of	the distribution	companies	or	electricity	cooperatives	power	requirement	must	be	sourced.

A	market	optimization	model	determines	the	price	and	dispatch	by	processing	the	bids	from	trading	participants	and	the	system	condition	from	the	system operator.	The	market	operator	then	comes	out	with	a	schedule	of	both	price	and	energy	which	maximizes	economic	gains	for	participants	subject	to	certain	constraints. The	dispatch	schedule	is	then	coordinated	with	the	system	operator	for	implementation.	The	market	is	operating	under	a	gross	pool,	net	settlement	system,	whereby	each generator	submits	energy	offers	regardless	of	their	contracted	energy.	However,	the	generator	should	declare	their	contracted	quantities,	since	the	market	will	not	include contracted	energy	in	its	settlement.

New	contracts	assigned	by	distribution	companies	for	consumption	after	expiration	are	awarded	to	generation	companies	either	through	the	lowest	supply	price offered	in	public	bid	processes	or	through	a	negotiated	contract.	The	ERC	then	approves	the	said	contract	benchmarked	against,	among	others,	the	prices	of	the	best	new entrant	generation	company.	Except	for	its	supply	to	MERALCO	(the	largest	distribution	company	in	the	Philippines),	to	which	it	is	allocated	about	14.89%	of	the contract	energy	under	the	NPC	Transition	Supply	Contract,	all	supply	contracts	of	AES	Masinloc	are	bilateral	contracts	already	provisionally	approved	by	the	ERC.

Principal	Regulators.	The	ERC,	created	under	the	EPIRA,	is	mandated	to	protect	long-term	consumer	interest	in	terms	of	quality,	reliability	and	reasonable pricing	of	sustainable	supply	of	electricity.	It	is	a	quasi-judicial	body	that	promulgates	and	enforces	rules,	regulations,	guidelines	and	policies.	The	Department	of Energy	is	mandated	to	prepare,	integrate,	coordinate,	supervise	and	control	all	plans,	programs,	projects	and	activities	of	the	government	relative	to	energy	exploration, development,	utilization,	distribution	and	conservation.	The	DOE	endorses	new	or	existing	generators.	The	Department	of	Environment	and	Natural	Resources administers	the	system	for	evaluating	the	environmental	impact	of	new	or	existing	generating	plants.

Principal	Regulations.	The	distinct	electricity	sector	activities	are	regulated	by	the	EPIRA.	Sector	activities	are	also	governed	by	the	corresponding	technical regulations	and	standards,	namely,	the	Philippine	Grid	Code,	Philippine	Distribution	Code,	Open	Access	Transmission	Service	Rules,	WESM	Rules,	and	Distribution System	Open	Access	Rules	("DSOAR").The	keystones	of	the	electricity	regulation	are:	(i)	performance	based	on	revenue	cap	and	non-discriminatory	access	to transmission	lines;	(ii)	a	contract-based	supply	and	spot	electricity	trading	for	generation;	(iii)	performance	based	on	maximum	average	price	and	non-discriminatory access	for	DUs	and	ECs	under	the	performance	base	rate	regime;	and	(iv)	electricity	supply	by	distribution	companies	in	their	respective	franchise	areas.

Section	31	of	EPIRA	establishes	the	Retail	Competition	and	Open	Access	("RC&OA")	under	which	Retail	Electricity	Suppliers,	who	are	duly	licensed	by	the ERC,	may	supply	directly	to	Contestable	Customers	(end-users	with	an	average	demand	of	at	least	1,000	kW)	with	DUs	and	ECs	providing	non-discriminatory	wires services.	Four	of	the	five	pre-conditions	for	RC&OA	have	already	been	satisfied	and	the	remaining	condition	for	open	access	to	commence	is	expected	to	be	achieved next	year.	Actual	RC&OA	may	commence	six	months	after	ERC's	determination	that	all	conditions	have	been	satisfied.

Environmental	Regulations.	The	Renewable	Energy	Act	of	2008	was	enacted	in	December	2008	("R.A.	9513")	R.A.	9513	promotes	non-conventional	renewable energy	sources,	such	as	solar,	wind,	small	hydroelectric	and	biomass	energies.	The	law	requires	that	electric	power	participants	to	initially	source	10%	of	their	supply from	eligible	renewable	energy	resources.	The	initial	requirement	of	10%	is	preliminary,	as	the	National	Renewable	Energy	Board	("NREB")	has	not	decided	on	the final	figure.	It	is	also	unknown	at	this	time	if	the

definition	of	electric	power	participant	applies	to	entities	that	are	power	producers	or	if	it	applies	to	power	consumers.	If	and	once	the	regulations	are	implemented,	our businesses	in	the	Philippines	could	be	adversely	impacted	by	having	to	source	a	portion	of	its	generation	from	renewable	energy	resources	to	supply	its	customers' contracts,	which	could	in	turn	affect	our	results	of	operations.

Under	Section	6	of	the	said	law,	consumers	are	also	given	a	green	energy	option	which	provides	end-users	the	option	to	choose	renewable	energy	resources	as their	source	of	energy.	Water	rights	are	given	by	the	National	Water	Resources	Board	under	the	Department	of	Environment	and	Natural	Resource	for	extraction	and discharge	of	water	used	in	the	operation	of	the	Masinloc	Plant.

Material	Regulatory	Actions.	Pending	with	the	ERC	is	the	decision	for	the	approval	of	additional	fees	for	AES	Masinloc	through	a	rate	adjustment	and	currency exchange	adjustment.	The	ERC	previously	ruled	that	NPC	shall	be	responsible	for	any	recovery/refund	for	both	these	recoveries	for	the	transition	period	prior	to	the closing	date	for	each	company	such	as	AES	Masinloc	which	obtained	facilities	in	the	privatization.	With	the	acquisition	of	the	Masinloc,	our	business	also	acquired	the right	to	supply	the	electricity	requirement	of	various	NPC	customers	pursuant	to	the	Transition	Supply	Contracts	entered	into	between	NPC	and	those	customers.	In	an Order	on	November	15,	2010,	the	ERC	approved	the	refund	for	currency	exchange	recovery	adjustment,	covering	the	test	period	up	to	June	2009.

Potential	or	Proposed	Regulations.	Section	72	of	the	EPIRA	requires	a	mandated	rate	reduction	from	NPC	rates.	With	the	assignment	of	the	Transition	Supply Contracts	to	successor	generating	companies,	such	as	AES	Masinloc,	NPC's	position	is	that	the	mandated	rate	reduction	shall	be	for	the	account	of	the	successor generating	companies.	AES	Masinloc	filed	a	petition	with	ERC	to	initiate	rule	making	and	clarify	the	MRR	implementation	in	light	of	the	ongoing	privatization	of	NPC plants.	In	its	decision,	the	ERC	ruled	in	favor	of	AES	Masinloc,	saying	that	the	EPIRA	mandated	rate	reduction	shall	be	implemented	by	the	successor	generating company	subject	to	the	execution	of	a	written	instrument	between	NPC	and	the	new	generator	specifically	containing	the	assumption	by	the	latter	of	such	obligation.	The ERC	ruled	in	favor	of	AES	Masinloc	since	there	was	no	such	written	instrument.	NPC	filed	a	petition	for	review	with	the	Court	asking	for	a	reversal	of	the	said	ERC decision.	The	case	is	pending	with	the	Court	of	Appeals.	If	AES	Masinloc	loses	this	matter	on	appeal,	it	may	be	subject	to	the	rate	reduction	described	above,	which could	have	a	material	impact	on	its	business	and	our	results	of	operations.

A	similar	mandated	rate	reduction	case	is	pending	with	the	ERC.	MERALCO	alleges	that	AES	Masinloc	failed	to	account	for	the	rate	reduction	in	MERALCO's favor	amounting	to	Php179,611,458.98	($4.1	million).	It	is	assumed	that	the	ERC	will	wait	for	the	decision	of	the	first	matter	described	in	the	preceding	paragraph	before ruling	on	the	MERALCO	case	since	the	latter	is	particularly	dependent	on	the	outcome	of	the	pending	petition	with	the	Court	of	Appeals.

# Environmental	and	Land	Use	Regulations

Overview.	The	Company	faces	certain	risks	and	uncertainties	related	to	numerous	environmental	laws	and	regulations,	including	existing	and	potential greenhouse	gas	("GHG")	legislation	or	regulations,	and	actual	or	potential	laws	and	regulations	pertaining	to	water	discharges,	waste	management	(including	disposal	of coal	combustion	byproducts),	and	certain	air	emissions,	such	as	SO ,	NO ,	particulate	matter,	mercury	and	other	hazardous	air	pollutants.	Such	risks	and	uncertainties could	result	in	increased	capital	expenditures	or	other	compliance	costs	which	could	have	a	material	adverse	effect	on	certain	of	our	United	States	or	international subsidiaries,	and	our	consolidated	results	of	operations.	For	further	information	about	these	risks,	see	Item	1A.—Risk	Factors,	"Our	businesses	are	subject	to	stringent environmental	laws	and	regulations,"	"Our	businesses	are	subject	to	enforcement	initiatives	from	environmental	regulatory	agencies,"	and	"Regulators,	politicians,	non- governmental	organizations	and	other	private	parties	have	expressed	concern	about	greenhouse	gas,	or	GHG,	emissions	and	the	potential	risks	associated	with	climate change	and	are	taking	actions	which	could	have	a	material	adverse	impact	on	our	consolidated	results	of	operations,	financial	condition	and	cash	flows"	in	this	Form 10-K.

Many	of	the	countries	in	which	the	Company	does	business	also	have	laws	and	regulations	relating	to	the	siting,	construction,	permitting,	ownership,	operation, modification,	repair	and	decommissioning	of,	and	power	sales	from	electric	power	generation	or	distribution	assets.	In	addition,	international	projects	funded	by	the International	Finance	Corporation,	the	private	sector	lending	arm	of	the	World	Bank,	or	many	other	international	lenders	are	subject	to	World	Bank	environmental standards	or	similar	standards,	which	tend	to	be	more	stringent	than	local	country	standards.	The	Company	often	has	used	advanced	environmental	technologies	in	order to	minimize	environmental	impacts,	including	circulating	fluidized	bed	("CFB")	coal	technologies,	flue	gas	desulphurization	technologies,	selective	catalytic	reduction technologies	and	advanced	gas	turbines.

Environmental	laws	and	regulations	affecting	electric	power	generation	and	distribution	facilities	are	complex,	change	frequently	and	have	become	more	stringent over	time.	The	Company	has	incurred	and	will	continue	to	incur	capital	costs	and	other	expenditures	to	comply	with	environmental	laws	and	regulations.	See	Item	7.— Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations—Capital	Expenditures	in	this	Form	10-K	for	more	detail.	If	these	regulations change	or	the	enforcement	of	these	regulations	becomes	more	rigorous,	the	Company	and	its	subsidiaries	may	be	required	to	make	significant	capital	or	other expenditures	to	comply.	There	can	be	no	assurance	that	the	businesses	operated	by	the	subsidiaries	of	the	Company	would	be	able	to	recover	any	of	these	compliance costs	from	their	counterparties	or	customers	such	that	the	Company's	consolidated	results	of	operations,	financial	condition	and	cash	flows	would	not	be	materially adversely	affected.

Various	licenses,	permits	and	approvals	are	required	for	our	operations.	Failure	to	comply	with	permits	or	approvals,	or	with	environmental	laws,	can	result	in fines,	penalties,	capital	expenditures,	interruptions	or	changes	to	our	operations.	Certain	subsidiaries	of	the	Company	are	subject	to	litigation	or	regulatory	action relating	to	environmental	permits	or	approvals.	See	Item	3.—Legal	Proceedings	in	this	Form	10-K	for	more	detail	with	respect	to	environmental	litigation	and	regulatory action,	including	a	Notice	of	Violation	("NOV")	issued	by	the	United	States	Environmental	Protection	Agency	against	IPL	concerning	new	source	review	and prevention	of	significant	deterioration	issues	under	the	United	States	Clean	Air	Act.

Greenhouse	Gas	Laws,	Protocols	and	Regulations.	In	2010,	the	Company's	subsidiaries	operated	electric	power	generation	businesses	which	had	total approximate	direct	CO 	emissions	of	77.2	million	metric	tonnes,	approximately	40	million	metric	tonnes	of	which	were	emitted	in	the	United	States	(both	figures ownership	adjusted).	The	Company	uses	CO 	emission	estimation	methodologies	supported	by	the	"The	Greenhouse	Gas	Protocol"	reporting	standard	on	GHG emissions.	For	existing	power	generation	plants,	CO 	emissions	are	either	obtained	directly	from	plant	continuous	emission	monitoring	systems	or	calculated	from	actual fuel	heat	inputs	and	fuel	type	CO 	emission	factors.	The	following	is	an	overview	of	both	the	regulations	and	laws	that	currently	apply	to	our	businesses	and	those	that may	be	imposed	over	the	next	few	years.	Such	regulations	and	laws	could	have	a	material	adverse	effect	on	the	electric	power	generation	and	distribution	businesses	of the	Company's	subsidiaries	and	on	the	Company's	consolidated	results	of	operations,	financial	condition	and	cash	flows.

# International

In	July	2003,	the	European	Community	"Directive	2003/87/EC	on	Greenhouse	Gas	Emission	Allowance	Trading"	was	created,	which	requires	member	states	to limit	emissions	of	CO 	from	large	industrial	sources	within	their	countries.	To	do	so,	member	states	are	required	to	implement	EC-approved	national	allocation	plans ("NAPs").	Under	the	NAPs,	member	states	are	responsible	for	allocating	limited	CO 	allowances	within	their	borders.	Directive	2003/87/EC	does	not	dictate	how	these allocations	are	to	be	made,	and	NAPs	that	have	been	submitted	thus	far	have	varied	in	their	allocation	methodologies.	For	these	and	other	reasons,	uncertainty	remains with	respect	to	the	implementation	of	the	European	Union	Emissions	Trading	System	("EU	ETS")	that	commenced	in	January	2005.	The	European	Union	has announced	that	it	intends	to	keep	the	EU	ETS	in	place	after	2012,	even	if	the	Kyoto	Protocol	is	not	extended	or	replaced	by	another	agreement.	The	Company's subsidiaries	operate	eight	electric	power	generation	facilities,	and	another	subsidiary	has	one	under	construction,	within	six	member	states	which	have	adopted	NAPs	to implement	Directive	2003/87/EC.	At	this	time,	the

Company	cannot	determine	fully	whether	achieving	and	maintaining	compliance	with	the	NAPs	to	which	its	subsidiaries	are	subject	will	have	a	material	impact	on	its consolidated	operations	or	results.	The	risk	and	benefit	associated	with	achieving	compliance	with	applicable	NAPs	at	several	facilities	of	the	Company's	subsidiaries are	not	the	responsibility	of	the	Company's	subsidiaries,	as	they	are	subject	to	contractual	provisions	that	transfer	the	costs	associated	with	compliance	to	contract counterparties.	However,	one	such	contract	counterparty,	GDF-Suez,	is	currently	disputing	these	provisions	with	AES	Energia	Cartagena	S.R.L.	The	matter	has	been submitted	to	arbitration	and	the	parties	are	currently	awaiting	a	decision.	See	Item	3.—Legal	Proceedings	in	this	Form	10-K	for	more	detail	regarding	this	dispute.	In connection	with	this	dispute	or	any	similar	dispute	that	might	arise	with	other	contract	counterparties,	there	can	be	no	assurance	that	the	Company	and/or	the	relevant subsidiary	would	prevail,	or	that	the	failure	to	prevail	in	any	such	dispute	will	not	have	a	material	adverse	effect	on	the	Company	and	its	financial	condition	or consolidated	results	of	operations.	Certain	of	the	Company's	subsidiaries	will	bear	some	or	all	of	the	risk	and	benefit	associated	with	compliance	with	applicable	NAPs at	certain	facilities.	Based	upon	anticipated	operations,	CO 	emission	allowance	allocations,	and	the	costs	to	acquire	offsets	and	emission	allowances	for	compliance purposes,	the	Company	has	not	to-date	incurred	material	costs	to	comply	with	Directive	2003/87/EC	and	applicable	NAPs;	however,	there	can	be	no	guarantees	that compliance	will	not	have	a	material	adverse	effect	on	our	business	in	future	periods.

Legislative	efforts	at	the	EU	have	produced	a	"Climate	Change	Package."	This	package	consists	of	three	directives—Carbon	Capture	&	Storage,	an	amended	EU ETS	and	a	revised	Renewables	Directive.	The	amended	EU	ETS	and	Renewable	Directives	have	now	been	approved	by	the	EU	Parliament	and	they	will	enter	into	force with	respect	to	individual	EU	member	states	upon	adoption	by	each	such	country	of	implementing	legislation	or	regulations.	The	main	objectives	of	the	Climate	Change Package	are	usually	referred	to	as	the	"20-20-20"	goals:

•	 A	20%	reduction	in	EU	GHG	emissions	by	2020,	as	compared	with	1990	levels,	or	30%	if	other	developed	nations	agree	to	take	similar	action	by	2020;

•The	EU	ETS	caps	on	emissions	allowances	is	designed	to	deliver	21%	GHG	reduction	by	2020	compared	to	2005	levels,	with	distribution	of	allowances skewed	in	favor	of	member	states	with	lower	GDP,	and	with	the	potential	for	auctioning	to	be	phased	in	for	affected	facilities;

•20%	increase	in	energy	efficiency;	and

•	 Minimum	compulsory	10%	target	for	renewable	energy	by	2020.

Progress	in	implementation	of	the	directives	referred	to	above	varies	from	member	state	to	member	state,	and	many	states	have	not	yet	adopted	any	implementing legislation	or	regulations.	AES	generation	businesses	in	each	member	state	will	be	required	to	comply	with	the	relevant	measures	taken	to	implement	the	directives.

On	February	16,	2005,	the	Kyoto	Protocol	became	effective.	The	Kyoto	Protocol	requires	the	industrialized	countries	that	have	ratified	it	to	significantly	reduce their	GHG	emissions,	including	CO .	The	vast	majority	of	developing	countries	which	have	ratified	the	Kyoto	Protocol	have	no	GHG	reduction	requirements,	including many	of	the	countries	in	which	the	Company's	subsidiaries	operate.	Of	the	28	countries	in	which	the	Company's	subsidiaries	currently	operate,	all	but	one—the	United States	(including	Puerto	Rico)—have	ratified	the	Kyoto	Protocol.	To	date,	compliance	with	the	Kyoto	Protocol	and	EU	ETS	has	not	had	a	material	adverse	effect	on	the Company's	consolidated	results	of	operations,	financial	condition	and	cash	flows.	In	December	2010,	the	annual	United	Nations	conference	of	the	parties	to	the	Kyoto Protocol	(called	COP	16)	was	held	in	Cancún,	Mexico	to	focus	on	establishing	an	international	agreement	or	framework	to	succeed	the	Kyoto	Protocol	when	it	expires	at the	end	of	2012.	COP	16	did	not	result	in	any	legally	binding	successor	agreement	to	the	Kyoto	Protocol,	but	countries	did	agree	to	continue	to	work	toward	a	successor international	agreement	on	GHG	emissions	reductions	by	the	next	annual	conference.	Countries	also	agreed	to	report	their	annual	GHG	emissions	and	many	countries have	submitted	non-binding	emission	targets.	The	United	States	reaffirmed	its	non-binding	target	of	reducing	GHG	emissions	by	17%	from	2005	levels	by	2020.	At present,	the	Company	cannot	predict	whether	compliance	with	the	Kyoto	Protocol	or	any	successor	agreements	will	have	a	material	adverse	effect	on	the	Company's consolidated	results	of	operations,	financial	condition	and	cash	flows	in	future	periods.

Even	though	it	has	been	announced	that	the	EU	ETS	will	remain	in	place	even	if	the	Kyoto	Protocol	expires	at	the	end	of	2012	without	any	successor	agreement or	commitment	on	GHG	emissions	reductions,	there	remains	significant	uncertainty	with	respect	to	the	implementation	of	NAPs	post-2012.	The	EU	has	indicated	that	a portion	of	the	emission	allowances	given	to	member	states	will	need	to	be	auctioned	under	the	NAPs	and	the	Company	cannot	predict	with	any	certainty	if	compliance with	such	programs	will	have	a	material	adverse	effect	on	its	consolidated	financial	condition	or	results	of	operations.

Countries	in	Latin	America,	Asia	and	Africa	in	which	subsidiaries	of	the	Company	operate	may	also	choose	to	adopt	regulations	that	directly	or	indirectly	regulate GHG	emissions	from	power	plants.	For	a	discussion	of	regulations	in	individual	countries	where	our	subsidiaries	operate,	see	Item	1.	Business—Regulatory	Matters	in this	Form	10-K.	Although	the	Company	does	not	currently	believe	that	the	laws	and	regulations	pertaining	to	GHG	emissions	that	have	been	adopted	to	date	in	countries in	Latin	America,	Asia	and	Africa	in	which	subsidiaries	of	the	Company	operate	will	have	a	material	impact	on	the	Company,	the	Company	cannot	predict	with	any certainty	if	future	laws	and	regulations	in	these	countries	regarding	CO 	emissions	will	have	a	material	adverse	effect	on	the	Company's	consolidated	financial	condition or	results	of	operations.

# United	States—Federal	Legislation	and	Regulation

Currently,	in	the	United	States	there	is	no	Federal	legislation	establishing	mandatory	GHG	emissions	reduction	programs	(including	CO)	affecting	the	electric power	generation	facilities	of	the	Company's	subsidiaries.	There	are	numerous	state	programs	regulating	GHG	emissions	from	electric	power	generation	facilities	and there	is	a	possibility	that	federal	GHG	legislation	will	be	enacted	within	the	next	several	years.	Further,	the	United	States	Environmental	Protection	Agency	("EPA")	has adopted	regulations	pertaining	to	GHG	emissions	and	has	announced	its	intention	to	propose	new	regulations	for	electric	generating	units	under	Section	111	of	the United	States	Clean	Air	Act	("CAA").

Potential	United	States	Federal	GHG	Legislation.	Federal	legislation	passed	the	United	States	House	of	Representatives	in	2009	that,	if	adopted,	would	impose	a nationwide	cap-and-trade	program	to	reduce	GHG	emissions.	In	the	United	States	Senate,	several	different	draft	bills	pertaining	to	GHG	legislation	have	been considered	at	various	times	since	then,	including	comprehensive	GHG	legislation	similar	to	the	legislation	that	passed	the	United	States	House	of	Representatives	and more	limited	legislation	focusing	only	on	the	utility	and	electric	generation	industry.	It	is	uncertain	whether	any	such	legislation	or	new	legislation	pertaining	to	GHG emissions	will	be	voted	on	or	passed	by	the	Senate.	If	any	legislation	is	passed	by	the	Senate,	it	is	uncertain	whether	such	legislation	will	be	reconciled	with	the	House	of Representatives'	legislation	and	ultimately	enacted	into	law.	However,	if	any	such	legislation	is	enacted,	the	impact	could	be	material	to	the	Company.

EPA	GHG	Regulation.	The	EPA	promulgated	regulations	governing	GHG	emissions	from	automobiles	under	the	CAA.	The	effect	of	the	EPA's	regulation	of GHG	emissions	from	mobile	sources	is	that	certain	provisions	of	the	CAA	will	also	apply	to	GHG	emissions	from	existing	stationary	sources,	including	many	United States	power	plants.	Beginning	on	January	2,	2011,	construction	of	new	stationary	sources	and	modifications	to	existing	stationary	sources	that	result	in	increased	GHG emissions	became	subject	to	permitting	requirements	under	the	prevention	of	significant	deterioration	("PSD")	program	of	the	CAA.	The	PSD	program,	as	currently applicable	to	GHG	emissions,	requires	sources	that	emit	above	a	certain	threshold	of	GHGs	to	obtain	PSD	permits	prior	to	commencement	of	new	construction	or modifications	to	existing	facilities.	In	addition,	major	sources	of	GHG	emissions	may	be	required	to	amend,	or	obtain	new,	Title	V	air	permits	under	the	CAA	to	reflect any	new	applicable	GHG	emissions	requirements	for	new	construction	or	for	modifications	to	existing	facilities.

The	EPA	promulgated	a	final	rule	on	June	3,	2010,	(the	"Tailoring	Rule")	that	sets	thresholds	for	GHG	emissions	that	would	trigger	PSD	permitting	requirements. The	Tailoring	Rule,	which	became	effective	in	January	of	2011,	provides	that	sources	already	subject	to	PSD	permitting	requirements	need	to	install	Best	Available Control	Technology	("BACT")	for	greenhouse	gases	if	a	proposed	modification	would	result	in	the

increase	of	more	than	75,000	tons	per	year	of	GHG	emissions.	Also,	under	the	Tailoring	Rule,	commencing	in	July	of	2011,	any	new	sources	of	GHG	emissions	that would	emit	over	100,000	tons	per	year	of	GHG	emissions,	in	addition	to	any	modification	that	would	result	in	GHG	emissions	exceeding	75,000	tons	per	year,	would require	PSD	review	and	be	subject	to	related	permitting	requirements.	The	EPA	anticipates	that	it	will	adjust	downward	the	permitting	thresholds	of	100,000	tons	and 75,000	tons	for	new	sources	and	modifications,	respectively,	in	future	rulemaking	actions.	The	Tailoring	Rule	substantially	reduces	the	number	of	sources	subject	to	PSD requirements	for	GHG	emissions	and	the	number	of	sources	required	to	obtain	Title	V	air	permits,	although	new	thermal	power	plants	may	still	be	subject	to	PSD	and Title	V	requirements	because	annual	GHG	emissions	from	such	plants	typically	far	exceed	the	100,000	ton	threshold	noted	above.	The	75,000	ton	threshold	for increased	GHG	emissions	from	modifications	to	existing	sources	may	reduce	the	likelihood	that	future	modifications	to	plants	owned	by	some	of	our	United	States subsidiaries	would	trigger	PSD	requirements,	although	some	projects	that	would	expand	capacity	or	electric	output	are	likely	to	exceed	this	threshold,	and	in	any	such cases	the	capital	expenditures	necessary	to	comply	with	the	PSD	requirements	could	be	significant.

In	December	2010,	the	EPA	entered	into	a	settlement	agreement	with	several	states	and	environmental	groups	to	resolve	a	petition	for	review	challenging	EPA's new	source	performance	standards	("NSPS")	rulemaking	for	electric	utility	steam	generating	units	("EUSGUs")	based	on	the	NSPS's	failure	to	address	GHG	emissions. Under	the	settlement	agreement,	the	EPA	has	committed	to	propose	GHG	emissions	standards	for	EUSGUs	by	July	26,	2011	and	to	finalize	GHG	emissions	standards for	EUSGUs	by	May	26,	2012.	The	NSPS	will	establish	GHG	emission	standards	for	newly	constructed	and	reconstructed	EUSGUs.	The	NSPS	also	will	establish guidelines	regarding	the	best	system	for	achieving	further	GHG	emissions	reductions	from	EUSGUs	and,	based	on	such	guidelines,	individual	states	will	be	required	to submit	a	plan	to	the	EPA	to	establish	GHG	emission	standards	for	existing	EUSGUs	within	their	state.	It	is	impossible	to	estimate	the	impact	and	compliance	cost associated	with	any	future	NSPS	applicable	to	EUSGUs	until	such	regulations	are	finalized.	However,	the	compliance	costs	could	have	a	material	and	adverse	impact	on our	consolidated	financial	condition	or	results	of	operations.

# United	States—State	Legislation	and	Regulation

Regional	Greenhouse	Gas	Initiative.	The	primary	regulation	of	GHG	emissions	affecting	the	United	States	plants	of	the	Company's	subsidiaries	has	been	through the	Regional	Greenhouse	Gas	Initiative	("RGGI").	Under	RGGI,	ten	Northeastern	States	have	coordinated	to	establish	rules	that	require	reductions	in	CO 	emissions from	power	plant	operations	within	those	states	through	a	cap-and-trade	program.	States	participating	in	RGGI	in	which	our	subsidiaries	have	generating	facilities include	Connecticut,	Maryland,	New	York	and	New	Jersey.	Under	RGGI,	power	plants	must	acquire	one	carbon	allowance	through	auction	or	in	the	emission	trading markets	for	each	ton	of	CO 	emitted.	We	have	estimated	the	costs	to	the	Company	of	compliance	with	RGGI	could	be	approximately	$15	million	for	2011.	The	initial three-year	compliance	period	for	RGGI	expires	at	the	end	of	2011	and	revisions	to	RGGI	for	2012	and	thereafter	are	currently	under	discussion.	While	these	estimated compliance	costs	are	not	material	to	the	Company,	changes	in	the	regulations	or	price	of	allowances	under	RGGI	could	have	a	material	and	adverse	impact	on	our operations	and	financial	performance.

The	Company's	Eastern	Energy	business	is	located	in	New	York.	Under	the	New	York	RGGI	rule,	each	budgeted	source	of	CO	emissions	is	required	to surrender	one	CO 	allowance	for	each	metric	tonne	of	CO 	emitted	during	a	three-year	compliance	period.	All	fossil	fuel	powered	generating	facilities	in	New	York	that have	a	generating	capacity	of	25	or	more	MW	are	subject	to	the	rule.	Eastern	Energy	secures	its	allowance	requirements	from	the	RGGI	allowance	auction	or	through the	secondary	market.

The	Company's	Thames	business	is	located	in	Connecticut.	The	state	of	Connecticut	passed	legislation,	effective	July	1,	2007,	which	requires	that	the Connecticut	Department	of	Environmental	Protection	develop	necessary	regulations	to	implement	RGGI.	The	regulations	adopted	to	implement	RGGI	include	an auction	of	CO 	emission	allowances	except	for	several	set-aside	accounts.	AES	Thames	is	eligible	for	a	set-aside	for	the	first	compliance	period,	2009-2011,	which allows	CO 	allowances	to	be	purchased	at	$2	per	allowance	in	2009,

and	$2	per	allowance	plus	a	consumer	price	indexing	in	years	2010	and	2011.	During	2010,	a	similar	$2	per	allowance	provision	for	the	second	compliance	period, 2012-2014,	was	enacted	by	the	Connecticut	legislature	for	contracted	facilities.

The	Company's	Warrior	Run	business	is	located	in	Maryland.	In	April	2006,	the	Maryland	General	Assembly	passed	the	Maryland	Healthy	Air	Act	which, among	other	things,	required	the	State	of	Maryland	to	join	RGGI.	The	Maryland	Department	of	Environment	("MDE")	adopted	regulations	that	require	100%	of	the allowances	the	State	receives	to	be	auctioned	except	for	several	small	allowance	set-aside	accounts.	The	MDE	regulations	include	a	safety	valve	to	control	the	economic impact	of	the	CO 	cap-and-trade	program.	If	the	auction	closing	price	reaches	$7,	up	to	50%	of	a	year's	allowances	will	be	reserved	for	purchase	by	electric	power generation	facilities	located	within	Maryland	at	$7	per	allowance,	regardless	of	auction	prices.	Warrior	Run	continues	to	secure	its	allowance	requirements	through	the RGGI	allowance	auction.

The	Company's	Red	Oak	business	is	located	in	New	Jersey.	The	State	of	New	Jersey	adopted	the	Global	Warming	Response	Act	in	July	2007,	which	established goals	for	the	reduction	of	GHG	emissions	in	the	State.	In	furtherance	of	these	goals,	in	January	2008,	additional	state	legislation	authorized	the	New	Jersey	Department of	Environmental	Protection	("NJDEP")	to	develop	and	adopt	RGGI	regulations	and	the	NJDEP	RGGI	regulations	became	effective	in	2008.	Under	the	terms	of	Red Oak's	tolling	agreement,	RGGI	CO 	compliance	costs	are	passed	through	to	its	power	offtaker.

In	2010,	of	the	approximately	40	million	metric	tonnes	of	CO	emitted	in	the	United	States	by	the	businesses	operated	by	our	subsidiaries	(ownership	adjusted), approximately	11.3	million	metric	tonnes	were	emitted	in	states	participating	in	RGGI.	Over	the	past	three	years,	such	emissions	have	averaged	approximately 10.9	million	metric	tonnes.	While	CO 	emissions	from	businesses	operated	by	subsidiaries	of	the	Company	are	calculated	globally	in	metric	tonnes,	RGGI	allowances are	denominated	in	short	tons.	(1	metric	tonne	equals	2,200	pounds	and	1	short	ton	equals	2,000	pounds.)	For	forecasting	purposes,	the	Company	has	modeled	the impact	of	CO 	compliance	based	on	a	three-year	average	of	CO	emissions	for	its	businesses	that	are	subject	to	RGGI	and	that	may	not	be	able	to	pass	through compliance	costs.	The	model	includes	a	conversion	from	metric	tonnes	to	short	tons,	as	well	as	the	impact	of	some	market	recovery	by	merchant	plants	and	contractual and	regulatory	provisions.	The	model	also	utilizes	a	price	of	$1.86	per	allowance	under	RGGI.	The	source	of	this	allowance	price	estimate	was	the	clearing	price	in	the most	recent	RGGI	allowance	auction	held	in	December	2010.	Based	on	these	assumptions,	the	Company	estimates	that	the	RGGI	compliance	costs	could	be approximately	$15	million	for	2011,	which	is	the	last	year	of	the	first	RGGI	compliance	period.	Given	the	fact	that	the	assumptions	utilized	in	the	model	may	prove	to be	incorrect,	there	is	a	significant	risk	that	our	actual	compliance	costs	under	RGGI	will	differ	from	our	estimates	by	a	material	amount	and	that	our	model	could underestimate	our	costs	of	compliance.

California.	The	Company's	Southland	and	Placerita	businesses	are	located	in	California.	On	September	27,	2006,	the	Governor	of	California	signed	the	Global Warming	Solutions	Act	of	2006,	also	called	Assembly	Bill	32	("A.B.	32").	A.B.	32	directs	the	California	Air	Resources	Board	("CARB")	to	promulgate	regulations	that will	require	the	reduction	of	CO 	and	other	GHG	emissions	to	1990	levels	by	2020.	On	October	29,	2010,	CARB	released	the	design	of	its	GHG	cap-and-trade	program and	on	December	16,	2010	voted	9-1	to	approve	the	plan.	The	plan	begins	with	Phase	I	in	2012,	and	initially	covers	emissions	from	electricity	generating	facilities,	large industrial	sources	with	annual	emissions	greater	than	25,000	tons,	and	imported	electricity.	Emitters	will	be	required	to	hold	enough	allowances	to	match	their	emissions and	can	comply	by	reducing	their	emissions	or	by	purchasing	tradable	allowances	from	other	emitters	or	at	state-run	auctions.	Companies	that	reduce	their	emissions below	the	allowances	they	hold	have	the	opportunity	to	sell	unused	allowances.	Initially,	retail	utilities	will	be	issued	free	allowances	and	merchant	facilities	will	be required	to	bid	for	allowances	at	auctions.	There	is	a	floor	price	of	$10	for	all	allowances	purchased	at	auctions.	The	number	of	free	allowances	will	decline	in	Phase	II and	will	further	decline	when	Phase	III	begins	in	2018.	CARB	will	continue	to	refine	certain	elements	of	the	cap-and-trade	program	and	further	define	important provisions,	such	as	allocations	in	early	2011,	through	CARB's	"15	day	notice"	procedure,	whereby	changes	to	adopted	regulations	are	recommended	by	CARB	staff 67

and	subject	to	a	15-day	public	comment	period.	The	Company	believes	that	any	compliance	costs	arising	from	A.B.	32	for	the	thermal	power	plants	of	its	subsidiaries operating	in	California	will	be	borne	by	the	power	offtaker	under	the	terms	of	existing	tolling	agreements	with	the	offtaker	and	under	the	terms	of	A.B.	32.	However, after	the	expiration	of	such	tolling	agreements,	if	the	Company's	subsidiaries	were	to	sell	power	on	a	merchant	basis	then	such	compliance	costs	could	be	borne	by	the subsidiaries.

Western	Climate	Initiative	(WCI).	In	February	2007,	the	governors	of	the	Western	United	States	states	(Arizona,	New	Mexico,	California,	Washington	and Oregon)	established	the	WCI.	The	WCI	has	since	been	joined	by	two	other	states	(Montana	and	Utah)	and	four	Canadian	provinces	(British	Columbia,	Manitoba, Ontario,	and	Quebec).	Participating	states	and	provinces	have	agreed	to	cut	GHG	emissions	to	15%	below	2005	levels	by	2020,	and	they	are	considering	the implementation	of	a	cap-and-trade	program	for	the	electricity	industry	to	achieve	this	reduction.	On	September	23,	2008,	the	WCI	issued	its	design	recommendations	for a	cap-and-trade	program	that	would	apply	to	in-state	electricity	generators	and	the	first	jurisdictional	deliverer	of	electricity	into	a	WCI	partner	state.	The	WCI	issued draft	guidance	on	the	creation	of	cap-and-trade	allowance	budgets	on	November	29,	2009.	The	draft	guidance	contemplates	an	eventual	cap-and-trade	program	with flexible	mechanisms,	such	as	allowance	banking	and	offsets.	The	final	regulatory	design	of	this	program	is	not	yet	known.

Midwestern	Greenhouse	Gas	Reduction	Accord	(MGGRA).	The	Company	owns	the	utility	IPL,	which	is	located	in	Indiana.	On	November	15,	2007,	six Midwestern	state	governors	(including	the	Governor	of	Indiana)	and	the	premier	of	Manitoba	signed	the	Midwestern	Greenhouse	Gas	Reduction	Accord	("MGGRA"), committing	the	participating	states	and	province	to	reduce	GHG	emissions	through	the	implementation	of	a	cap-and-trade	program.	Three	states	(including	Indiana)	and the	province	of	Ontario	have	signed	as	observers.	In	May	of	2010,	the	MGGRA	Advisory	Group	finalized	a	set	of	recommendations	for	the	establishment	of	targets	for emissions	reductions	in	the	region	and	for	the	design	of	a	regional	cap-and-trade	program.	These	include	a	recommended	reduction	in	GHG	emissions	of	20%	below 2005	emission	levels	by	2025.	The	recommendations	are	from	the	advisory	group	only,	and	have	not	been	endorsed	or	approved	by	individual	governors,	including	the Governor	of	Indiana.	If	Indiana	were	to	implement	the	recommended	reduction	targets,	the	impact	on	the	Company's	consolidated	results	of	operations,	financial condition,	and	cash	flows	could	be	material.

Hawaii.	The	Company	owns	a	power	generation	facility	in	Hawaii.	On	June	30,	2007,	the	Governor	of	Hawaii	signed	Act	234	which	sets	a	goal	of	reducing	GHG emissions	to	at	or	below	1990	levels	by	January	1,	2020.	Act	234	also	established	the	Greenhouse	Gas	Emissions	Reduction	Task	Force,	which	is	tasked	with developing	measures	to	meet	Hawaii's	GHG	emissions	reduction	goal.	The	Task	Force	filed	a	report	to	the	Hawaii	Legislature	on	December	30,	2009,	strongly supporting	the	Hawaii	Clean	Energy	Initiative,	which	calls	for	additional	renewable	energy	development,	increased	energy	efficiency,	and	incorporates	already-enacted renewable	portfolio	standards.	The	Task	Force	also	evaluated	other	mechanisms	and	concluded	that	a	state-level	cap-and-trade	program	is	inappropriate	due	to	the	small size	of	Hawaii's	economy.

At	this	time,	other	than	the	estimated	impact	of	CO	compliance	noted	above	for	certain	of	its	businesses	that	are	subject	to	RGGI,	the	Company	has	not	estimated the	costs	of	compliance	with	other	potential	United	States	federal,	state	or	regional	CO 	emissions	reduction	legislation	or	initiatives,	such	as	A.B.	32,	WCI,	MGGRA and	potential	Hawaii	regulations,	due	to	the	fact	that	most	of	these	proposals	are	in	the	early	stages	of	development	and	any	final	regulations	or	laws,	if	adopted,	could vary	drastically	from	current	proposals.	Although	complete	specific	implementation	measures	for	any	federal	regulations,	A.B.	32,	WCI,	MGGRA	and	the	Hawaiian regulations	have	yet	to	be	finalized,	if	these	GHG-related	initiatives	are	finalized	they	may	affect	a	number	of	the	Company's	United	States	subsidiaries	unless	they	are preempted	by	federal	GHG	legislation.	Any	federal,	state	or	regional	legislation	or	regulations	adopted	in	the	United	States	that	would	require	the	reduction	of	GHG emissions	could	have	a	material	adverse	effect	on	the	Company's	consolidated	results	of	operations,	financial	condition	and	cash	flows.

The	possible	impact	of	any	future	federal	GHG	legislation	or	regulations	or	any	regional	or	state	proposal	will	depend	on	various	factors,	including	but	not	limited to:

•the	geographic	scope	of	legislation	and/or	regulation	(e.g.,	federal,	regional,	state),	which	entities	are	subject	to	the	legislation	and/or	regulation (e.g.,	electricity	generators,	load-serving	entities,	electricity	deliverers,	etc.),	the	enactment	date	of	the	legislation	and/or	regulation	and	the	compliance deadlines	set	forth	therein;

•the	level	of	reductions	of	CO 	being	sought	by	the	regulation	and/or	legislation	(e.g.,	10%,	20%,	50%,	etc.)	and	the	year	selected	as	a	baseline	for determining	the	amount	or	percentage	of	mandated	CO 	reduction	(e.g.,	10%	reduction	from	1990	CO	emission	levels,	20%	reduction	from	2000	CO^2 emission	levels,	etc.);

•the	legislative	and/or	regulatory	structure	(e.g.,	a	CO	cap-and-trade	program,	a	carbon	tax,	CO	emission	limits,	etc.);

•in	any	cap-and-trade	program,	the	mechanism	used	to	determine	the	price	of	emission	allowances	or	offsets	to	be	auctioned	by	designated	governmental authorities	or	representatives;

•the	price	of	offsets	and	emission	allowances	in	the	secondary	market,	including	any	price	floors	or	price	caps	on	the	costs	of	offsets	and	emission allowances;

•the	operation	of	and	emissions	from	regulated	units;

•the	permissibility	of	using	offsets	to	meet	reduction	requirements	and	the	requirements	of	such	offsets	(e.g.,	type	of	offset	projects	allowed,	the	amount	of offsets	that	can	be	used	for	compliance	purposes,	any	geographic	limitations	regarding	the	origin	or	location	of	creditable	offset	projects),	as	well	as	the methods	required	to	determine	whether	the	offsets	have	resulted	in	reductions	in	GHG	emissions	and	that	those	reductions	are	permanent	(i.e.,	the verification	method);

•	 whether	the	use	of	proceeds	of	any	auction	conducted	by	responsible	governmental	authorities	is	reinvested	in	developing	new	energy	technologies,	is	used to	offset	any	cost	impact	on	certain	energy	consumers	or	is	used	to	address	issues	unrelated	to	power;

•how	the	price	of	electricity	is	determined	at	the	affected	businesses,	including	whether	the	price	includes	any	costs	resulting	from	any	new	CO	legislation and	the	potential	to	transfer	compliance	costs	pursuant	to	legislation,	market	or	contract,	to	other	parties;

•any	impact	on	fuel	demand	and	volatility	that	may	affect	the	market	clearing	price	for	power;

•the	effects	of	any	legislation	or	regulation	on	the	operation	of	power	generation	facilities	that	may	in	turn	affect	reliability;

•the	availability	and	cost	of	carbon	control	technology;

•the	extent	to	which	existing	contractual	arrangements	transfer	compliance	costs	to	power	offtakers	or	other	contractual	counterparties	of	our	subsidiaries;

•	 whether	legislation	regulating	GHG	emissions	will	preclude	EPA	from	regulating	GHG	emissions	under	the	Clean	Air	Act	or	preempt	private	nuisance suits	or	other	litigation	by	third	parties;	and

•any	opportunities	to	change	the	use	of	fuel	at	the	generation	facilities	of	our	subsidiaries	or	opportunities	to	increase	efficiency.

Other	United	States	Air	Emissions	Regulations	and	Legislation.	In	the	United	States	the	CAA	and	various	state	laws	and	regulations	regulate	emissions	of	air pollutants,	including	SO ,	NO ,	particulate	matter	("PM"),	mercury	and	other	hazardous	air	pollutants	("HAPs").	The	applicable	rules	and	the	steps	taken	by	the Company	to	comply	with	the	rules	are	discussed	in	further	detail	below.

The	EPA	promulgated	the	"Clean	Air	Interstate	Rule"	("CAIR")	on	March	10,	2005,	which	required	allowance	surrender	for	SO	and	NO X	emissions	from existing	power	plants	located	in	28	eastern	states	and	the	District	of	Columbia.	CAIR	was	subsequently	challenged	in	federal	court,	and	on	July	11,	2008,	the	United States	Court	of	Appeals	for	the	D.C.	Circuit	issued	an	opinion	striking	down	much	of	CAIR	and	remanding	it	to	the	EPA.

In	response	to	the	D.C.	Circuit's	opinion,	on	July	6,	2010,	the	EPA	issued	a	new	proposed	rule	(the	"Clean	Air	Transport	Rule")	to	replace	CAIR.	The	final	Clean Air	Transport	Rule	("Transport	Rule")	is	scheduled	to	be	issued	by	July	2011.	The	Transport	Rule	would	require	significant	additional	reductions	in	SO 	and	NO^X emissions	in	31	states	and	the	District	of	Columbia	starting	in	2012,	including	several	states	where	subsidiaries	of	the	Company	conduct	business.

The	Transport	Rule	contemplates	three	possible	options	for	reducing	SO 	and	NO X	emissions	in	the	designated	states.	The	EPA's	preferred	option	contemplates	a set	limit	or	budget	on	SO 	and	NO X	emissions	for	each	of	the	states,	with	limited	interstate	trading	of	emissions	allowances	and	unlimited	intrastate	trading	of	SO	and NO X	emissions	allowances.	Affected	power	plants	would	receive	emissions	allowances	based	on	the	applicable	state	emissions	budgets.	The	EPA's	second	option	under the	Transport	Rule	would	establish	emission	budgets	for	each	state,	but	only	allow	intrastate	trading	of	emissions	allowances.	The	final	option	would	set	emission	rate limitations	for	each	power	plant,	but	would	allow	for	some	intrastate	averaging	of	emission	rates.	Under	any	of	the	proposed	options,	additional	pollution	control technology	may	be	required	by	some	of	our	subsidiaries,	and	the	cost	of	implementing	any	such	technology	could	affect	the	financial	condition	or	results	of	operations of	these	subsidiaries	or	the	parent	company.	The	EPA	has	received	public	comments	on	the	Transport	Rule,	and	such	public	comments	will	be	considered	by	the	EPA prior	to	promulgating	a	final	rule.

On	December	23,	2009,	the	New	York	State	Department	of	Environmental	Conservation	("NYSDEC")	published	and	enacted	a	rulemaking	requiring	the application	of	Reasonably	Available	Control	Technology	("RACT")	for	reductions	in	NO X	emissions	from	electric	utility	and	industrial	boilers,	combustion	turbines	and internal	combustion	engines.	The	regulations	establish	that	sources	subject	to	the	new	emission	limits	must	provide	a	compliance	plan	by	January	1,	2012	and demonstrate	compliance	by	July	1,	2014.

As	a	result	of	prior	EPA	determinations	and	a	D.C.	Circuit	Court	ruling,	the	EPA	is	obligated	under	Section	112	of	the	CAA	to	develop	a	rule	requiring	pollution controls	for	hazardous	air	pollutants,	including	mercury,	hydrogen	chloride,	hydrogen	fluoride,	and	nickel	species	from	coal	and	oil-fired	power	plants.	The	EPA	has entered	into	a	consent	decree	under	which	it	is	obligated	to	propose	the	rule	by	March	2011	and	to	finalize	the	rule	by	November	2011.	In	connection	with	such	rule,	the CAA	requires	the	EPA	to	establish	maximum	achievable	control	technology	("MACT")	standards	for	each	pollutant	regulated	under	the	rule.	MACT	is	defined	as	the emission	limitation	achieved	by	the	"best	performing	12%"	of	sources	in	the	source	category.	While	it	is	impossible	to	project	what	emission	rate	levels	the	EPA	may propose	as	MACT,	the	rule	may	require	all	coal-fired	power	plants	to	install	acid	gas	scrubbers	(wet	or	dry	flue	gas	desulfurization	technology)	and/or	some	other	type of	mercury	control	technology,	such	as	sorbent	injection.	Most	of	the	Company's	United	States	coal-fired	plants	have	acid	gas	scrubbers	or	comparable	control technologies,	but	it	is	possible	that	EPA	regulations	will	require	improvements	to	such	control	technologies	at	some	of	our	plants.	Under	the	CAA,	compliance	is required	within	three	years	of	the	effective	date	of	the	rule;	however,	the	compliance	period	for	a	unit,	or	group	of	units,	may	be	extended	by	state	permitting	authorities (for	one	additional	year)	or	through	a	determination	by	the	President	(for	up	to	two	additional	years).	At	this	time,	the	Company	cannot	predict	whether	new	regulations for	hazardous	air	pollutants	will	be	promulgated	or,	if	promulgated,	the	extent	of	such	regulations,	but	the	cost	of	compliance	with	any	such	regulations	could	be material.

In	July	1999,	the	EPA	published	the	"Regional	Haze	Rule"	to	reduce	haze	and	protect	visibility	in	designated	federal	areas.	On	June	15,	2005,	the	EPA	proposed amendments	to	the	Regional	Haze	Rule	that,	among	other	things,	set	guidelines	for	determining	when	to	require	the	installation	of	"best	available	retrofit	technology" ("BART")	at	older	plants.	The	amendment	to	the	Regional	Haze	Rule	required	states	to	consider	the

visibility	impacts	of	the	haze	produced	by	an	individual	facility,	in	addition	to	other	factors,	when	determining	whether	that	facility	must	install	potentially	costly emissions	controls.	States	were	required	to	submit	their	regional	haze	state	implementation	plans	("SIPs")	to	the	EPA	by	December	2007,	but	only	13	states	met	this deadline.	The	EPA	has	yet	to	approve	any	state's	Regional	Haze	state	implementation	plan.	The	statute	requires	compliance	within	five	years	after	the	EPA	approves	the relevant	SIP,	although	individual	states	may	impose	more	stringent	compliance	schedules.

Other	International	Air	Emissions	Regulations	and	Legislation.	In	Europe,	the	Company	is,	and	will	continue	to	be,	required	to	reduce	air	emissions	from	our facilities	to	comply	with	applicable	EC	Directives,	including	Directive	2001/80/EC	on	the	limitation	of	emissions	of	certain	pollutants	into	the	air	from	large	combustion plants	(the	"LCPD"),	which	sets	emission	limit	values	for	NO X,	SO ,	and	particulate	matter	for	large-scale	industrial	combustion	plants	for	all	member	states.	Until	June 2004,	existing	coal	plants	could	"opt-in"	or	"opt-out"	of	the	LCPD	emissions	standards.	Those	plants	that	opted	out	will	be	required	to	cease	all	operations	by	2015	and may	not	operate	for	more	than	20,000	hours	after	2008.	Those	that	opted-in,	like	the	Company's	Kilroot	facility	in	the	United	Kingdom,	must	invest	in	abatement technology	to	achieve	specific	SO 	reductions.	Kilroot	installed	a	new	flue	gas	desulphurization	system	in	the	second	quarter	of	2009	in	order	to	satisfy	SO	reduction requirements.	The	Company's	other	coal	plants	in	Europe	are	either	exempt	from	the	Directive	due	to	their	size	or	have	opted-in	but	will	not	require	any	additional abatement	technology	to	comply	with	the	LCPD.

In	November	2010,	the	Council	of	the	EU	approved	a	revised	directive	on	industrial	emissions	so	as	to	reduce	emissions	of	pollutants	that	are	alleged	to	be harmful	to	the	environment	and	associated	with	cancer,	asthma	and	acid	rain.	The	industrial	emissions	directive	seeks	to	prevent	and	control	air,	water	and	soil	pollution by	industrial	installations.	It	regulates	emissions	of	a	wide	range	of	pollutants,	including	sulphur	and	nitrogen	compounds,	dust	particles,	asbestos	and	heavy	metals.	The directive	is	aimed	at	improving	local	air,	water	and	soil	quality.	The	review	integrates	seven	directives	into	a	single	legal	framework	and	provides	for	a	more	harmonized and	rigorous	implementation	of	emissions	limits	associated	with	the	cleanest	available	technology,	so-called	BAT.	Deviations	from	this	standard	are	only	permitted where	local	and	technical	characteristics	would	make	it	disproportionately	costly	to	comply.	The	recast	also	tightens	emission	limits	for	NO ,	SO 	and	dust	from	power plants	and	large	combustion	installations	in	oil	refineries	and	the	metal	industry.	New	plants	must	apply	the	cleanest	available	technology	from	2012,	four	years	earlier than	initially	proposed.	Existing	plants	have	to	comply	with	this	standard	beginning	in	2016,	though	a	transition	period	is	foreseen.	Until	June	30,	2020,	member	states may	define	transitional	plans	with	declining	annual	caps	for	NO ,	SO 	or	dust	emissions.	Where	installations	are	already	scheduled	to	close	by	the	end	of	2023	or	operate less	than	17,500	hours	after	2016,	they	may	not	need	to	upgrade.	Member	states	have	two	years	to	implement	the	Directive.	Progress	in	implementation	of	the	directives referred	to	above	varies	from	member	state	to	member	state.	AES	generation	businesses	in	each	member	state	will	be	required	to	comply	with	the	relevant	measures taken	to	implement	the	directives.

On	January	18	2011,	the	President	of	Chile	approved	a	new	air	emissions	regulation	submitted	to	him	by	the	national	environmental	regulatory	agency ("CONAMA").	The	new	regulation	establishes	limits	on	emissions	of	NO X,	SO ,	metals	and	particulate	matter	for	both	existing	and	new	thermal	power	plants,	with more	stringent	limitations	on	new	facilities.	The	regulation	will	become	effective	upon	approval	of	the	General	Comptroller	of	Chile.	The	regulation	will	require	AES Gener,	our	Chilean	subsidiary,	to	install	emissions	reduction	equipment	at	its	existing	thermal	plants	from	late	2011	through	2015.	The	exact	costs	of	compliance	with such	regulation	have	not	yet	been	determined	and	the	Company	believes	some	of	the	compliance	costs	are	contractually	passed	through	to	counterparties.	However,	the compliance	costs	could	be	material.

Water	Discharges.	The	Company's	facilities	are	subject	to	a	variety	of	rules	governing	water	discharges.	In	particular,	the	Company	is	subject	to	the	United	States Clean	Water	Act	Section	316(b)	rule	regarding	existing	power	plant	cooling	water	intake	structures	issued	by	the	EPA	in	2005	(69	Fed.	Reg.	41579,	July	9,	2004),	and the	subsequent	Circuit	Court	of	Appeals	decision	and	Supreme	Court	decision	regarding	this	rule.	The	rule	as	originally	issued	could	affect	12	of	the	Company's	United States	power	plants	and	the	rule's	requirements	would

be	implemented	via	each	plant's	National	Pollutant	Discharge	Elimination	System	("NPDES")	water	quality	permit	renewal	process.	These	permits	are	usually processed	by	state	water	quality	agencies.	To	protect	fish	and	other	aquatic	organisms,	the	2004	rule	requires	existing	steam	electric	generating	facilities	to	utilize	the best	technology	available	for	cooling	water	intake	structures.	To	comply,	a	steam	electric	generating	facility	must	first	prepare	a	Comprehensive	Demonstration	Study	to assess	the	facility's	effect	on	the	local	aquatic	environment.	Since	each	facility's	design,	location,	existing	control	equipment	and	results	of	impact	assessments	must	be taken	into	consideration,	costs	will	likely	vary.	The	timing	of	capital	expenditures	to	achieve	compliance	with	this	rule	will	vary	from	site	to	site.	On	January	25,	2007, the	United	States	Court	of	Appeals	for	the	Second	Circuit	decision	(Docket	Nos.	04-6692	to	04-6699)	vacated	and	remanded	major	parts	of	the	2004	rule	back	to	the EPA.	In	November	2007,	three	industry	petitioners	sought	review	of	the	Second	Circuit's	decision	by	the	United	States	Supreme	Court,	and	this	review	was	granted	by the	United	States	Supreme	Court	in	April	2008.	In	its	April	2009	decision,	the	United	States	Supreme	Court	granted	the	EPA	authority	to	use	a	cost-benefit	analysis when	setting	technology-based	requirements	under	Section	316(b)	of	the	Clean	Water	Act,	and	expressed	no	view	on	the	remaining	bases	for	the	Second	Circuit's remand.	New	draft	rule	316(b)	regulations	are	expected	to	be	proposed	by	the	EPA	by	March	14,	2011,	and	finalized	by	July	27,	2012.	Until	such	regulations	are	final, the	EPA	has	instructed	state	regulatory	agencies	to	use	their	best	professional	judgment	in	determining	how	to	evaluate	what	constitutes	best	technology	available	for minimizing	adverse	environmental	impacts	from	cooling	water	intake	structures.	Certain	states	in	which	the	Company	operates	power	generation	facilities,	such	as	New York,	have	been	delegated	authority	and	are	moving	forward	with	best	technology	available	determinations	in	the	absence	of	any	final	rule	from	the	EPA.	On September	27,	2010,	the	California	Office	of	Administrative	Law	approved	a	policy	adopted	by	the	California	Water	Resources	Control	Board	with	respect	to	power plant	cooling	water	intake	structures.	This	policy	became	effective	on	October	1,	2010,	and	establishes	technology-based	standards	to	implement	Section	316(b)	of	the United	States	Clean	Water	Act.	At	this	time,	it	is	contemplated	that	the	Company's	Redondo	Beach,	Huntington	Beach	and	Alamitos	power	plants	in	California	will need	to	have	in	place	best	technology	available	by	December	31,	2020,	or	repower	the	facilities.	At	present,	the	Company	cannot	predict	the	final	requirements	under Section	316(b)	or	whether	compliance	with	the	anticipated	new	316(b)	rule	will	have	a	material	impact	on	our	operations	or	results,	but	the	Company	expects	that	capital investments	and/or	modifications	resulting	from	such	requirements	could	be	significant.	In	the	third	quarter	of	2010,	we	impaired	approximately	$200	million	at	our business	at	Southland	as	a	result	of	this	regulation.

Waste	Management.	In	the	course	of	operations,	the	Company's	facilities	generate	solid	and	liquid	waste	materials	requiring	eventual	disposal	or	processing. With	the	exception	of	coal	combustion	byproducts	("CCB"),	the	wastes	are	not	usually	physically	disposed	of	on	our	property,	but	are	shipped	off	site	for	final	disposal, treatment	or	recycling.	CCB,	which	consists	of	bottom	ash,	fly	ash	and	air	pollution	control	wastes,	is	disposed	of	at	some	of	our	coal-fired	power	generation	plant	sites using	engineered,	permitted	landfills.	Waste	materials	generated	at	our	electric	power	and	distribution	facilities	include	CCB,	oil,	scrap	metal,	rubbish,	small	quantities of	industrial	hazardous	wastes	such	as	spent	solvents,	tree	and	land	clearing	wastes	and	polychlorinated	biphenyl	("PCB")	contaminated	liquids	and	solids.	The Company	endeavors	to	ensure	that	all	of	its	solid	and	liquid	wastes	are	disposed	of	in	accordance	with	applicable	national,	regional,	state	and	local	regulations.	On December	22,	2009,	a	dike	at	a	coal	ash	containment	area	at	the	Tennessee	Valley	Authority's	plant	in	Kingston,	Tennessee	failed,	and	over	1	billion	gallons	of	ash	was released	into	adjacent	waterways	and	properties.	Following	such	incident,	there	has	been	heightened	focus	on	the	regulation	of	CCBs.	On	June	21,	2010,	the	EPA published	in	the	Federal	Register	a	proposed	rule	to	regulate	CCB	under	the	Resource	Conservation	and	Recovery	Act	("RCRA").	The	proposed	rule	provides	two possible	options	for	CCB	regulation,	and	both	options	contemplate	heightened	structural	integrity	requirements	for	surface	impoundments	of	CCB.	The	first	option contemplates	regulation	of	CCB	as	a	hazardous	waste	subject	to	regulation	under	Subtitle	C	of	the	RCRA.	Under	this	option,	existing	surface	impoundments	containing CCB	would	be	required	to	be	retrofitted	with	composite	liners	and	these	impoundments	would	likely	be	phased	out	over	several	years.	State	and/or	federal	permit programs	would	be	developed	for	storage,	transport	and	disposal	of	CCB.	States	could	bring	enforcement	actions	for	non-compliance	with	permitting	requirements,	and the	EPA	would	have	oversight	responsibilities	as	well	as	the	authority	to	bring	lawsuits	for	non-compliance.	The	second	option	contemplates	regulation	of	CCB	under Subtitle	D	of	the	RCRA.	Under	this	option,	the	EPA	would	create	national	criteria	applicable	to	CCB	landfills	and	surface	impoundments.

Existing	impoundments	would	also	be	required	to	be	retrofitted	with	composite	liners	and	would	likely	be	phased	out	over	several	years.	This	option	would	not	contain federal	or	state	permitting	requirements.	The	primary	enforcement	mechanism	under	regulation	pursuant	to	Subtitle	D	would	be	private	lawsuits.

The	public	comment	period	for	this	proposed	regulation	has	expired,	and	EPA	is	required	to	consider	the	public	comments	prior	to	promulgating	a	final	rule. Requirements	under	a	final	rule	are	expected	to	become	effective	by	January	2012,	with	a	compliance	schedule	of	five	years.	While	the	exact	impact	and	compliance cost	associated	with	future	regulations	of	CCB	cannot	be	established	until	such	regulations	are	finalized,	there	can	be	no	assurance	that	the	Company's	businesses, financial	condition	or	results	of	operations	would	not	be	materially	and	adversely	affected	by	such	regulations.

# Subsequent	Events

Subsequent	to	December	31,	2010,	the	Company	continued	to	repurchase	stock	under	the	stock	repurchase	program	announced	on	July	7,	2010.	The	Company has	repurchased	1,026,610	shares	at	a	cost	of	$13	million	in	2011,	bringing	the	cumulative	total	through	February	22,	2010	to	9,409,435	shares	at	a	total	cost	of	$112 million	(average	price	of	$11.92	per	share	including	commissions).	As	of	February	25,	2011,	$388	million	of	the	$500	million	authorized	remained	available	under	the stock	repurchase	program.	For	additional	information,	see	Note	14—Equity.

On	February	1,	2011,	AES	Thames,	LLC	("Thames"),	our	208	MW	coal-fired	plant	in	Connecticut,	filed	petitions	for	bankruptcy	protection	under	Chapter	11	in the	U.	S.	Bankruptcy	Court.	The	bankruptcy	is	due,	in	part,	to	the	increased	cost	of	energy	production.	The	bankruptcy	protection	is	not	expected	to	have	a	material impact	on	the	Company's	financial	position	or	the	results	of	operations.

# ITEM	1A. RISK	FACTORS

You	should	consider	carefully	the	following	risks,	along	with	the	other	information	contained	in	or	incorporated	by	reference	in	this	Form	10-K.	Additional	risks and	uncertainties	also	may	adversely	affect	our	business	and	operations	including	those	discussed	in	Item	7.—Management's	Discussion	and	Analysis	of	Financial Condition	and	Results	of	Operations	in	this	Form	10-K.	If	any	of	the	following	events	actually	occur,	our	business,	financial	results	and	financial	condition	could	be materially	adversely	affected.

# Risks	Associated	with	our	Disclosure	Controls	and	Internal	Control	over	Financial	Reporting

We	completed	the	remediation	of	our	material	weaknesses	in	internal	control	over	financial	reporting	in	2008.	However,	our	disclosure	controls	and procedures	may	not	be	effective	in	future	periods	if	our	judgments	prove	incorrect	or	new	material	weaknesses	are	identified.

For	each	of	the	fiscal	quarters	since	December	31,	2004	through	September	30,	2008,	our	management	reported	material	weaknesses	in	our	internal	control	over financial	reporting.	A	material	weakness	is	a	deficiency	(within	the	meaning	of	the	Public	Company	Accounting	Oversight	Board	("PCAOB")	Auditing	Standard	No.	5), or	a	combination	of	deficiencies,	that	adversely	affects	a	company's	ability	to	initiate,	authorize,	record,	process,	or	report	external	financial	data	reliably	in	accordance with	generally	accepted	accounting	principles	such	that	there	is	a	reasonable	possibility	that	a	material	misstatement	of	the	annual	or	interim	financial	statements	will	not be	prevented	or	detected.	As	a	result	of	these	material	weaknesses,	our	management	concluded	that	for	each	of	the	fiscal	quarters	from	December	31,	2004	through September	30,	2008,	we	did	not	maintain	effective	internal	control	over	financial	reporting	and	concluded	that	our	disclosure	controls	and	procedures	were	not	effective to	provide	reasonable	assurance	that	financial	information	that	we	are	required	to	disclose	in	our	reports	under	the	Exchange	Act	was	recorded,	processed,	summarized and	reported	accurately.

To	address	these	material	weaknesses	in	our	internal	control	over	financial	reporting,	each	time	we	prepared	our	annual	and	quarterly	reports,	we	performed additional	analyses	and	other	post-closing	procedures.	These

additional	procedures	were	costly,	time	consuming	and	required	us	to	dedicate	a	significant	amount	of	our	resources,	including	the	time	and	attention	of	our	senior management,	toward	the	correction	of	these	problems.	Nevertheless,	even	with	these	additional	procedures,	the	material	weaknesses	in	our	internal	control	over financial	reporting	caused	us	to	have	errors	in	our	financial	statements	and	since	2003	we	had	to	restate	our	annual	financial	statements	six	times	to	correct	these	errors.

The	material	weaknesses	in	our	internal	control	over	financial	reporting	also	caused	us	to	delay	the	filing	of	certain	quarterly	and	annual	reports	with	the	SEC	to dates	that	went	beyond	the	deadlines	prescribed	by	the	SEC's	rules	to	file	such	reports.	We	did	not	timely	file	with	the	SEC	our	quarterly	and	annual	reports	for	the	year ended	December	31,	2005,	our	quarterly	reports	for	the	second	and	third	quarters	of	2005,	our	annual	report	for	the	year	ended	December	31,	2006,	and	our	quarterly report	for	the	quarter	ended	March	31,	2007.	Under	SEC	rules,	failure	to	timely	file	these	reports	prohibited	us	for	a	period	of	twelve	months	from	offering	and	selling our	securities	pursuant	to	our	shelf	registration	statement	on	Form	S-3,	which	impaired	our	ability	to	access	the	capital	markets	through	the	public	sale	of	registered securities	in	a	timely	manner.	The	failure	to	file	our	annual	and	quarterly	reports	with	the	SEC	in	a	timely	fashion	also	resulted	in	covenant	defaults	under	our	senior secured	credit	facility	and	the	indenture	governing	certain	of	our	outstanding	debt	securities.	Such	defaults	required	us	to	obtain	a	waiver	from	the	lenders	under	the senior	secured	credit	facility;	however	the	default	under	the	indentures	was	cured	upon	the	filing	of	the	reports	within	the	permitted	grace	period.	In	addition	to	these problems,	the	material	weaknesses	in	internal	controls,	the	restatements	of	our	financial	statements	and	the	delay	in	the	filing	of	our	annual	and	quarterly	reports	exposed us	to	other	risks	including,	but	not	limited	to:

•litigation	or	an	expansion	of	the	SEC's	informal	inquiry	into	our	restatements	or	the	commencement	of	formal	proceedings	by	the	SEC	or	other	regulatory authorities,	which	could	require	us	to	incur	significant	legal	expenses	and	other	costs	or	to	pay	damages,	fines	or	other	penalties;

•negative	publicity;

•ratings	downgrades;

•inability	to	raise	capital	in	the	public	markets	and/or	private	markets	when	desired	or	necessary;	or

•the	loss	or	impairment	of	investor	confidence	in	the	Company.

Since	December	31,	2008,	our	management	has	reported	that	all	of	our	previously	identified	material	weaknesses	have	been	remediated	and	that	our	internal control	over	financial	reporting	and	our	disclosure	controls	have	been	effective.	For	a	discussion	of	our	internal	control	over	financial	reporting	and	our	disclosure controls,	see	Item	9A.—Controls	and	Procedures	in	this	Form	10-K.	In	making	its	assessment	about	the	effectiveness	of	our	internal	control	over	financial	reporting	and our	disclosure	controls	and	procedures,	management	had	to	make	certain	judgments	and	it	is	possible	that	any	number	of	their	judgments	could	prove	to	be	incorrect	and that	our	remediation	efforts	did	not	fully	and	completely	cure	the	previously	identified	material	weaknesses.	There	is	also	the	possibility	that	there	are	other	material weaknesses	in	our	internal	control	that	are	unknown	to	us	or	that	new	material	weaknesses	may	develop	in	the	future.	The	existence	of	any	material	weakness	in	our internal	control	over	financial	reporting	would	subject	us	to	all	of	the	risks	described	above.

Furthermore,	any	evaluation	of	the	effectiveness	of	controls	is	subject	to	risks	that	those	internal	controls	may	become	inadequate	in	future	periods	because	of changes	in	business	conditions,	changes	in	accounting	practice	or	policy,	or	that	the	degree	of	compliance	with	the	revised	policies	or	procedures	deteriorates	over	time. Management,	including	our	CEO	and	CFO,	does	not	expect	that	our	internal	controls	will	prevent	or	detect	all	errors	and	all	fraud.	A	control	system,	no	matter	how	well designed	and	operated,	can	provide	only	reasonable,	not	absolute,	assurance	that	the	objectives	of	the	control	system	are	met.	Further,	the	design	of	a	control	system must	reflect	the	fact	that	there	are	resource	constraints,	and	the	benefits	of	controls	must	be	considered	relative	to	their	costs.

# In	the	future,	we	may	be	adversely	impacted	by	the	efforts	required	to	adopt	new	accounting	standards	issued	by	the	FASB	as	a	result	of	the	convergence	of accounting	standards	project	between	the	FASB	and	IASB

The	U.S	Financial	Accounting	Standards	Board	(the	"FASB"),	which	establishes	accounting	principles	generally	accepted	in	the	United	States	("GAAP") guidelines	that	companies	follow	in	the	United	States,	and	the	International	Accounting	Standards	Board	("IASB"),	which	is	an	international	accounting	standards	setter outside	of	the	United	States,	are	presently	engaged	in	a	project	to	converge	several	accounting	standards.	The	convergence	project	may	result	in	the	issuance	of	several new	accounting	standards	in	the	future	that	revise	existing	GAAP	accounting	standards	and	which	the	Company	may	be	required	to	adopt	under	GAAP.

Based	on	the	present	timeline	released	by	the	FASB,	several	pronouncements	could	be	issued	in	final	form	in	2011.	Although	the	release	of	final	pronouncements is	not	assured	and	the	proposed	adoption	dates	of	these	standards	have	not	been	set,	each	new	standard	that	the	Company	must	comply	with	may	require	significant effort	to	adopt.	For	each	new	standard,	the	Company	will	be	required	to	evaluate	the	impact	of	any	accounting	changes	necessitated	by	a	new	standard	which	will include,	but	not	be	limited	to,	an	evaluation	of	a	new	standard's	impact	on	its	financial	statements	and	contractual	arrangements;	planning	for	and	implementation	of any	changes	to	accounting	systems;	processes	and	procedures	to	ensure	the	Company	properly	complies	with	a	new	standard;	and	training	personnel.	To	the	extent	that multiple	standards	are	effective	as	of	one	date	or	in	close	proximity	to	one	another,	the	Company	may	require	considerable	resources	to	achieve	compliance	with	these new	standards.	An	inability	to	complete	these	efforts	prior	to	their	effective	date	could	have	an	adverse	effect	on	our	ability	to	timely	file	our	financial	statements	with the	SEC	and/or	the	effectiveness	of	our	internal	controls	over	financial	reporting.

# We	have	a	significant	amount	of	debt,	a	large	percentage	of	which	is	secured,	which	could	adversely	affect	our	business	and	the	ability	to	fulfill	our obligations.

As	of	December	31,	2010,	we	had	approximately	$19.7	billion	of	outstanding	indebtedness	on	a	consolidated	basis.	All	outstanding	borrowings	under	The	AES Corporation's	senior	secured	credit	facility	and	certain	other	indebtedness	are	secured	by	certain	of	our	assets,	including	the	pledge	of	capital	stock	of	many	of	The	AES Corporation's	directly	held	subsidiaries.	Most	of	the	debt	of	The	AES	Corporation's	subsidiaries	is	secured	by	substantially	all	of	the	assets	of	those	subsidiaries.	Since we	have	such	a	high	level	of	debt,	a	substantial	portion	of	cash	flow	from	operations	must	be	used	to	make	payments	on	this	debt.	Furthermore,	since	a	significant percentage	of	our	assets	are	used	to	secure	this	debt,	this	reduces	the	amount	of	collateral	that	is	available	for	future	secured	debt	or	credit	support	and	reduces	our flexibility	in	dealing	with	these	secured	assets.	This	high	level	of	indebtedness	and	related	security	could	have	other	important	consequences	to	us	and	our	investors, including:

•	 making	it	more	difficult	to	satisfy	debt	service	and	other	obligations	at	the	holding	company	and/or	individual	subsidiaries;

•increasing	the	likelihood	of	a	downgrade	of	our	debt,	which	could	cause	future	debt	costs	and/or	payments	to	increase	under	our	debt	and	related	hedging instruments	and	consume	an	even	greater	portion	of	cash	flow;

•increasing	our	vulnerability	to	general	adverse	industry	conditions	and	economic	conditions,	including	but	not	limited	to	adverse	changes	in	foreign exchange	rates	and	commodity	prices;

•reducing	the	availability	of	cash	flow	to	fund	other	corporate	purposes	and	grow	our	business;

•limiting	our	flexibility	in	planning	for,	or	reacting	to,	changes	in	our	business	and	the	industry;

•placing	us	at	a	competitive	disadvantage	to	our	competitors	that	are	not	as	highly	leveraged;	and

•limiting,	along	with	the	financial	and	other	restrictive	covenants	relating	to	such	indebtedness,	among	other	things,	our	ability	to	borrow	additional	funds	as needed	or	take	advantage	of	business	opportunities	as	they	arise,	pay	cash	dividends	or	repurchase	common	stock.

The	agreements	governing	our	indebtedness,	including	the	indebtedness	of	our	subsidiaries,	limit,	but	do	not	prohibit	the	incurrence	of	additional	indebtedness. To	the	extent	we	become	more	leveraged,	the	risks	described	above	would	increase.	Further,	our	actual	cash	requirements	in	the	future	may	be	greater	than	expected. Accordingly,	our	cash	flows	may	not	be	sufficient	to	repay	at	maturity	all	of	the	outstanding	debt	as	it	becomes	due	and,	in	that	event,	we	may	not	be	able	to	borrow money,	sell	assets,	raise	equity	or	otherwise	raise	funds	on	acceptable	terms	or	at	all	to	refinance	our	debt	as	it	becomes	due.	See	Note	10—Debt	included	in	Item	8.	of this	Form	10-K	for	a	schedule	of	our	debt	maturities.

# The	AES	Corporation	is	a	holding	company	and	its	ability	to	make	payments	on	its	outstanding	indebtedness,	including	its	public	debt	securities,	is	dependent upon	the	receipt	of	funds	from	its	subsidiaries	by	way	of	dividends,	fees,	interest,	loans	or	otherwise.

The	AES	Corporation	is	a	holding	company	with	no	material	assets	other	than	the	stock	of	its	subsidiaries.	All	of	The	AES	Corporation's	revenue	is	generated through	its	subsidiaries.	Accordingly,	almost	all	of	The	AES	Corporation's	cash	flow	is	generated	by	the	operating	activities	of	its	subsidiaries.	Therefore,	The	AES Corporation's	ability	to	make	payments	on	its	indebtedness	and	to	fund	its	other	obligations	is	dependent	not	only	on	the	ability	of	its	subsidiaries	to	generate	cash,	but also	on	the	ability	of	the	subsidiaries	to	distribute	cash	to	it	in	the	form	of	dividends,	fees,	interest,	loans	or	otherwise.

However,	our	subsidiaries	face	various	restrictions	in	their	ability	to	distribute	cash	to	The	AES	Corporation.	Most	of	the	subsidiaries	are	obligated,	pursuant	to loan	agreements,	indentures	or	project	financing	arrangements,	to	satisfy	certain	restricted	payment	covenants	or	other	conditions	before	they	may	make	distributions	to The	AES	Corporation.	In	addition,	the	payment	of	dividends	or	the	making	of	loans,	advances	or	other	payments	to	The	AES	Corporation	may	be	subject	to	other contractual,	legal	or	regulatory	restrictions.	Business	performance	and	local	accounting	and	tax	rules	may	limit	the	amount	of	retained	earnings	that	may	be	distributed to	us	as	a	dividend.	Subsidiaries	in	foreign	countries	may	also	be	prevented	from	distributing	funds	to	The	AES	Corporation	as	a	result	of	foreign	governments restricting	the	repatriation	of	funds	or	the	conversion	of	currencies.	Any	right	that	The	AES	Corporation	has	to	receive	any	assets	of	any	of	its	subsidiaries	upon	any liquidation,	dissolution,	winding	up,	receivership,	reorganization,	bankruptcy,	insolvency	or	similar	proceedings	(and	the	consequent	right	of	the	holders	of	The	AES Corporation's	indebtedness	to	participate	in	the	distribution	of,	or	to	realize	proceeds	from,	those	assets)	will	be	effectively	subordinated	to	the	claims	of	any	such subsidiary's	creditors	(including	trade	creditors	and	holders	of	debt	issued	by	such	subsidiary).

The	AES	Corporation	could	receive	less	funds	than	it	expects	as	a	result	of	the	current	challenges	facing	the	global	and	local	economies,	which	could	impact	the performance	of	our	businesses	and	their	ability	to	distribute	cash	to	The	AES	Corporation.	For	further	discussion	of	the	macroeconomic	environment	and	its	impact	on our	business,	see	Item	7.—Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations—Global	Economic	Conditions.

The	AES	Corporation's	subsidiaries	are	separate	and	distinct	legal	entities	and,	unless	they	have	expressly	guaranteed	any	of	The	AES	Corporation's indebtedness,	have	no	obligation,	contingent	or	otherwise,	to	pay	any	amounts	due	pursuant	to	such	debt	or	to	make	any	funds	available	whether	by	dividends,	fees,	loans or	other	payments.	While	some	of	The	AES	Corporation's	subsidiaries	guarantee	the	Parent's	indebtedness	under	the	Parent's	senior	secured	credit	facility,	none	of	its subsidiaries	guarantee,	or	are	otherwise	obligated	with	respect	to,	its	outstanding	public	debt	securities.

# Even	though	The	AES	Corporation	is	a	holding	company,	existing	and	potential	future	defaults	by	subsidiaries	or	affiliates	could	adversely	affect	The	AES Corporation.

We	attempt	to	finance	our	domestic	and	foreign	projects	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."	In	some	project financings,	The	AES	Corporation	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,	the	project	lenders	or	other	parties.

As	of	December	31,	2010,	we	had	approximately	$19.7	billion	of	outstanding	indebtedness	on	a	consolidated	basis,	of	which	approximately	$4.6	billion	was recourse	debt	of	The	AES	Corporation	and	approximately	$15.1	billion	was	non-recourse	debt.	In	addition,	we	have	outstanding	guarantees,	letters	of	credit,	and	other credit	support	commitments	which	are	further	described	in	this	Form	10-K	in	Item	7.—Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of Operations—Capital	Resources	and	Liquidity—Parent	Company	Liquidity.

Some	of	our	subsidiaries	are	currently	in	default	with	respect	to	all	or	a	portion	of	their	outstanding	indebtedness.	The	total	debt	classified	as	current	in	our consolidated	balance	sheets	related	to	such	defaults	was	$1.4	billion	at	December	31,	2010.	While	the	lenders	under	our	non-recourse	project	financings	generally	do	not have	direct	recourse	to	The	AES	Corporation	(other	than	to	the	extent	of	any	credit	support	given	by	The	AES	Corporation),	defaults	thereunder	can	still	have	important consequences	for	The	AES	Corporation,	including,	without	limitation:

•reducing	The	AES	Corporation's	receipt	of	subsidiary	dividends,	fees,	interest	payments,	loans	and	other	sources	of	cash	since	the	project	subsidiary	will typically	be	prohibited	from	distributing	cash	to	The	AES	Corporation	during	the	pendency	of	any	default;

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

•causing	The	AES	Corporation	to	record	a	loss	in	the	event	the	lender	forecloses	on	the	assets;

•triggering	defaults	in	The	AES	Corporation's	outstanding	debt	and	trust	preferred	securities.	For	example,	The	AES	Corporation's	senior	secured	credit facility	and	outstanding	senior	notes	include	events	of	default	for	certain	bankruptcy	related	events	involving	material	subsidiaries.	In	addition,	The	AES Corporation's	senior	secured	credit	facility	includes	certain	events	of	default	relating	to	accelerations	of	outstanding	debt	of	material	subsidiaries;

# •the	loss	or	impairment	of	investor	confidence	in	the	Company;	or

•foreclosure	on	the	assets	that	are	pledged	under	the	nonrecourse	loans,	therefore	eliminating	any	and	all	potential	future	benefits	derived	from	those	assets.

None	of	the	projects	that	are	currently	in	default	are	owned	by	subsidiaries	that	meet	the	applicable	definition	of	materiality	in	The	AES	Corporation's	senior secured	credit	facility	or	other	debt	agreements	in	order	for	such	defaults	to	trigger	an	event	of	default	or	permit	acceleration	under	such	indebtedness.	However,	as	a result	of	future	mix	of	distributions,	write-down	of	assets,	dispositions	and	other	matters	that	affect	our	financial	position	and	results	of	operations,	it	is	possible	that	one or	more	of	these	subsidiaries	could	fall	within	the	applicable	definition	of	materiality	and	thereby	upon	an	acceleration	of	such	subsidiary's	debt,	trigger	an	event	of default	and	possible	acceleration	of	the	indebtedness	under	The	AES	Corporation's	senior	secured	credit	facility.	The	risk	of	such	defaults	may	have	increased	as	a	result of	the	deteriorating	global	economy.	For	further

discussion	of	these	conditions,	see	Item	7.—Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations—Global	Economic	Conditions	of this	Form	10-K.

# The	AES	Corporation	has	significant	cash	requirements	and	limited	sources	of	liquidity.

The	AES	Corporation	requires	cash	primarily	to	fund:

•principal	repayments	of	debt;

•interest	and	preferred	dividends;

•acquisitions;

•construction	and	other	project	commitments;

•other	equity	commitments,	including	business	development	investments;

•equity	repurchases;

•taxes;	and

•Parent	Company	overhead	costs.

The	AES	Corporation's	principal	sources	of	liquidity	are:

•dividends	and	other	distributions	from	its	subsidiaries;

•proceeds	from	debt	and	equity	financings	at	the	Parent	Company	level;	and

•proceeds	from	asset	sales.

For	a	more	detailed	discussion	of	The	AES	Corporation's	cash	requirements	and	sources	of	liquidity,	please	see	Item	7.—Management's	Discussion	and	Analysis of	Financial	Condition	and	Results	of	Operations—Capital	Resources	and	Liquidity	of	this	Form	10-K.

While	we	believe	that	these	sources	will	be	adequate	to	meet	our	obligations	at	the	Parent	Company	level	for	the	foreseeable	future,	this	belief	is	based	on	a number	of	material	assumptions,	including,	without	limitation,	assumptions	about	our	ability	to	access	the	capital	or	commercial	lending	markets,	the	operating	and financial	performance	of	our	subsidiaries,	exchange	rates,	our	ability	to	sell	assets,	and	the	ability	of	our	subsidiaries	to	pay	dividends.	Any	number	of	assumptions	could prove	to	be	incorrect	and	therefore	there	can	be	no	assurance	that	these	sources	will	be	available	when	needed	or	that	our	actual	cash	requirements	will	not	be	greater than	expected.	For	example,	in	recent	years,	certain	financial	institutions	have	gone	bankrupt.	In	the	event	that	a	bank	who	is	party	to	our	senior	secured	credit	facility	or other	facilities	goes	bankrupt	or	is	otherwise	unable	to	fund	its	commitments,	we	would	need	to	replace	that	bank	in	our	syndicate	or	risk	a	reduction	in	the	size	of	the facility,	which	would	reduce	our	liquidity.	In	addition,	our	cash	flow	may	not	be	sufficient	to	repay	at	maturity	the	entire	principal	outstanding	under	our	credit	facilities and	our	debt	securities	and	we	may	have	to	refinance	such	obligations.	There	can	be	no	assurance	that	we	will	be	successful	in	obtaining	such	refinancing	on	terms acceptable	to	us	or	at	all	and	any	of	these	events	could	have	a	material	effect	on	us.

# Our	ability	to	grow	our	business	could	be	materially	adversely	affected	if	we	were	unable	to	raise	capital	on	favorable	terms.

From	time	to	time,	we	rely	on	access	to	capital	markets	as	a	source	of	liquidity	for	capital	requirements	not	satisfied	by	operating	cash	flows.	Our	ability	to	arrange for	financing	on	either	a	recourse	or	non-recourse	basis	and	the	costs	of	such	capital	are	dependent	on	numerous	factors,	some	of	which	are	beyond	our	control, including:

•general	economic	and	capital	market	conditions;

•the	availability	of	bank	credit;

# •investor	confidence;

•the	financial	condition,	performance	and	prospects	of	The	AES	Corporation	in	general	and/or	that	of	any	subsidiary	requiring	the	financing	as	well	as companies	in	our	industry	or	similar	financial	circumstances;	and

•changes	in	tax	and	securities	laws	which	are	conducive	to	raising	capital.

Should	future	access	to	capital	not	be	available	to	us,	we	may	have	to	sell	assets	or	decide	not	to	build	new	plants	or	expand	or	improve	existing	facilities,	either of	which	would	affect	our	future	growth,	results	of	operations	or	financial	condition.

# A	downgrade	in	the	credit	ratings	of	The	AES	Corporation	or	its	subsidiaries	could	adversely	affect	our	ability	to	access	the	capital	markets	which	could increase	our	interest	costs	or	adversely	affect	our	liquidity	and	cash	flow.

If	any	of	the	credit	ratings	of	The	AES	Corporation	or	its	subsidiaries	were	to	be	downgraded,	our	ability	to	raise	capital	on	favorable	terms	could	be	impaired	and our	borrowing	costs	would	increase.	Furthermore,	depending	on	The	AES	Corporation's	credit	ratings	and	the	trading	prices	of	its	equity	and	debt	securities, counterparties	may	no	longer	be	as	willing	to	accept	general	unsecured	commitments	by	The	AES	Corporation	to	provide	credit	support.	Accordingly,	with	respect	to both	new	and	existing	commitments,	The	AES	Corporation	may	be	required	to	provide	some	other	form	of	assurance,	such	as	a	letter	of	credit	and/or	collateral,	to backstop	or	replace	any	credit	support	by	The	AES	Corporation.	There	can	be	no	assurance	that	such	counterparties	will	accept	such	guarantees	or	that	AES	could arrange	such	further	assurances	in	the	future.	In	addition,	to	the	extent	The	AES	Corporation	is	required	and	able	to	provide	letters	of	credit	or	other	collateral	to	such counterparties,	it	will	limit	the	amount	of	credit	available	to	The	AES	Corporation	to	meet	its	other	liquidity	needs.

# We	may	not	be	able	to	raise	sufficient	capital	to	fund	"greenfield"	projects	in	certain	less	developed	economies	which	could	change	or	in	some	cases adversely	affect	our	growth	strategy.

Part	of	our	strategy	is	to	grow	our	business	by	developing	Generation	and	Utility	businesses	in	less	developed	economies	where	the	return	on	our	investment	may be	greater	than	projects	in	more	developed	economies.	Commercial	lending	institutions	sometimes	refuse	to	provide	non-recourse	project	financing	in	certain	less developed	economies,	and	in	these	situations	we	have	sought	and	will	continue	to	seek	direct	or	indirect	(through	credit	support	or	guarantees)	project	financing	from	a limited	number	of	multilateral	or	bilateral	international	financial	institutions	or	agencies.	As	a	precondition	to	making	such	project	financing	available,	the	lending institutions	may	also	require	governmental	guarantees	of	certain	project	and	sovereign	related	risks.	There	can	be	no	assurance,	however,	that	project	financing	from	the international	financial	agencies	or	that	governmental	guarantees	will	be	available	when	needed,	and	if	they	are	not,	we	may	have	to	abandon	the	project	or	invest	more	of our	own	funds	which	may	not	be	in	line	with	our	investment	objectives	and	would	leave	less	funds	for	other	projects.	These	risks	have	increased	as	a	result	of	the	recent credit	crisis	and	the	deteriorating	global	economy.	For	further	discussion	of	these	global	economic	conditions	and	their	potential	impact	on	the	Company,	see	Item	7.— Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations—Global	Economic	Conditions.

Our	businesses	may	incur	substantial	costs	and	liabilities	and	be	exposed	to	price	volatility	as	a	result	of	risks	associated	with	the	wholesale	electricity markets,	which	could	have	a	material	adverse	effect	on	our	financial	performance.

Some	of	our	businesses	sell	electricity	in	the	wholesale	spot	markets	in	cases	where	they	operate	wholly	or	partially	without	long-term	power	sales	agreements. Our	Generation	and	Utility	businesses	may	also	buy	electricity	in	the	wholesale	spot	markets.	As	a	result,	we	are	exposed	to	the	risks	of	rising	and	falling	prices	in 79

those	markets.	The	open	market	wholesale	prices	for	electricity	are	very	volatile	and	often	reflect	the	fluctuating	cost	of	coal,	natural	gas	or	oil.	Consequently,	any changes	in	the	supply	and	cost	of	coal,	natural	gas,	or	oil	may	impact	the	open	market	wholesale	price	of	electricity.

Volatility	in	market	prices	for	fuel	and	electricity	may	result	from	among	other	things:

•plant	availability	in	the	markets	generally;

•availability	and	effectiveness	of	transmission	facilities	owned	and	operated	by	third	parties;

•competition;

•demand	for	energy	commodities;

•electricity	usage;

•seasonality;

•interest	rate	and	foreign	exchange	rate	fluctuation;

•availability	and	price	of	emission	credits;

•input	prices;

•hydrology	and	other	weather	conditions;

•illiquid	markets;

•transmission	or	transportation	constraints	or	inefficiencies;

•availability	of	competitively	priced	renewables	sources;

•available	supplies	of	natural	gas,	crude	oil	and	refined	products,	and	coal;

•generating	unit	performance;

•natural	disasters,	terrorism,	wars,	embargoes	and	other	catastrophic	events;

•energy,	market	and	environmental	regulation,	legislation	and	policies;

•geopolitical	concerns	affecting	global	supply	of	oil	and	natural	gas;	and

•general	economic	conditions	in	areas	where	we	operate	which	impact	energy	consumption.

# Our	financial	position	and	results	of	operations	may	fluctuate	significantly	due	to	fluctuations	in	currency	exchange	rates	experienced	at	our	foreign operations.

Our	exposure	to	currency	exchange	rate	fluctuations	results	primarily	from	the	translation	exposure	associated	with	the	preparation	of	the	Consolidated	Financial Statements,	as	well	as	from	transaction	exposure	associated	with	transactions	in	currencies	other	than	an	entity's	functional	currency.	While	the	Consolidated	Financial Statements	are	reported	in	U.S.	Dollars,	the	financial	statements	of	many	of	our	subsidiaries	outside	the	United	States	are	prepared	using	the	local	currency	as	the functional	currency	and	translated	into	U.S.	Dollars	by	applying	appropriate	exchange	rates.	As	a	result,	fluctuations	in	the	exchange	rate	of	the	U.S.	Dollar	relative	to the	local	currencies	where	our	subsidiaries	outside	the	United	States	report	could	cause	significant	fluctuations	in	our	results.	In	addition,	while	our	expenses	with respect	to	foreign	operations	are	generally	denominated	in	the	same	currency	as	corresponding	sales,	we	have	transaction	exposure	to	the	extent	receipts	and expenditures	are	not	denominated	in	the	subsidiary's	functional	currency.

We	also	experience	foreign	transaction	exposure	to	the	extent	monetary	assets	and	liabilities,	including	debt,	are	in	a	different	currency	than	the	subsidiary's functional	currency.	Moreover,	the	costs	of	doing	business	abroad	may	increase	as	a	result	of	adverse	exchange	rate	fluctuations.	Our	financial	position	and	results	of operations	have	been	affected	by	fluctuations	in	the	value	of	a	number	of	currencies,	primarily	the	Euro,	Brazilian	real,	Argentine	peso,	Chilean	peso,	Colombian	peso and	Philippine	peso.

# We	may	not	be	adequately	hedged	against	our	exposure	to	changes	in	commodity	prices	or	interest	rates.

We	routinely	enter	into	contracts	to	hedge	a	portion	of	our	purchase	and	sale	commitments	for	electricity,	fuel	requirements	and	other	commodities	to	lower	our financial	exposure	related	to	commodity	price	fluctuations.	As	part	of	this	strategy,	we	routinely	utilize	fixed-price	forward	physical	purchase	and	sales	contracts, futures,	financial	swaps,	and	option	contracts	traded	in	the	over-the-counter	markets	or	on	exchanges.	We	also	enter	into	contracts	which	help	us	hedge	our	interest	rate exposure	on	variable	rate	debt.	However,	we	may	not	cover	the	entire	exposure	of	our	assets	or	positions	to	market	price	or	interest	rate	volatility,	and	the	coverage	will vary	over	time.	Furthermore,	the	risk	management	procedures	we	have	in	place	may	not	always	be	followed	or	may	not	work	as	planned.	In	particular,	if	prices	of commodities	or	interest	rates	significantly	deviate	from	historical	prices	or	interest	rates	or	if	the	price	or	interest	rate	volatility	or	distribution	of	these	changes	deviates from	historical	norms,	our	risk	management	system	may	not	protect	us	from	significant	losses.	As	a	result,	fluctuating	commodity	prices	or	interest	rates	may	negatively impact	our	financial	results	to	the	extent	we	have	unhedged	or	inadequately	hedged	positions.	In	addition,	certain	types	of	economic	hedging	activities	may	not	qualify for	hedge	accounting	under	GAAP,	resulting	in	increased	volatility	in	our	net	income.	The	Company	may	also	suffer	losses	associated	with	"basis	risk"	which	is	the assumed	relative	correlation	of	performance	between	the	intended	hedge	instrument	and	the	targeted	underlying	exposure.	Furthermore,	there	is	a	risk	that	the	current counterparties	to	these	arrangements	may	fail	or	are	unable	to	perform	their	obligations	under	these	arrangements.

In	2010,	we	faced	substantial	challenges	in	North	America	as	a	result	of	high	coal	prices	relative	to	natural	gas,	which	has	affected	the	results	of	certain	of	our coal	plants	in	the	region,	particularly	those	which	are	merchant	plants	that	are	exposed	to	market	risk	and	those	that	have	hybrid	merchant	risk,	meaning	those businesses	that	have	a	PPA	in	place	but	purchase	fuel	at	market	prices	or	under	short	term	contracts.	In	particular,	our	coal-fired	plants	in	New	York	and	our	petroleum coke-fired	plant	in	Texas	have	been	affected	by	these	conditions.	In	North	America,	current	dark	spreads	and	the	corresponding	forward	curves	do	not	currently	present a	long-term	opportunity	to	engage	in	hedging	activity	for	2011	and	we	have	very	limited	hedges	in	place.	As	short-term	opportunities	occur	or	should	dark	spreads improve,	the	Company	may	engage	in	additional	hedging	in	2011.	As	a	result	of	these	and	other	challenges	that	arose	from	new	regulatory	concerns,	we	impaired	$1.1 billion	of	assets	and	goodwill	in	North	America	as	described	in	Item	7.—Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations— Impairments.	In	addition,	AES	Thames,	our	208	MW	coal-fired	generation	business	in	Connecticut,	filed	for	bankruptcy	protection	in	January	2011.

# Supplier	and/or	customer	concentration	may	expose	the	Company	to	significant	financial	credit	or	performance	risks.

We	often	rely	on	a	single	contracted	supplier	or	a	small	number	of	suppliers	for	the	provision	of	fuel,	transportation	of	fuel	and	other	services	required	for	the operation	of	certain	of	our	facilities.	If	these	suppliers	cannot	perform,	we	would	seek	to	meet	our	fuel	requirements	by	purchasing	fuel	at	market	prices,	exposing	us	to market	price	volatility	and	the	risk	that	fuel	and	transportation	may	not	be	available	during	certain	periods	at	any	price,	which	could	be	lower	than	contracted	prices	and would	expose	these	businesses	to	considerable	price	volatility.

At	times,	we	rely	on	a	single	customer	or	a	few	customers	to	purchase	all	or	a	significant	portion	of	a	facility's	output,	in	some	cases	under	long-term	agreements that	account	for	a	substantial	percentage	of	the	anticipated	revenue	from	a	given	facility.	We	have	also	hedged	a	portion	of	our	exposure	to	power	price	fluctuations through	forward	fixed	price	power	sales.	Counterparties	to	these	agreements	may	breach	or	may	be	unable	to	perform	their	obligations.	We	may	not	be	able	to	enter	into replacement	agreements	on	terms	as	favorable	as	our	existing	agreements,	or	at	all.	If	we	were	unable	to	enter	into	replacement	PPAs,	these	businesses	may	have	to	sell power	at	market	prices.

The	failure	of	any	supplier	or	customer	to	fulfill	its	contractual	obligations	to	The	AES	Corporation	or	our	subsidiaries	could	have	a	material	adverse	effect	on	our financial	results.	Consequently,	the	financial	performance	of	our	facilities	is	dependent	on	the	credit	quality	of,	and	continued	performance	by,	suppliers	and	customers.

# The	market	pricing	of	our	common	stock	has	been	volatile	and	may	continue	to	be	volatile	in	future	periods.

The	market	price	for	our	common	stock	has	been	volatile	in	the	past,	and	the	price	of	our	common	stock	could	fluctuate	substantially	in	the	future.	Stock	price movements	on	a	quarter	by	quarter	basis	for	the	past	two	years	are	set	forth	in	Item	5.—Market—Market	Information	of	this	Form	10-K.	Factors	that	could	affect	the price	of	our	common	stock	in	the	future	include	general	conditions	in	our	industry,	in	the	power	markets	in	which	we	participate	and	in	the	world,	including environmental	and	economic	developments,	over	which	we	have	no	control,	as	well	as	developments	specific	to	us,	including,	risks	that	could	result	in	revenue	and earnings	volatility	as	well	as	other	risk	factors	described	in	this	Item	1A.—Risk	Factors	and	those	matters	described	in	Item	7.—Management's	Discussion	and	Analysis of	Financial	Conditions	and	Results	of	Operations.

# Risks	Associated	with	our	Operations

# We	do	a	significant	amount	of	business	outside	the	United	States,	including	in	developing	countries,	which	presents	significant	risks.

A	significant	amount	of	our	revenue	is	generated	outside	the	United	States	and	a	significant	portion	of	our	international	operations	is	conducted	in	developing countries.	Part	of	our	growth	strategy	is	to	expand	our	business	in	developing	countries	because	the	growth	rates	and	the	opportunity	to	implement	operating improvements	and	achieve	higher	operating	margins	may	be	greater	than	those	typically	achievable	in	more	developed	countries.	International	operations,	particularly the	operation,	financing	and	development	of	projects	in	developing	countries,	entail	significant	risks	and	uncertainties,	including,	without	limitation:

•economic,	social	and	political	instability	in	any	particular	country	or	region;

•adverse	changes	in	currency	exchange	rates;

•government	restrictions	on	converting	currencies	or	repatriating	funds;

•unexpected	changes	in	foreign	laws	and	regulations	or	in	trade,	monetary	or	fiscal	policies;

•high	inflation	and	monetary	fluctuations;

•restrictions	on	imports	of	coal,	oil,	gas	or	other	raw	materials	required	by	our	generation	businesses	to	operate;

•threatened	or	consummated	expropriation	or	nationalization	of	our	assets	by	foreign	governments;

•difficulties	in	hiring,	training	and	retaining	qualified	personnel,	particularly	finance	and	accounting	personnel	with	GAAP	expertise;

•unwillingness	of	governments,	government	agencies,	similar	organizations	or	other	counterparties	to	honor	their	contracts;

•unwillingness	of	governments,	government	agencies,	courts	or	similar	bodies	to	enforce	contracts	that	are	economically	advantageous	to	subsidiaries	of	the Company	and	economically	unfavorable	to	counterparties,	against	such	counterparties,	whether	such	counterparties	are	governments	or	private	parties;

•inability	to	obtain	access	to	fair	and	equitable	political,	regulatory,	administrative	and	legal	systems;

•adverse	changes	in	government	tax	policy;

•difficulties	in	enforcing	our	contractual	rights	or	enforcing	judgments	or	obtaining	a	favorable	result	in	local	jurisdictions;	and •potentially	adverse	tax	consequences	of	operating	in	multiple	jurisdictions.

Any	of	these	factors,	by	itself	or	in	combination	with	others,	could	materially	and	adversely	affect	our	business,	results	of	operations	and	financial	condition.	For example,	partly	in	response	to	challenging	business	and	political	conditions	in	Kazakhstan,	in	2008,	we	sold	certain	businesses	in	that	country.	As	another	example,	in the	second	quarter	of	2007,	we	sold	our	stake	in	EDC	to	Petróleos	de	Venezuela,	S.A.,	the	state-owned	energy	company	in	Venezuela	after	Venezuelan	President	Hugo Chavez	threatened	to	expropriate	the	electricity	business	in	Venezuela.	In	connection	with	the	sale,	we	recognized	an	impairment	charge	of	approximately	$680	million. In	addition,	our	Latin	American	operations	experience	volatility	in	revenues	and	gross	margin	which	have	caused	and	are	expected	to	cause	significant	volatility	in	our results	of	operations	and	cash	flows.	The	volatility	is	caused	by	regulatory	and	economic	difficulties,	political	instability	and	currency	devaluations	being	experienced	in many	of	these	countries.	This	volatility	reduces	the	predictability	and	enhances	the	uncertainty	associated	with	cash	flows	from	these	businesses.

# The	operation	of	power	generation	and	distribution	facilities	involves	significant	risks	that	could	adversely	affect	our	financial	results.	We	and/or	our subsidiaries	may	not	have	adequate	insurance	coverage	for	liabilities.

We	are	in	the	business	of	generating	and	distributing	electricity,	which	involves	certain	risks	that	can	adversely	affect	financial	and	operating	performance, including:

•changes	in	the	availability	of	our	generation	facilities	or	distribution	systems	due	to	increases	in	scheduled	and	unscheduled	plant	outages,	equipment failure,	failure	of	transmission	systems,	labor	disputes,	disruptions	in	fuel	supply,	inability	to	comply	with	regulatory	or	permit	requirements	or	catastrophic events	such	as	fires,	floods,	storms,	hurricanes,	earthquakes,	explosions,	terrorist	acts	or	other	similar	occurrences;	and

•changes	in	our	operating	cost	structure	including,	but	not	limited	to,	increases	in	costs	relating	to:	gas,	coal,	oil	and	other	fuel;	fuel	transportation; purchased	electricity;	operations,	maintenance	and	repair;	environmental	compliance,	including	the	cost	of	purchasing	emissions	offsets	and	capital expenditures	to	install	environmental	emission	equipment;	transmission	access;	and	insurance.

Our	businesses	require	reliable	transportation	sources	(including	related	infrastructure	such	as	roads,	ports	and	rail),	power	sources	and	water	sources	to	access and	conduct	operations.	The	availability	and	cost	of	this	infrastructure	affects	capital	and	operating	costs	and	levels	of	production	and	sales.	Limitations,	or	interruptions in	transportation	including	as	a	result	of	third	parties	intentionally	or	unintentionally	disrupting	the	facilities	of	our	subsidiaries,	could	impede	their	ability	to	produce electricity.	This	could	have	a	material	adverse	effect	on	our	businesses'	results	of	operations,	financial	condition	and	prospects.

In	addition,	a	portion	of	our	generation	facilities	were	constructed	many	years	ago.	Older	generating	equipment	may	require	significant	capital	expenditures	for maintenance.	This	equipment	is	also	likely	to	require	periodic	upgrading	and	improvement.	Breakdown	or	failure	of	one	of	our	operating	facilities	may	prevent	the facility	from	performing	under	applicable	power	sales	agreements	which,	in	certain	situations,	could	result	in	termination	of	a	power	purchase	or	other	agreement	or incurring	a	liability	for	liquidated	damages	and/or	other	penalties.

As	a	result	of	the	above	risks	and	other	potential	hazards	associated	with	the	power	generation	and	distribution	industries,	we	may	from	time	to	time	become exposed	to	significant	liabilities	for	which	we	may	not	have	adequate	insurance	coverage.	Power	generation	involves	hazardous	activities,	including	acquiring, transporting	and	unloading	fuel,	operating	large	pieces	of	rotating	equipment	and	delivering	electricity	to

transmission	and	distribution	systems.	In	addition	to	natural	risks,	such	as	earthquakes,	floods,	lightning,	hurricanes	and	wind,	hazards,	such	as	fire,	explosion,	collapse and	machinery	failure,	are	inherent	risks	in	our	operations	which	may	occur	as	a	result	of	inadequate	internal	processes,	technological	flaws,	human	error	or	certain external	events.	The	control	and	management	of	these	risks	depend	upon	adequate	development	and	training	of	personnel	and	on	the	existence	of	operational procedures,	preventative	maintenance	plans	and	specific	programs	supported	by	quality	control	systems	which	reduce,	but	do	not	eliminate	the	possibility	of	the occurrence	and	impact	of	these	risks.

The	hazards	described	above	can	cause	significant	personal	injury	or	loss	of	life,	severe	damage	to	and	destruction	of	property,	plant	and	equipment, contamination	of,	or	damage	to,	the	environment	and	suspension	of	operations.	The	occurrence	of	any	one	of	these	events	may	result	in	our	being	named	as	a	defendant in	lawsuits	asserting	claims	for	substantial	damages,	environmental	cleanup	costs,	personal	injury	and	fines	and/or	penalties.	We	maintain	an	amount	of	insurance protection	that	we	believe	is	customary,	but	there	can	be	no	assurance	that	our	insurance	will	be	sufficient	or	effective	under	all	circumstances	and	against	all	hazards	or liabilities	to	which	we	may	be	subject.	A	claim	for	which	we	are	not	fully	insured	or	insured	at	all	could	hurt	our	financial	results	and	materially	harm	our	financial condition.	Further,	due	to	rising	insurance	costs	and	changes	in	the	insurance	markets,	we	cannot	provide	assurance	that	insurance	coverage	will	continue	to	be	available on	terms	similar	to	those	presently	available	to	us	or	at	all.	Any	losses	not	covered	by	insurance	could	have	a	material	adverse	effect	on	our	financial	condition,	results	of operations	or	cash	flows.

Our	businesses'	insurance	does	not	cover	every	potential	risk	associated	with	its	operations.	Adequate	coverage	at	reasonable	rates	is	not	always	obtainable.	In addition,	insurance	may	not	fully	cover	the	liability	or	the	consequences	of	any	business	interruptions	such	as	equipment	failure	or	labor	dispute.	The	occurrence	of	a significant	adverse	event	not	fully	or	partially	covered	by	insurance	could	have	a	material	adverse	effect	on	the	Company's	business,	results	or	operations,	financial condition	and	prospects.

Any	of	the	above	risks	could	have	a	material	adverse	effect	on	our	business	and	results	of	operations.

# Our	inability	to	attract	and	retain	skilled	people	could	have	a	material	adverse	effect	on	our	operations.

Our	operating	success	and	ability	to	carry	out	growth	initiatives	depends	in	part	on	our	ability	to	retain	executives	and	to	attract	and	retain	additional	qualified personnel	who	have	experience	in	our	industry	and	in	operating	a	company	of	our	size	and	complexity,	including	people	in	our	foreign	businesses.	The	inability	to attract	and	retain	qualified	personnel	could	have	a	material	adverse	effect	on	our	business,	because	of	the	difficulty	of	promptly	finding	qualified	replacements.	In particular,	we	routinely	are	required	to	assess	the	financial	and	tax	impacts	of	complicated	business	transactions	which	occur	on	a	worldwide	basis.	These	assessments are	dependent	on	hiring	personnel	on	a	worldwide	basis	with	sufficient	expertise	in	GAAP	to	timely	and	accurately	comply	with	United	States	reporting	obligations.	An inability	to	maintain	adequate	internal	accounting	and	managerial	controls	and	hire	and	retain	qualified	personnel	could	have	an	adverse	affect	on	our	financial	and	tax reporting.

# We	have	contractual	obligations	to	certain	customers	to	provide	full	requirements	service,	which	makes	it	difficult	to	predict	and	plan	for	load	requirements and	may	result	in	increased	operating	costs	to	certain	of	our	businesses.

We	have	contractual	obligations	to	certain	customers	to	supply	power	to	satisfy	all	or	a	portion	of	their	energy	requirements.	The	uncertainty	regarding	the amount	of	power	that	our	power	generation	and	distribution	facilities	must	be	prepared	to	supply	to	customers	may	increase	our	operating	costs.	A	significant	under-	or over-estimation	of	load	requirements	could	result	in	our	facilities	not	having	enough	or	having	too	much	power	to	cover	their	obligations,	in	which	case	we	would	be required	to	buy	or	sell	power	from	or	to	third	parties	at	prevailing	market	prices.	Those	prices	may	not	be	favorable	and	thus	could	increase	our	operating	costs.

# We	may	not	be	able	to	enter	into	long-term	contracts,	which	reduce	volatility	in	our	results	of	operations.	Even	when	we	successfully	enter	into	long-term contracts,	our	generation	businesses	are	often	dependent	on	one	or	a	limited	number	of	customers	and	a	limited	number	of	fuel	suppliers.

Many	of	our	generation	plants	conduct	business	under	long-term	contracts.	In	these	instances,	we	rely	on	power	sales	contracts	with	one	or	a	limited	number	of customers	for	the	majority	of,	and	in	some	cases	all	of,	the	relevant	plant's	output	and	revenues	over	the	term	of	the	power	sales	contract.	The	remaining	terms	of	the power	sales	contracts	range	from	1	to	25	years.	In	many	cases,	we	also	limit	our	exposure	to	fluctuations	in	fuel	prices	by	entering	into	long-term	contracts	for	fuel	with	a limited	number	of	suppliers.	In	these	instances,	the	cash	flows	and	results	of	operations	are	dependent	on	the	continued	ability	of	customers	and	suppliers	to	meet	their obligations	under	the	relevant	power	sales	contract	or	fuel	supply	contract,	respectively.	Some	of	our	long-term	power	sales	agreements	are	at	prices	above	current	spot market	prices	and	some	of	our	long-term	fuel	supply	contracts	are	at	prices	below	current	market	prices.	The	loss	of	significant	power	sales	contracts	or	fuel	supply contracts,	or	the	failure	by	any	of	the	parties	to	such	contracts	that	prevents	us	from	fulfilling	our	obligations	thereunder,	could	have	a	material	adverse	impact	on	our business,	results	of	operations	and	financial	condition.	In	addition,	depending	on	market	conditions	and	regulatory	regimes,	it	may	be	difficult	for	us	to	secure	long-term contracts,	either	where	our	current	contracts	are	expiring	or	for	new	development	projects.	The	inability	to	enter	into	long-term	contracts	could	require	many	of	our businesses	to	purchase	inputs	at	market	prices	and	sell	electricity	into	spot	markets,	which	may	not	be	favorable.	For	example,	during	the	past	several	years,	various governmental	authorities	in	Europe	have	terminated	or	declined	to	fulfill	their	obligations	under	long-term	contracts	with	our	subsidiaries.	In	2008,	as	part	of	the accession	to	the	European	Union,	the	Hungarian	government	terminated	all	long-term	PPAs,	including	AES	Tisza's	PPA,	as	of	December	31,	2008.	Partly	as	a	result	of the	termination	AES	Tisza's	results	of	operations	declined	and	we	were	required	to	record	an	$85	million	asset	impairment	charge	for	AES	Tisza	in	the	third	quarter	of 2010.	Kilroot	in	Northern	Ireland	received	notice	from	the	Utility	Regulator	directing	Kilroot	and	NIE	Energy	to	terminate	the	Generating	Unit	Agreements	for	the	two coal	fired	units	effective	November	1,	2010	and,	as	a	result,	the	performance	(and	contributions	to	income	and	cash	flow)	from	Kilroot	will	decline	in	2011	when compared	to	prior	years.	Furthermore,	these	businesses	(and	any	other	businesses	whose	long-term	contracts	may	be	challenged)	may	have	to	sell	electricity	into	the	spot markets.	Because	of	the	volatile	nature	of	inputs	and	power	prices,	the	inability	to	secure	long-term	contracts	could	generate	increased	volatility	in	our	earnings	and	cash flows	and	could	generate	substantial	losses	(or	result	in	a	write-down	of	assets),	which	could	have	a	material	impact	on	our	business	and	results	of	operations.

We	have	sought	to	reduce	counterparty	credit	risk	under	our	long-term	contracts	in	part	by	entering	into	power	sales	contracts	with	utilities	or	other	customers	of strong	credit	quality	and	by	obtaining	guarantees	from	certain	sovereign	governments	of	the	customer's	obligations.	However,	many	of	our	customers	do	not	have,	or have	failed	to	maintain,	an	investment-grade	credit	rating,	and	our	Generation	business	cannot	always	obtain	government	guarantees	and	if	they	do,	the	government does	not	always	have	an	investment	grade	credit	rating.	We	have	also	sought	to	reduce	our	credit	risk	by	locating	our	plants	in	different	geographic	areas	in	order	to mitigate	the	effects	of	regional	economic	downturns.	However,	there	can	be	no	assurance	that	our	efforts	to	mitigate	this	risk	will	be	successful.	These	risks	have increased	as	a	result	of	the	deteriorating	and	volatile	global	economy.	For	further	discussion	of	these	global	economic	conditions	and	their	potential	impact	on	the Company,	see	Item	7.—Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations—Global	Economic	Conditions	in	this	Form	10-K.

# Competition	is	increasing	and	could	adversely	affect	us.

The	power	production	markets	in	which	we	operate	are	characterized	by	numerous	strong	and	capable	competitors,	many	of	whom	may	have	extensive	and diversified	developmental	or	operating	experience	(including	both	domestic	and	international)	and	financial	resources	similar	to	or	greater	than	ours.	Further,	in	recent years,	the	power	production	industry	has	been	characterized	by	strong	and	increasing	competition	with	respect	to	both	obtaining	power	sales	agreements	and	acquiring existing	power	generation	assets.	In	certain

markets,	these	factors	have	caused	reductions	in	prices	contained	in	new	power	sales	agreements	and,	in	many	cases,	have	caused	higher	acquisition	prices	for	existing assets	through	competitive	bidding	practices.	The	evolution	of	competitive	electricity	markets	and	the	development	of	highly	efficient	gas-fired	power	plants	have	also caused,	or	are	anticipated	to	cause,	price	pressure	in	certain	power	markets	where	we	sell	or	intend	to	sell	power.	These	competitive	factors	could	have	a	material adverse	effect	on	us.

# Some	of	our	subsidiaries	participate	in	defined	benefit	pension	plans	and	their	net	pension	plan	obligations	may	require	additional	significant	contributions.

Certain	of	our	subsidiaries	have	defined	benefit	pension	plans	covering	substantially	all	of	their	respective	employees.	Of	the	twenty	nine	defined	benefit	plans, three	are	at	United	States	subsidiaries	and	the	remaining	plans	are	at	foreign	subsidiaries.	Pension	costs	are	based	upon	a	number	of	actuarial	assumptions,	including	an expected	long-term	rate	of	return	on	pension	plan	assets,	the	expected	life	span	of	pension	plan	beneficiaries	and	the	discount	rate	used	to	determine	the	present	value	of future	pension	obligations.	Any	of	these	assumptions	could	prove	to	be	wrong,	resulting	in	a	shortfall	of	pension	plan	assets	compared	to	pension	obligations	under	the pension	plan.	The	Company	periodically	evaluates	the	value	of	the	pension	plan	assets	to	ensure	that	they	will	be	sufficient	to	fund	the	respective	pension	obligations. The	Company's	exposure	to	market	volatility	is	mitigated	to	some	extent	due	to	the	fact	that	the	asset	allocations	in	our	largest	plans	are	more	heavily	weighted	to investments	in	fixed	income	securities	that	have	not	been	as	severely	impacted	by	the	global	recession.	Future	downturns	in	the	debt	and/or	equity	markets,	or	the inaccuracy	of	any	of	our	significant	assumptions	underlying	the	estimates	of	our	subsidiaries'	pension	plan	obligations,	could	result	in	an	increase	in	pension	expense and	future	funding	requirements,	which	may	be	material.	Our	subsidiaries	who	participate	in	these	plans	are	responsible	for	satisfying	the	funding	requirements	required by	law	in	their	respective	jurisdiction	for	any	shortfall	of	pension	plan	assets	compared	to	pension	obligations	under	the	pension	plan.	This	may	necessitate	additional cash	contributions	to	the	pension	plans	that	could	adversely	affect	the	Parent	Company	and	our	subsidiaries'	liquidity.

For	additional	information	regarding	the	funding	position	of	the	Company's	pension	plans,	see	Item	7.—Management's	Discussion	and	Analysis	of	Financial Condition	and	Results	of	Operations—Critical	Accounting—Estimates—Pension	and	Postretirement	Obligations	and	Note	13	to	our	Consolidated	Financial	Statements included	in	this	Form	10-K.

# Our	business	is	subject	to	substantial	development	uncertainties.

Certain	of	our	subsidiaries	and	affiliates	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,	commissioning	delays,	or	the	potential	for	termination	of	the	power sales	contract	as	a	result	of	a	failure	to	meet	certain	milestones.	Timing	of	equipment	purchases	can	also	pose	financial	risks	to	the	Company.	As	part	of	our	development process,	we	attempt	to	make	purchases	of	equipment	and/or	materials	as	needed.	However,	from	time	to	time,	there	may	be	excess	demand	for	certain	types	of	equipment with	substantial	delays	between	the	time	we	place	orders	and	receive	delivery.	In	those	instances,	to	avoid	construction	delays	and	costs	associated	with	the	inability	to own	and	place	such	equipment	and/or	materials	into	service	when	needed	in	the	construction	process,	we	may	place	orders	well	in	advance	of	deployment.	In	some cases,	we	may	order	such	equipment	and/or	materials	without	yet	having	a	specific	project	where	the	equipment	and/or	materials	will	be	deployed,	in	anticipation	that equipment	and	materials	will	be	needed	at	the	time	of	delivery.	However,	there	is	a	risk	that	at	the	time	of	delivery,	we	are	required	to	accept	delivery	and	pay	for	such equipment	and/or	materials,	even	though	no	project	has	materialized	where	these	items	will	be	used.	This	can	result	in	our	having	to	incur	material	equipment	and/or material	costs,	with	no	deployment	plan	at	delivery.	Financing	risk	has	also	increased	as	a	result	of	the	deterioration	of	the	global	economy	and	the	crisis	in	the	financial markets	and,	as	a	result,	we	may	forgo	certain	development	opportunities.	We	believe	that	capitalized	costs	for	projects	under	development	are

recoverable;	however,	there	can	be	no	assurance	that	any	individual	project	will	be	completed	and	reach	commercial	operation.	If	these	development	efforts	are	not successful,	we	may	abandon	a	project	under	development	and	write	off	the	costs	incurred	in	connection	with	such	project.	At	the	time	of	abandonment,	we	would expense	all	capitalized	development	costs	incurred	in	connection	therewith	and	could	incur	additional	losses	associated	with	any	related	contingent	liabilities.

Certain	delays	have	occurred	at	the	670	MW	Maritza	coal-fired	project	in	Bulgaria,	and	the	project	has	not	begun	commercial	operations.	As	noted	in	Note	10 —Debt	included	in	Item	8	of	this	Form	10-K,	as	a	result	of	these	delays	the	project	debt	is	in	default	and	the	Company	is	working	with	its	lenders	to	resolve	the	default. In	addition,	as	noted	in	Item	3.	—Legal	Proceedings,	the	Company	is	in	litigation	with	the	contractor	regarding	the	cause	of	delays.	At	this	time,	management	believes that	Maritza	will	commence	commercial	operations	for	at	least	some	of	the	project's	capacity	by	the	second	half	of	2011.	However,	commencement	of	commercial operations	could	be	delayed	beyond	this	timeframe.	There	can	be	no	assurance	that	Maritza	will	achieve	commercial	operations,	in	whole	or	in	part,	by	the	second	half of	2011,	resolve	the	default	with	the	lenders	or	prevail	in	the	litigation	referenced	above,	which	could	result	in	the	loss	of	some	or	all	of	our	investment	or	require additional	funding	for	the	project.	Any	of	these	events	could	have	a	material	adverse	effect	on	the	Company's	operating.

In	June	2009,	the	Supreme	Court	of	Chile	affirmed	a	January	2009	decision	of	the	Valparaiso	Court	of	Appeals	("VCA")	that	the	environmental	permit	for Empresa	Electrica	Campiche's	("EEC")	thermal	power	plant	("Plant")	was	not	properly	granted	and	illegal.	Construction	of	the	Plant	stopped	as	a	consequence	of	the Supreme	Court's	decision.	In	December	2009,	Chilean	authorities	approved	new	land	use	regulations	that	entitled	EEC	to	apply	for	a	new	environmental	permit.	EEC applied	for	a	new	environmental	permit	in	January	2010	and	permit	approval	was	granted	by	the	Environmental	Authority	in	February	2010.	In	March	2010,	the	Mayor of	Puchuncaví	and	another	third	party	challenged	the	new	environmental	permit	before	the	VCA.	The	parties	later	entered	into	a	settlement	agreement	pursuant	to	which the	challenge	to	the	new	environmental	permit	was	withdrawn	in	July	2010.	In	addition,	the	construction	permit	that	is	required	to	resume	construction	of	the	Plant	was issued	by	the	Municipality	in	August	2010.	In	September	2010,	neighbors	of	Puchuncaví	challenged	the	construction	permit	filing	claims	in	the	VCA.	In	November 2010,	the	VCA	rejected	the	claims.	The	challenging	parties	subsequently	filed	appeals	with	the	Supreme	Court.	In	January	2011,	the	Supreme	Court	confirmed	the decision	of	the	VCA,	finally	rejecting	the	constitutional	action.	EEC	has	resumed	construction	of	the	Plant.

# Our	acquisitions	may	not	perform	as	expected.

Historically,	acquisitions	have	been	a	significant	part	of	our	growth	strategy.	We	may	continue	to	grow	our	business	through	acquisitions.	Although	acquired businesses	may	have	significant	operating	histories,	we	will	have	a	limited	or	no	history	of	owning	and	operating	many	of	these	businesses	and	possibly	limited	or	no experience	operating	in	the	country	or	region	where	these	businesses	are	located.	Some	of	these	businesses	may	be	government	owned	and	some	may	be	operated	as	part of	a	larger	integrated	utility	prior	to	their	acquisition.	If	we	were	to	acquire	any	of	these	types	of	businesses,	there	can	be	no	assurance	that:

•	 we	will	be	successful	in	transitioning	them	to	private	ownership;

•such	businesses	will	perform	as	expected;

•integration	or	other	one-time	costs	will	not	be	greater	than	expected;

•	 we	will	not	incur	unforeseen	obligations	or	liabilities;

•such	business	will	generate	sufficient	cash	flow	to	support	the	indebtedness	incurred	to	acquire	them	or	the	capital	expenditures	needed	to	develop	them;	or

•the	rate	of	return	from	such	businesses	will	justify	our	decision	to	invest	our	capital	to	acquire	them.

# In	some	of	our	joint	venture	projects	and	businesses,	we	have	granted	protective	rights	to	minority	holders	or	we	own	less	than	a	majority	of	the	equity	in	the project	or	business	and	do	not	manage	or	otherwise	control	the	project	or	business,	which	entails	certain	risks.

We	have	invested	in	some	joint	ventures	where	we	own	less	than	a	majority	of	the	voting	equity	in	the	venture.	Very	often,	one	of	our	subsidiaries	seeks	to	exert	a degree	of	influence	with	respect	to	the	management	and	operation	of	projects	or	businesses	in	which	we	have	less	than	a	majority	of	the	ownership	interests	by	operating the	project	or	business	pursuant	to	a	management	contract,	negotiating	to	obtain	positions	on	management	committees	or	to	receive	certain	limited	governance	rights, such	as	rights	to	veto	significant	actions.	However,	we	do	not	always	have	this	type	of	control	over	the	project	or	business	in	every	instance;	and	we	may	be	dependent on	our	co-venturers	to	operate	such	projects	or	businesses.	Our	co-venturers	may	not	have	the	level	of	experience,	technical	expertise,	human	resources,	management and	other	attributes	necessary	to	operate	these	projects	or	businesses	optimally.	The	approval	of	co-venturers	also	may	be	required	for	us	to	receive	distributions	of	funds from	projects	or	to	transfer	our	interest	in	projects	or	businesses.

In	some	joint	venture	agreements	where	we	do	have	majority	control	of	the	voting	securities,	we	have	entered	into	shareholder	agreements	granting	protective minority	rights	to	the	other	shareholders.	For	example,	Companhia	Brasiliana	de	Energia	("Brasiliana")	is	a	holding	company	in	which	we	have	a	controlling	equity interest	and	through	which	we	own	three	of	our	four	Brazilian	businesses:	Eletropaulo,	Tietê	and	Uruguaiana.	We	entered	into	a	shareholders'	agreement	with	an affiliate	of	the	Brazilian	National	Development	Bank	("BNDES")	which	owns	more	than	49%	of	the	voting	equity	of	Brasiliana.	Among	other	things,	the	shareholders' agreement	requires	the	consent	of	both	parties	before	taking	certain	corporate	actions,	grants	both	parties	rights	of	first	refusal	in	connection	with	the	sale	of	interests	in Brasiliana	and	grants	certain	drag-along	rights	to	BNDES.	In	May	2007,	BNDES	notified	us	that	it	intends	to	sell	all	of	its	interest	in	Brasiliana	pursuant	to	a	public auction	(the	"Brasiliana	Sale").	BNDES	also	informed	us	that	if	we	fail	to	exercise	our	right	of	first	refusal	to	purchase	all	of	its	interest	in	Brasiliana,	then	BNDES intends	to	exercise	its	drag-along	rights	under	the	shareholders'	agreement	and	cause	us	to	sell	all	of	our	interests	in	Brasiliana	in	the	Brasiliana	Sale	as	well.	BNDES has	since	suspended	the	auction;	however,	BNDES	may	determine	to	recommence	a	sale	process	in	the	future.	In	that	event,	after	the	auction,	if	a	third	party	offer	has been	received	in	the	Brasiliana	Sale,	we	will	have	30	days	to	exercise	our	right	of	first	refusal	to	purchase	all	of	BNDES's	interest	in	Brasiliana	on	the	same	terms	as	the third-party	offer.	If	we	do	not	exercise	this	right	and	BNDES	proceeds	to	exercise	its	drag-along	rights,	then	we	may	be	forced	to	sell	all	of	our	interest	in	Brasiliana. Due	to	the	uncertainty	in	the	sale	price	at	this	point	in	time,	we	are	uncertain	whether	we	will	exercise	our	right	of	first	refusal	should	BNDES	receive	a	valid	third-party offer	in	the	Brasiliana	Sale	and,	if	we	do,	whether	we	would	do	it	alone	or	with	joint	venture	partners.	Even	if	we	desire	to	exercise	our	right	of	first	refusal,	we	cannot assure	that	we	will	have	the	cash	on	hand	or	that	debt	or	equity	financing	will	be	available	at	acceptable	terms	in	order	to	purchase	BNDES's	interest	in	Brasiliana.	If	we do	not	exercise	our	right	of	first	refusal,	we	cannot	be	assured	that	we	will	not	have	to	record	a	loss	if	the	sale	price	is	below	the	book	value	of	our	investment	in Brasiliana.

# Our	renewable	energy	projects	and	other	initiatives	face	considerable	uncertainties	including,	development,	operational	and	regulatory	challenges.

AES	Wind	Generation,	AES	Solar,	our	greenhouse	gas	emissions	reductions	projects	("GHG	Emissions	Reduction	Projects"),	and	our	investments	in	projects such	as	energy	storage	are	subject	to	substantial	risks.	Projects	of	this	nature	have	been	developed	through	advancement	in	technologies	which	may	not	be	proven	or whose	commercial	application	is	limited,	and	which	are	unrelated	to	our	core	business.	Some	of	these	business	lines	are	dependent	upon	favorable	regulatory	incentives to	support	continued	investment,	and	there	is	significant	uncertainty	about	the	extent	to	which	such	favorable	regulatory	incentives	will	be	available	in	the	future.	For example,	several	European	countries	have	recently	faced	a	debt	crisis,	which	has	or	may	result	in	government	austerity	measures.	If	these	incentives	are	repealed,	or sovereign	governments	are	unable	or	unwilling	to	fulfill	their	commitments	or	maintain	favorable	regulatory	incentives	for	renewables,	this	could	materially	impact	our renewable	businesses,	results	of	operations	and	financial	condition,	and	impact	the	ability	of	the	affected

businesses	to	continue	or	grow	their	operations.	In	addition,	any	of	the	foregoing	could	also	impact	contractual	counterparties	of	our	subsidiaries	in	core	power	or renewables.	If	such	counterparties	are	adversely	impacted,	then	they	may	be	unable	to	meet	their	commitments	to	our	subsidiaries,	which	could	also	have	a	material impact	on	our	results	of	operations.

Furthermore,	production	levels	for	our	wind,	solar,	and	GHG	Emissions	Reduction	Projects	may	be	dependent	upon	adequate	wind,	sunlight,	or	biogas	production which	can	vary	significantly	from	period	to	period,	resulting	in	volatility	in	production	levels	and	profitability.	For	example,	for	our	wind	projects,	wind	resource estimates	are	based	on	historical	experience	when	available	and	on	wind	resource	studies	conducted	by	an	independent	engineer,	and	are	not	expected	to	reflect	actual wind	energy	production	in	any	given	year.	With	regard	to	GHG	Emissions	Reduction	Projects,	there	is	particular	uncertainty	about	whether	agreements	providing incentives	for	reductions	in	greenhouse	gas	emissions,	such	as	the	Kyoto	Protocol,	will	continue	and	whether	countries	around	the	world	will	enact	or	maintain legislation	that	provides	incentives	for	reductions	in	greenhouse	gas	emissions,	without	which	such	projects	may	not	be	economical	or	financing	for	such	projects	may become	unavailable.

As	a	result,	renewable	energy	projects	face	considerable	risk	relative	to	our	core	business,	including	the	risk	that	favorable	regulatory	regimes	expire	or	are adversely	modified.	In	addition,	because	certain	of	these	projects	depend	on	technology	outside	of	our	expertise	in	Generation	and	Utility	businesses,	there	are	risks associated	with	our	ability	to	develop	and	manage	such	projects	profitably.	Furthermore,	at	the	development	or	acquisition	stage,	because	of	the	nascent	nature	of	these industries	or	the	limited	experience	with	the	relevant	technologies,	our	ability	to	predict	actual	performance	results	may	be	hindered	and	the	projects	may	not	perform	as predicted.	There	are	also	risks	associated	with	the	fact	that	many	of	these	projects	exist	in	new	or	emerging	markets,	where	long-term	fixed	price	contracts	for	the	major cost	and	revenue	components	may	be	unavailable,	which	in	turn	may	result	in	these	projects	having	relatively	high	levels	of	volatility.

These	projects	can	be	capital-intensive	and	generally	require	that	we	obtain	third	party	financing,	which	may	be	difficult	to	obtain.	As	a	result,	these	capital constraints	may	reduce	our	ability	to	develop	these	projects.	These	risks	may	be	exacerbated	by	the	current	global	economic	crisis,	including	our	management's increased	focus	on	liquidity,	which	may	also	result	in	slower	growth	in	the	number	of	projects	we	can	pursue.	The	economic	downturn	could	also	impact	the	value	of	our assets	in	these	countries	and	our	ability	to	develop	these	projects.	If	the	value	of	these	assets	decline,	this	could	result	in	a	material	impairment	or	a	series	of	impairments which	are	material	in	the	aggregate,	which	would	adversely	affect	our	financial	statements.

# An	impairment	in	the	carrying	value	of	goodwill	or	long-lived	assets	would	negatively	impact	our	consolidated	results	of	operations	and	net	worth.

Goodwill	is	initially	recorded	at	fair	value	and	is	not	amortized,	but	is	evaluated	for	impairment	at	least	annually,	or	more	frequently	if	impairment	indicators	are present.	In	assessing	the	recoverability	of	goodwill,	we	make	estimates	and	assumptions	about	sales,	operating	margin	growth	rates	and	discount	rates	based	on	our budgets,	business	plans,	economic	projections,	anticipated	future	cash	flows	and	marketplace	data.	There	are	inherent	uncertainties	related	to	these	factors	and management's	judgment	in	applying	these	factors.	The	fair	value	of	a	reporting	unit	has	been	determined	using	an	income	approach	based	on	the	present	value	of	future cash	flows	of	each	reporting	unit.	We	could	be	required	to	evaluate	the	recoverability	of	goodwill	outside	of	the	required	annual	assessment	process	if	we	experience situations,	including	but	not	limited	to,	disruptions	to	the	business,	unexpected	significant	declines	in	operating	results,	divestiture	of	a	significant	component	of	our business	or	adverse	actions	or	assessments	by	a	regulator.	There	could	also	be	impairments	if	our	acquisitions	do	not	perform	as	expected.	See	further	discussion	in	Risk Factor,	"Our	Acquisitions	May	Not	Perform	as	Expected."	These	types	of	events	and	the	resulting	analyses	could	result	in	goodwill	impairment	charges	in	the	future. Impairment	charges	could	substantially	affect	our	financial	results	in	the	periods	of	such	charges.	As	of	December	31,	2010,	we	had	$1.3	billion	of	goodwill,	which represented	approximately	3%	of	total	assets.	If	current	conditions	in	the	global	economy	continue	or	worsen,	this	could	increase	the	risk	that	we	will	have	to

impair	goodwill,	as	further	described	in	Item	7.—Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations—Global	Economic Conditions.

Long-lived	assets	are	initially	recorded	at	fair	value	and	are	amortized	or	depreciated	over	their	useful	lives.	Long-lived	assets	are	evaluated	for	impairment	when impairment	indicators	are	present.	In	assessing	the	recoverability	of	long-lived	assets,	we	make	estimates	and	assumptions	about	sales,	operating	margin	growth	rates, commodity	prices	and	discount	rates	based	on	our	budgets,	business	plans,	economic	projections,	anticipated	future	cash	flows	and	marketplace	data.	There	are	inherent uncertainties	related	to	these	factors	and	management's	judgment	in	applying	these	factors.	Generally,	the	fair	value	of	a	long-lived	asset	or	asset	group	is	determined using	an	income	approach	based	on	the	present	value	of	future	cash	flows	of	each	asset	group.	We	could	be	required	to	evaluate	the	recoverability	of	long-lived	assets	if we	experience	situations,	including	but	not	limited	to,	disruptions	to	the	business,	unexpected	significant	declines	in	operating	results,	divestiture	of	a	significant component	of	our	business	or	adverse	action	or	assessment	by	a	regulator.	These	types	of	events	and	the	resulting	analyses	could	result	in	additional	long-lived	asset impairment	charges	in	the	future.	Impairment	charges	could	substantially	affect	our	financial	results	in	the	periods	of	such	charges.	If	current	conditions	in	the	global economy	continue	or	worsen,	this	could	increase	the	risk	that	we	will	have	to	impair	long-lived	assets,	as	further	described	in	Item	7.—Management's	Discussion	and Analysis	of	Financial	Condition	and	Results	of	Operations—Global	Economic	Conditions.

# Certain	of	our	businesses	are	sensitive	to	variations	in	weather.

Our	businesses	are	affected	by	variations	in	general	weather	conditions	and	unusually	severe	weather.	Our	businesses	forecast	electric	sales	on	the	basis	of	normal weather,	which	represents	a	long-term	historical	average.	While	we	also	consider	possible	variations	in	normal	weather	patterns	and	potential	impacts	on	our	facilities and	our	businesses,	there	can	be	no	assurance	that	such	planning	can	prevent	these	impacts,	which	can	adversely	affect	our	business.	Generally,	demand	for	electricity peaks	in	winter	and	summer.	Typically,	when	winters	are	warmer	than	expected	and	summers	are	cooler	than	expected,	demand	for	energy	is	lower,	resulting	in	less demand	for	electricity	than	forecasted.	Significant	variations	from	normal	weather	where	our	businesses	are	located	could	have	a	material	impact	on	our	results	of operations.

In	addition,	we	are	dependent	upon	hydrological	conditions	prevailing	from	time	to	time	in	the	broad	geographic	regions	in	which	our	hydroelectric	generation facilities	are	located.	If	hydrological	conditions	result	in	droughts	or	other	conditions	that	negatively	affect	our	hydroelectric	generation	business,	our	results	of operations	could	be	materially	adversely	affected.	In	the	past,	our	businesses	in	Latin	America	have	been	negatively	impacted	by	lower	than	normal	rainfall.	Similarly, our	wind	businesses	are	dependent	on	adequate	wind	conditions	while	the	solar	projects	at	AES	Solar	are	dependent	on	sufficient	sunlight.	In	each	case,	inadequate	wind or	sunlight	could	have	a	material	adverse	impact	on	these	businesses.

# Our	operations	are	subject	to	significant	government	regulation	and	our	business	and	results	of	operations	could	be	adversely	affected	by	changes	in	the	law or	regulatory	schemes.

Our	inability	to	predict,	influence	or	respond	appropriately	to	changes	in	law	or	regulatory	schemes,	including	any	inability	to	obtain	expected	or	contracted increases	in	electricity	tariff	rates	or	tariff	adjustments	for	increased	expenses,	could	adversely	impact	our	results	of	operations	or	our	ability	to	meet	publicly	announced projections	or	analysts'	expectations.	Furthermore,	changes	in	laws	or	regulations	or	changes	in	the	application	or	interpretation	of	regulatory	provisions	in	jurisdictions where	we	operate,	particularly	our	Utilities	where	electricity	tariffs	are	subject	to	regulatory	review	or	approval,	could	adversely	affect	our	business,	including,	but	not limited	to:

•changes	in	the	determination,	definition	or	classification	of	costs	to	be	included	as	reimbursable	or	pass-through	costs	to	be	included	in	the	rates	we	charge our	customers,	including	but	not	limited	to	costs	incurred	to	upgrade	our	power	plants	to	comply	with	more	stringent	environmental	regulations;

•changes	in	the	determination	of	what	is	an	appropriate	rate	of	return	on	invested	capital	or	a	determination	that	a	utility's	operating	income	or	the	rates	it charges	customers	is	too	high,	resulting	in	a	reduction	of	rates	or	consumer	rebates;

•changes	in	the	definition	or	determination	of	controllable	or	non-controllable	costs;

•adverse	changes	in	tax	law;

•changes	in	the	definition	of	events	which	may	or	may	not	qualify	as	changes	in	economic	equilibrium;

•changes	in	the	timing	of	tariff	increases;

•other	changes	in	the	regulatory	determinations	under	the	relevant	concessions;	or

•other	changes	related	to	licensing	or	permitting	which	affect	our	ability	to	conduct	business.

Any	of	the	above	events	may	result	in	lower	margins	for	the	affected	businesses,	which	can	adversely	affect	our	business.

In	many	countries	where	we	conduct	business,	the	regulatory	environment	is	constantly	changing	or	the	regulations	can	be	difficult	to	interpret.	As	a	result,	there is	risk	that	we	may	not	properly	interpret	certain	regulations	and	may	not	understand	the	impact	of	certain	regulations	on	our	business.	For	example,	in	October	2006, ANEEL,	which	regulates	our	utility	operations	at	Sul	and	Eletropaulo	in	Brazil,	issued	Normative	Resolution	234	requiring	that	utilities	begin	amortizing	a	liability called	"Special	Obligations"	beginning	with	their	second	tariff	reset	cycle	in	2007	or	a	later	year	as	an	offset	to	depreciation	expense.	As	of	May	23,	2007,	the	date	of	the filing	of	our	2006	Form	10-K,	no	industry	positions	or	any	other	consensus	had	been	reached	regarding	how	ANEEL	guidance	should	be	applied	at	that	date	and accordingly,	no	adjustments	to	the	financial	statements	were	made	relating	to	Special	Obligations	in	Brazil.	Subsequent	to	May	23,	2007,	industry	discussions	occurred and	other	Brazilian	companies	filed	Forms	20-F	with	the	SEC	reflecting	the	impact	of	Resolution	234	in	their	December	31,	2006	financial	statements	differently	from how	the	Company	accounted	for	Resolution	234.	In	the	absence	of	any	significant	regulatory	developments	between	May	23,	2007	and	the	date	of	these	other	filings,	the Company	determined	that	Resolution	234	required	us	to	record	an	adjustment	to	our	Special	Obligations	liability	as	of	December	31,	2006.	In	part,	the	decision	to record	the	adjustment	led	to	the	restatement	of	our	financial	statements	in	the	third	quarter	of	2007.	If	we	face	additional	challenges	interpreting	regulations	or	changes	in regulations,	it	could	have	a	material	adverse	impact	on	our	business.

On	July	21,	2010,	President	Obama	signed	the	Dodd-Frank	Wall	Street	Reform	and	Consumer	Protection	Act	(the	"Dodd-Frank	Act").	While	the	bulk	of regulations	contained	in	the	Dodd-Frank	Act	regulate	financial	institutions	and	their	products,	there	are	several	provisions	related	to	corporate	governance,	executive compensation,	disclosure	and	other	matters	which	relate	to	public	companies	generally.	The	types	of	provisions	described	above	are	currently	not	expected	to	have	a material	impact	on	the	Company	or	its	results	of	operations.	Furthermore,	while	the	Dodd-Frank	Act	substantially	expands	the	regulation	regarding	the	trading,	clearing and	reporting	of	derivative	transactions,	the	Dodd-Frank	Act	provides	for	commercial	end-user	exemptions	which	may	apply	to	our	derivative	transactions,	though	this is	not	certain	since	the	Act	directs	the	SEC,	CFTC	and	listed	companies	to	enact	rules	that	will	clarify	the	Dodd-Frank	Act,	and	such	rulemaking	could	impact	the availability	of	the	commercial	end-user	exemption.	Even	if	the	exemption	is	available,	the	Dodd-Frank	Act	could	still	have	a	material	adverse	impact	on	the	Company, as	the	regulation	of	derivatives	(which	includes	capital	and	margin	requirements	for	non-exempt	companies),	could	limit	the	availability	of	derivative	transactions	that we	use	to	reduce	interest	rate,	commodity	and	currency	risks,	which	would	increase	our	exposure	to	these	risks.	Even	if	derivative	transactions	remain	available,	the costs	to	enter	into	these	transactions	may	increase,	which	could	adversely	affect	the	operating	results	of	certain	projects;	cause	us	to	default	on	certain	types	of	contracts where	we	are	contractually	obligated	to	hedge	certain	risks,	such	as	project	financing	agreements;	prevent	us	from	developing	new	projects	where	interest	rate	hedging	is required;	cause	the	Company	to	abandon	certain	of	its	hedging	strategies	and	transactions,	thereby	increasing	our	exposure	to	interest	rate,	commodity	and	currency	risk; and/or	consume	substantial	liquidity	by	forcing	the	Company	to	post	cash	and/or	other	permitted	collateral	in	support	of	these	derivatives.	Any	of	these	outcomes	could have	a	material	adverse	effect	on	the	Company.

On	June	12,	2009	AES	Kelanitissa	received	a	letter	and	an	invoice	from	the	Director	General,	Public	Utilities	Commission	of	Sri	Lanka	("PUC")	seeking payment	of	an	Annual	Regulatory	Fee	and	pursuant	to	PUC	assurances	on	an	application	for	renewal	of	the	AES	Kelanitissa	generation	license.	The	application	is pursuant	to	an	April	2009	revision	of	the	Sri	Lanka	Electricity	Act	("Electricity	Act"),	which	came	into	force	in	April	2009,	notwithstanding	that	in	March	29,	2001, AES	Kelanitissa	had	been	granted,	and	pre-paid	fees	for,	a	21	year	generation	license	with	effect	from	September	25,	2000	under	the	Electricity	Act,	1950.	AES Kelanitissa	submitted	an	application	to	be	licensed	under	the	revised	legislation	and,	on	August	26,	2009,	PUC	published	its	intention	to	issue	a	generation	license	under the	revised	legislation	to	AES	Kelanitissa	and	other	Independent	Power	Producers	("IPPs")	in	Sri	Lanka.	This	was	consistent	with	assurances	received	from	relevant authorities	that	the	revised	legislation	was	to	be	amended	to	grandfather	IPPs	with	existing	generation	licenses.	In	a	letter	dated	June	21,	2010	from	the	PUC,	AES Kelanitissa	was	informed	that	under	the	new	regulations,	as	amended	in	2009,	AES	Kelanitissa	(Pvt)	Ltd	no	longer	fulfilled	the	eligibility	criteria	to	apply	for	a generation	license.	The	"eligibility	criteria"	to	which	the	letter	refers	is	a	provision	requiring	an	element	of	state	ownership.	Representatives	of	AES	Kelanitissa	have been	informed	that	an	amendment	to	the	Electricity	Act	to	grandfather	existing	IPPs	remains	in	the	legislative	pipeline,	although	it	is	not	possible	to	predict	with certainty	when	or	whether	such	an	amendment	will	be	passed.	In	addition,	AES	Kelanitissa	believes	that	under	Sri	Lankan	law,	it	may	continue	operations	under	the	21 year	license	issued	in	2001.	No	step	has	been	taken	to	date	to	prohibit	AES	Kelanitissa	from	generating	power	and	conducting	its	operations.	However,	in	the	event	that it	is	determined	that	AES	Kelanitissa	may	not	operate	under	its	current	license	or	the	revised	legislation	is	not	amended	(and	PUC	maintains	that	AES	Kelanitissa	is ineligible	for	a	generation	license	or	extension	of	the	Generating	License),	AES	Kelanitissa	may	not	be	able	to	continue	operations	on	grounds	that	it	has	no	license under	the	revised	legislation.	In	that	event,	AES	Kelanitissa	and/or	the	Company	could	face	a	number	of	adverse	consequences,	including	potential	litigation	with counterparties	mitigating	a	write	down	in	the	value	of	the	assets	of	the	business,	continued	default	status	under	its	debt	documents	and/or	other	consequences	which could	have	a	material	impact	on	the	Company	or	its	results	of	operations.

Our	Generation	business	in	the	United	States	is	subject	to	the	provisions	of	various	laws	and	regulations	administered	in	whole	or	in	part	by	the	FERC, including	the	Public	Utility	Regulatory	Policies	Act	of	1978	("PURPA"),	the	Federal	Power	Act,	and	the	EPAct	2005.	Actions	by	the	FERC	and	by	state	utility commissions	can	have	a	material	effect	on	our	operations.

EPAct	2005	authorizes	the	FERC	to	remove	the	obligation	of	electric	utilities	under	Section	210	of	PURPA	to	enter	into	new	contracts	for	the	purchase	or	sale	of electricity	from	or	to	QFs	if	certain	market	conditions	are	met.	Pursuant	to	this	authority,	the	FERC	has	instituted	a	rebuttable	presumption	that	utilities	located	within the	control	areas	of	the	Midwest	Transmission	System	Operator,	Inc.,	PJM	("Pennsylvania,	New	Jersey	and	Maryland")	Interconnection,	L.L.C.,	ISO	New England,	Inc.,	the	New	York	Independent	System	Operator	("NYISO")	and	the	Electric	Reliability	Council	of	Texas,	Inc.	are	not	required	to	purchase	or	sell	power from	or	to	QFs	above	a	certain	size.	In	addition,	the	FERC	is	authorized	under	the	new	law	to	remove	the	purchase/sale	obligations	of	individual	utilities	on	a	case-by- case	basis.	While	the	new	law	does	not	affect	existing	contracts,	as	a	result	of	the	changes	to	PURPA,	our	QFs	may	face	a	more	difficult	market	environment	when	their current	long-term	contracts	expire.

EPAct	2005	repealed	PUHCA	1935	and	enacted	PUHCA	2005	in	its	place.	PUHCA	1935	had	the	effect	of	requiring	utility	holding	companies	to	operate	in geographically	proximate	regions	and	therefore	limited	the	range	of	potential	combinations	and	mergers	among	utilities.	By	comparison,	PUHCA	2005	has	no	such restrictions	and	simply	provides	the	FERC	and	state	utility	commissions	with	enhanced	access	to	the	books	and	records	of	certain	utility	holding	companies.	The	repeal of	PUHCA	1935	removed	barriers	to	mergers	and	other	potential	combinations	which	could	result	in	the	creation	of	large,	geographically	dispersed	utility	holding companies.	These	entities	may	have	enhanced	financial	strength	and	therefore	an	increased	ability	to	compete	with	us	in	the	United	States	generation	market.

In	accordance	with	Congressional	mandates	in	the	EPAct	1992	and	now	in	EPAct	2005,	the	FERC	has	strongly	encouraged	competition	in	wholesale	electric markets.	Increased	competition	may	have	the	effect	of	lowering	our	operating	margins.	Among	other	steps,	the	FERC	has	encouraged	RTOs	and	ISOs	to	develop demand	response	bidding	programs	as	a	mechanism	for	responding	to	peak	electric	demand.	These	programs	may	reduce	the	value	of	our	peaking	assets	which	rely	on very	high	prices	during	a	relatively	small	number	of	hours	to	recover	their	costs.	Similarly,	the	FERC	is	encouraging	the	construction	of	new	transmission	infrastructure in	accordance	with	provisions	of	EPAct	2005.	Although	new	transmission	lines	may	increase	market	opportunities,	they	may	also	increase	the	competition	in	our existing	markets.

While	the	FERC	continues	to	promote	competition,	some	state	utility	commissions	have	reversed	course	and	begun	to	encourage	the	construction	of	generation facilities	by	traditional	utilities	to	be	paid	for	on	a	cost-of-service	basis	by	retail	ratepayers.	Such	actions	have	the	effect	of	reducing	sale	opportunities	in	the	competitive wholesale	generating	markets	in	which	we	operate.

# Our	businesses	are	subject	to	stringent	environmental	laws	and	regulations.

Our	activities	are	subject	to	stringent	environmental	laws	and	regulations	by	many	federal,	regional,	state	and	local	authorities,	international	treaties	and	foreign governmental	authorities.	These	laws	and	regulations	generally	concern	emissions	into	the	air,	effluents	into	the	water,	use	of	water,	wetlands	preservation,	remediation of	contamination,	waste	disposal,	endangered	species	and	noise	regulation,	among	others.	Failure	to	comply	with	such	laws	and	regulations	or	to	obtain	any	necessary environmental	permits	pursuant	to	such	laws	and	regulations	could	result	in	fines	or	other	sanctions.	Environmental	laws	and	regulations	affecting	power	generation	and distribution	are	complex	and	have	tended	to	become	more	stringent	over	time.	Congress	and	other	domestic	and	foreign	governmental	authorities	have	either	considered or	implemented	various	laws	and	regulations	to	restrict	or	tax	certain	emissions,	particularly	those	involving	air	and	water	emissions.	See	the	various	descriptions	of these	laws	and	regulations	contained	in	Item	1.—Business—Regulatory	Matters	of	this	Form	10-K.	These	laws	and	regulations	have	imposed,	and	proposed	laws	and regulations	could	impose	in	the	future,	additional	costs	on	the	operation	of	our	power	plants.	We	have	incurred	and	will	continue	to	incur	significant	capital	and	other expenditures	to	comply	with	these	and	other	environmental	laws	and	regulations.	Changes	in,	or	new,	environmental	restrictions	may	force	us	to	incur	significant expenses	or	expenses	that	may	exceed	our	estimates.	There	can	be	no	assurance	that	we	would	be	able	to	recover	all	or	any	increased	environmental	costs	from	our customers	or	that	our	business,	financial	condition,	including	recorded	asset	values	or	results	of	operations	would	not	be	materially	and	adversely	affected	by	such expenditures	or	any	changes	in	domestic	or	foreign	environmental	laws	and	regulations.

# Our	businesses	are	subject	to	enforcement	initiatives	from	environmental	regulatory	agencies.

The	EPA	has	pursued	an	enforcement	initiative	against	coal-fired	generating	plants	alleging	wide-spread	violations	of	the	new	source	review	and	prevention	of significant	deterioration	provisions	of	the	CAA.	The	EPA	has	brought	suit	against	a	number	of	companies	and	has	obtained	settlements	with	approximately	17 companies	over	such	allegations.	The	allegations	typically	involve	claims	that	a	company	made	major	modifications	to	a	coal-fired	generating	unit	without	proper	permit approval	and	without	installing	best	available	control	technology.	The	principal	focus	of	this	EPA	enforcement	initiative	is	emissions	of	SO 2	and	NO X.	In	connection	with this	enforcement	initiative,	the	EPA	has	imposed	fines	and	required	companies	to	install	improved	pollution	control	technologies	to	reduce	emissions	of	SO 	and	NO X. One	of	our	businesses,	IPL,	is	currently	the	subject	of	such	an	EPA	enforcement	action,	and	another	business,	Eastern	Energy,	has	received	an	information	request	from the	EPA	in	connection	with	a	possible	enforcement	action.	See	Item	3.—Legal	Proceedings	of	this	Form	10-K	for	more	detail	with	respect	to	these	EPA	enforcement actions	and	information	requests.	There	can	be	no	assurance	that	foreign	environmental	regulatory	agencies	in	countries	in	which	our	subsidiaries	operate	will	not pursue	similar	enforcement	initiatives	under	relevant	laws	and	regulations.

# Regulators,	politicians,	non-governmental	organizations	and	other	private	parties	have	expressed	concern	about	greenhouse	gas,	or	GHG,	emissions	and	the potential	risks	associated	with	climate	change	and	are	taking	actions	which	could	have	a	material	adverse	impact	on	our	consolidated	results	of	operations, financial	condition	and	cash	flows.

As	discussed	in	Item	1.—Business—Regulatory	Matters—Environmental	and	Land	Use	Regulations,	at	the	international,	federal	and	various	regional	and	state levels,	rules	are	in	effect	or	policies	are	under	development	to	regulate	GHG	emissions,	thereby	effectively	putting	a	cost	on	such	emissions	in	order	to	create	financial incentives	to	reduce	them.	In	2010,	the	Company's	subsidiaries	operated	businesses	which	had	total	approximate	CO 	emissions	of	77.2	million	metric	tonnes approximately	40	million	of	which	were	emitted	by	businesses	located	in	the	United	States	(both	figures	ownership	adjusted).	The	Company	uses	CO 	emission estimation	methodologies	supported	by	"The	Greenhouse	Gas	Protocol"	reporting	standard	on	GHG	emissions.	For	existing	power	generation	plants,	CO 	emissions	are either	obtained	directly	from	plant	continuous	emission	monitoring	systems	or	calculated	from	actual	fuel	heat	inputs	and	fuel	type	CO 	emission	factors.	The	estimated annual	CO 2	emissions	from	fossil	fuel	electric	power	generation	facilities	of	the	Company's	subsidiaries	that	are	in	construction	or	development	and	have	received	the necessary	air	permits	for	commercial	operations	are	approximately	18	million	metric	tonnes	(ownership	adjusted).	This	overall	estimate	is	based	upon	a	number	of projections	and	assumptions	which	may	prove	to	be	incorrect	such	as	the	forecast	dispatch,	anticipated	plant	efficiency,	fuel	type,	CO 	emissions	and	our	subsidiaries' achieving	completion	of	such	construction	and	development	projects.	However,	it	is	certain	that	the	projects	under	construction	or	development	when	completed	will increase	emissions	of	our	portfolio	and	therefore	could	increase	the	risks	associated	with	emissions	described	below.	Because	there	is	significant	uncertainty	regarding these	estimates,	actual	emissions	from	these	projects	under	construction	or	development	may	vary	substantially	from	these	estimates.

The	subsidiaries	of	the	Company	often	seek	to	pass	on	any	costs	arising	from	CO	emissions	to	contract	counterparties,	but	there	can	be	no	assurance	that	the subsidiaries	of	the	Company	will	effectively	pass	such	costs	onto	the	contract	counterparties	or	that	the	cost	and	burden	associated	with	any	dispute	over	which	party bears	such	costs	would	not	be	burdensome	and	costly	to	the	relevant	subsidiaries	of	the	Company.

Foreign,	federal,	state	or	regional	regulation	of	GHG	emissions	could	have	a	material	adverse	impact	on	the	Company's	financial	performance.	The	actual	impact on	the	Company's	financial	performance	and	the	financial	performance	of	the	Company's	subsidiaries	will	depend	on	a	number	of	factors,	including	among	others,	the degree	and	timing	of	GHG	emissions	reductions	required	under	any	such	legislation	or	regulations,	the	cost	of	emissions	reduction	equipment	the	price	and	availability of	offsets,	the	extent	to	which	market	based	compliance	options	are	available,	the	extent	to	which	our	subsidiaries	would	be	entitled	to	receive	GHG	emissions allowances	without	having	to	purchase	them	in	an	auction	or	on	the	open	market	and	the	impact	of	such	legislation	or	regulation	on	the	ability	of	our	subsidiaries	to recover	costs	incurred	through	rate	increases	or	otherwise.	As	a	result	of	these	factors,	our	cost	of	compliance	could	be	substantial	and	could	have	a	material	impact	on our	results	of	operations.

In	January	2005,	based	on	European	Community	"Directive	2003/87/EC	on	Greenhouse	Gas	Emission	Allowance	Trading,"	the	European	Union	Greenhouse	Gas Emission	Trading	Scheme	("EU	ETS")	commenced	operation	as	the	largest	multi-country	GHG	emission	trading	scheme	in	the	world.	On	February	16,	2005,	the	Kyoto Protocol	became	effective.	The	Kyoto	Protocol	requires	the	40	developed	countries	that	have	ratified	it	to	substantially	reduce	their	GHG	emissions,	including	CO .	To date,	compliance	with	the	Kyoto	Protocol	and	the	EU	ETS	has	not	had	a	material	adverse	effect	on	the	Company's	consolidated	results	of	operations,	financial	condition and	cash	flows.

The	United	States	has	not	ratified	the	Kyoto	Protocol.	In	the	United	States,	there	currently	is	no	legislation	establishing	federal	mandatory	GHG	emission reduction	programs	(including	CO )	affecting	the	electric	power	generation	facilities	of	the	Company's	subsidiaries.	However,	federal	GHG	legislation	has	been proposed	in	the	United	States	Congress	that	would,	if	enacted,	constrain	GHG	emissions,	including	CO ,	and/or	impose	costs	on

us	that	could	be	material	to	our	business	or	results	of	operations.	The	EPA	has	also	initiated	regulations	pertaining	to	GHG	emissions	that	require	new	sources	of	GHG emissions	of	over	100,000	tons	per	year,	and	existing	sources	planning	physical	changes	that	would	increase	their	GHG	emissions	by	more	than	75,000	tons	per	year,	to obtain	new	source	review	permits	from	the	EPA	prior	to	construction	or	modification.

Such	regulations	could	increase	our	costs	directly	and	indirectly	and	have	a	material	adverse	effect	on	our	business	and/or	results	of	operations.	See	Item	1. Business—Regulatory	Matters—Environmental	and	Land	Use	Regulations	of	this	Form	10-K	for	further	discussion	about	these	environmental	agreements,	laws	and regulations.

At	the	state	level,	RGGI,	a	cap-and-trade	program	covering	CO	emissions	from	electric	power	generation	facilities	in	the	Northeast,	became	effective	in	January 2009,	and	the	WCI	is	also	developing	market-based	programs	to	address	GHG	emissions	in	seven	western	states.	In	addition,	several	states,	including	California,	have adopted	comprehensive	legislation	that,	when	effective,	will	require	mandatory	GHG	reductions	from	several	industrial	sectors,	including	the	electric	power	generation industry.	See	Item	1.—Business—Regulatory	Matters—Environmental	and	Land	Use	Regulations	of	this	Form	10-K	for	further	discussion	about	the	United	States	state environmental	regulations	we	face.	At	this	time,	other	than	with	regard	to	RGGI	(further	described	below),	the	Company	cannot	estimate	the	costs	of	compliance	with United	States	federal,	regional	or	state	CO 	emissions	reduction	legislation	or	initiatives,	due	to	the	fact	that	these	proposals	are	in	earlier	stages	of	development	and	any final	regulations	or	legislation,	if	adopted,	could	vary	drastically	from	current	proposals.

The	RGGI	program	became	effective	in	January	2009.	The	first	regional	auction	of	RGGI	allowances	needed	to	be	acquired	by	power	generators	to	comply	with state	programs	implementing	RGGI	was	held	in	September	2008,	with	subsequent	auctions	occurring	approximately	every	quarter.	Our	subsidiaries	in	New	York,	New Jersey,	Connecticut	and	Maryland	are	subject	to	RGGI.	Of	the	approximately	40	million	metric	tonnes	of	CO 	emitted	in	the	United	States	by	our	subsidiaries	in	2010 (ownership	adjusted),	approximately	11.3	million	metric	tonnes	were	emitted	in	United	States	states	participating	in	RGGI.	Over	the	past	three	years,	such	emissions have	averaged	approximately	10.9	million	metric	tonnes.	While	CO 	emissions	from	businesses	operated	by	subsidiaries	of	the	Company	are	calculated	globally	in metric	tonnes,	RGGI	allowances	are	denominated	in	short	tons.	(1	metric	tonne	equals	2,200	pounds	and	1	short	ton	equals	2,000	pounds.)	For	forecasting	purposes,	the Company	has	modeled	the	impact	of	CO 	compliance	based	on	a	3-year	average	of	CO	emissions	for	its	businesses	that	are	subject	to	RGGI	and	that	may	not	be	able	to pass	through	compliance	costs.	The	model	includes	a	conversion	from	metric	tonnes	to	short	tons	as	well	as	the	impact	of	some	market	recovery	by	merchant	plants	and contractual	and	regulatory	provisions.	The	model	also	utilizes	a	price	of	$1.86	per	allowance	under	RGGI.	The	source	of	this	allowance	price	estimate	was	the	clearing price	in	the	recent	RGGI	allowance	auction	held	in	December	2010.	Based	on	these	assumptions,	the	Company	estimates	that	the	RGGI	compliance	costs	could	be approximately	$15	million	for	2011,	which	is	the	last	year	of	the	first	RGGI	compliance	period.	Given	the	fact	that	the	assumptions	utilized	in	the	model	may	prove	to be	incorrect,	there	is	a	significant	risk	that	our	actual	compliance	costs	under	RGGI	will	differ	from	our	estimates	by	a	material	amount	and	that	our	model	could underestimate	our	costs	of	compliance.

In	addition	to	government	regulators,	other	groups	such	as	politicians,	environmentalists	and	other	private	parties	have	expressed	increasing	concern	about	GHG emissions.	For	example,	certain	financial	institutions	have	expressed	concern	about	providing	financing	for	facilities	which	would	emit	GHGs,	which	can	affect	our ability	to	obtain	capital,	or	if	we	can	obtain	capital,	to	receive	it	on	commercially	viable	terms.	In	addition,	rating	agencies	may	decide	to	downgrade	our	credit	ratings based	on	the	emissions	of	the	businesses	operated	by	our	subsidiaries	or	increased	compliance	costs	which	could	make	financing	unattractive.	In	addition,	environmental groups	and	other	private	plaintiffs	have	brought	and	may	decide	to	bring	additional	private	lawsuits	against	the	Company	because	of	its	subsidiaries'	GHG	emissions. The	Company	is	facing	and	may	face	in	the	future	private	lawsuits	relating	to	GHG	emissions	that	may	have	a	material	impact	on	the	Company's	results	of	operations. In	one	recent	case	in	the	United	States,	which	does	not	involve	the	Company,	a	federal	appellate	court	reversed	the	dismissal	by	a	federal	district	court	of	nuisance	and other	claims	against	emitters	of	GHG	based	on	property	damage	allegedly	caused	by	their	contributions	to	global	warming.	While	the	scope	of	relief	sought	in	that	case is

unclear,	the	plaintiffs	in	this	case	evidently	seek	injunctive	relief	to	prevent	or	reduce	further	GHG	emissions.	The	defendants	appealed	the	appellate	court	decision	to	the Supreme	Court	of	the	United	States,	and	the	Supreme	Court	is	expected	to	render	a	decision	in	2011.	If	the	defendants	do	not	prevail,	other	parties	may	be	encouraged	to bring	similar	suits	against	electric	power	generators,	including	the	Company	or	any	of	its	United	States	subsidiaries.	Also,	unless	the	United	States	Congress	acts	to preempt	such	suits	as	part	of	comprehensive	federal	legislation,	additional	lawsuits	may	be	brought	against	the	Company	or	its	subsidiaries.	At	this	stage	of	the litigation,	it	is	impossible	to	predict	whether	such	lawsuits	are	likely	to	prevail	or	result	in	damages	awards.	Consequently,	it	is	impossible	to	determine	whether	such lawsuits	are	likely	to	have	a	material	adverse	effect	on	the	Company's	consolidated	results	of	operations	and	financial	condition.

Furthermore,	according	to	the	Intergovernmental	Panel	on	Climate	Change,	physical	risks	from	climate	change	could	include,	but	are	not	limited	to,	increased runoff	and	earlier	spring	peak	discharge	in	many	glacier	and	snow	fed	rivers,	warming	of	lakes	and	rivers,	an	increase	in	sea	level,	changes	and	variability	in precipitation	and	in	the	intensity	and	frequency	of	extreme	weather	events.	Physical	impacts	may	have	the	potential	to	significantly	affect	the	Company's	business	and operations,	and	any	such	potential	impact	may	render	it	more	difficult	for	our	businesses	to	obtain	financing.	For	example,	extreme	weather	events	could	result	in increased	downtime	and	operation	and	maintenance	costs	at	the	electric	power	generation	facilities	and	support	facilities	of	the	Company's	subsidiaries.	Variations	in weather	conditions,	primarily	temperature	and	humidity	also	would	be	expected	to	affect	the	energy	needs	of	customers.	A	decrease	in	energy	consumption	could decrease	the	revenues	of	the	Company's	subsidiaries.	In	addition,	while	revenues	would	be	expected	to	increase	if	the	energy	consumption	of	customers	increased,	such increase	could	prompt	the	need	for	additional	investment	in	generation	capacity.	Changes	in	the	temperature	of	lakes	and	rivers	and	changes	in	precipitation	that	result	in drought	could	adversely	affect	the	operations	of	the	fossil-fuel	fired	electric	power	generation	facilities	of	the	Company's	subsidiaries.	Changes	in	temperature, precipitation	and	snow	pack	conditions	also	could	affect	the	amount	and	timing	of	hydroelectric	generation.

In	addition	to	potential	physical	risks	noted	by	the	Intergovernmental	Panel	on	Climate	Change,	there	could	be	damage	to	the	reputation	of	the	Company	and	its subsidiaries	due	to	public	perception	of	GHG	emissions	by	the	Company	or	any	of	its	subsidiaries,	and	any	such	negative	public	perception	or	concerns	could	ultimately result	in	a	decreased	demand	for	electric	power	generation	or	distribution	from	our	subsidiaries.	The	level	of	GHG	emissions	made	by	subsidiaries	of	the	Company	is	not a	factor	in	the	compensation	of	executives	of	the	Company.

If	any	of	the	foregoing	risks	materialize,	costs	may	increase	or	revenues	may	decrease	and	there	could	be	a	material	adverse	effect	on	the	electric	power generation	businesses	of	the	Company's	subsidiaries	and	on	the	Company's	consolidated	results	of	operations,	financial	condition	and	cash	flows.

# Tax	legislation	initiatives	or	challenges	to	our	tax	positions	could	adversely	affect	our	results	of	operations	and	financial	condition.

Our	subsidiaries	have	operations	in	the	United	States	and	various	non-United	States	jurisdictions.	As	such,	we	are	subject	to	the	tax	laws	and	regulations	of	the United	States	federal,	state	and	local	governments	and	of	many	non-United	States	jurisdictions.	From	time	to	time,	legislative	measures	may	be	enacted	that	could adversely	affect	our	overall	tax	positions.	There	can	be	no	assurance	that	our	effective	tax	rate	or	tax	payments	will	not	be	adversely	affected	by	these	initiatives.	In addition,	United	States	federal,	state	and	local,	as	well	as	non-United	States,	tax	laws	and	regulations	are	extremely	complex	and	subject	to	varying	interpretations. There	can	be	no	assurance	that	our	tax	positions	will	be	sustained	if	challenged	by	relevant	tax	authorities.

# We	and	our	affiliates	are	subject	to	material	litigation	and	regulatory	proceedings.

We	and	our	affiliates	are	parties	to	material	litigation	and	regulatory	proceedings.	See	Item	3.—Legal	Proceedings	below.	There	can	be	no	assurances	that	the outcome	of	such	matters	will	not	have	a	material	adverse	effect	on	our	consolidated	financial	position.

# The	SEC	is	conducting	an	informal	inquiry	relating	to	our	restatements.

We	have	been	cooperating	with	an	informal	inquiry	by	the	SEC	Staff	concerning	our	past	restatements	and	related	matters,	and	have	been	providing	information and	documents	to	the	SEC	Staff	on	a	voluntary	basis.	Although	we	have	not	received	correspondence	regarding	this	inquiry	for	some	time,	we	have	not	been	advised that	the	matter	is	closed.	Because	we	are	unable	to	predict	the	outcome	of	this	inquiry,	the	SEC	Staff	may	disagree	with	the	manner	in	which	we	have	accounted	for	and reported	the	financial	impact	of	the	adjustments	to	previously	filed	financial	statements	and	there	may	be	a	risk	that	the	inquiry	by	the	SEC	could	lead	to	circumstances in	which	we	may	have	to	further	restate	previously	filed	financial	statements,	amend	prior	filings	or	take	other	actions	not	currently	contemplated.

# ITEM	1B. UNRESOLVED	STAFF	COMMENTS

None.

# ITEM	2. PROPERTIES

We	maintain	offices	in	many	places	around	the	world,	generally	pursuant	to	the	provisions	of	long-	and	short-term	leases,	none	of	which	we	believe	are	material. With	a	few	exceptions,	our	facilities,	which	are	described	in	Item	1	of	this	Form	10-K,	are	subject	to	mortgages	or	other	liens	or	encumbrances	as	part	of	the	project's related	finance	facility.	In	addition,	the	majority	of	our	facilities	are	located	on	land	that	is	leased.	However,	in	a	few	instances,	no	accompanying	project	financing	exists for	the	facility,	and	in	a	few	of	these	cases,	the	land	interest	may	not	be	subject	to	any	encumbrance	and	is	owned	outright	by	the	subsidiary	or	affiliate.

# ITEM	3. LEGAL	PROCEEDINGS

The	Company	is	involved	in	certain	claims,	suits	and	legal	proceedings	in	the	normal	course	of	business,	some	of	which	are	described	below.	The	Company	has accrued	for	litigation	and	claims	where	it	is	probable	that	a	liability	has	been	incurred	and	the	amount	of	loss	can	be	reasonably	estimated.	The	Company	has	evaluated claims	in	accordance	with	the	accounting	guidance	for	contingencies	that	it	deems	both	probable	and	reasonably	estimable	and	accordingly,	has	recorded	aggregate reserves	for	all	claims	for	approximately	$450	million	and	$482	million	as	of	December	31,	2010	and	2009.	These	are	reported	on	the	Consolidated	Balance	Sheet	within "accrued	and	other	liabilities"	and	"other	long-term	liabilities."	A	significant	portion	of	these	reserves	relate	to	employment,	non-income	tax	and	customer	disputes	in international	jurisdictions,	principally	Brazil.	Certain	of	the	Company's	subsidiaries,	principally	in	Brazil,	are	defendants	in	a	number	of	labor	and	employment	lawsuits. The	complaints	generally	seek	unspecified	monetary	damages,	injunctive	relief,	or	other	relief.	The	subsidiaries	have	denied	any	liability	and	intend	to	vigorously defend	themselves	in	all	of	these	proceedings.	There	can	be	no	assurance	that	this	reserve	will	be	adequate	to	cover	all	existing	and	future	claims	or	that	we	will	have	the liquidity	to	pay	such	claims	as	they	arise.

The	Company	believes,	based	upon	information	it	currently	possesses	and	taking	into	account	established	reserves	for	liabilities	and	its	insurance	coverage,	that the	ultimate	outcome	of	these	proceedings	and	actions	is	unlikely	to	have	a	material	effect	on	the	Company's	financial	statements.	However,	even	where	no	reserve	has been	recognized,	it	is	reasonably	possible	that	some	matters	could	be	decided	unfavorably	to	the	Company,	and	could	require	the	Company	to	pay	damages	or	make expenditures	in	amounts	that	could	be	material.

In	1989,	Centrais	Elétricas	Brasileiras	S.A.	("Eletrobrás")	filed	suit	in	the	Fifth	District	Court	in	the	State	of	Rio	de	Janeiro	against	Eletropaulo	Eletricidade	de São	Paulo	S.A.	("EEDSP")	relating	to	the	methodology	for	calculating	monetary	adjustments	under	the	parties'	financing	agreement.	In	April	1999,	the	Fifth	District Court

found	for	Eletrobrás	and	in	September	2001,	Eletrobrás	initiated	an	execution	suit	in	the	Fifth	District	Court	to	collect	approximately	R$1.10	billion	($659	million)	from Eletropaulo	(as	estimated	by	Eletropaulo)	and	a	lesser	amount	from	an	unrelated	company,	Companhia	de	Transmissão	de	Energia	Elétrica	Paulista	("CTEEP") (Eletropaulo	and	CTEEP	were	spun	off	from	EEDSP	pursuant	to	its	privatization	in	1998).	In	November	2002,	the	Fifth	District	Court	rejected	Eletropaulo's	defenses	in the	execution	suit.	Eletropaulo	appealed	and	in	September	2003,	the	Appellate	Court	of	the	State	of	Rio	de	Janeiro	("AC")	ruled	that	Eletropaulo	was	not	a	proper	party to	the	litigation	because	any	alleged	liability	had	been	transferred	to	CTEEP	pursuant	to	the	privatization.	In	June	2006,	the	Superior	Court	of	Justice	("SCJ")	reversed the	Appellate	Court's	decision	and	remanded	the	case	to	the	Fifth	District	Court	for	further	proceedings,	holding	that	Eletropaulo's	liability,	if	any,	should	be	determined by	the	Fifth	District	Court.	Eletropaulo's	subsequent	appeals	to	the	Special	Court	(the	highest	court	within	the	SCJ)	and	the	Supreme	Court	of	Brazil	were	dismissed. Eletrobrás	later	requested	that	the	amount	of	Eletropaulo's	alleged	debt	be	determined	by	an	accounting	expert	appointed	by	the	Fifth	District	Court.	Eletropaulo consented	to	the	appointment	of	such	an	expert,	subject	to	a	reservation	of	rights.	In	February	2010,	the	Fifth	District	Court	appointed	an	accounting	expert	to	determine the	amount	of	the	alleged	debt	and	the	responsibility	for	its	payment	in	light	of	the	privatization,	in	accordance	with	the	methodology	proposed	by	Eletrobrás.	Pursuant to	its	reservation	of	rights,	Eletropaulo	filed	an	interlocutory	appeal	with	the	AC	asserting	that	the	expert	was	required	to	determine	the	issues	in	accordance	with	the methodology	proposed	by	Eletropaulo,	and	that	Eletropaulo	should	be	entitled	to	take	discovery	and	present	arguments	on	the	issues	to	be	determined	by	the	expert.	In April	2010,	the	AC	issued	a	decision	agreeing	with	Eletropaulo's	arguments	and	directing	the	Fifth	District	Court	to	proceed	accordingly.	Eletrobrás	may	restart	the accounting	proceedings	at	the	Fifth	District	Court	at	any	time,	which	would	proceed	according	to	the	AC's	April	2010	decision.	In	the	Fifth	District	Court	proceedings, the	expert's	conclusions	will	be	subject	to	the	Fifth	District	Court's	review	and	approval.	If	Eletropaulo	is	determined	to	be	responsible	for	the	debt,	after	the	amount	of the	alleged	debt	is	determined,	Eletrobrás	will	be	entitled	to	resume	the	execution	suit	in	the	Fifth	District	Court	at	any	time.	If	Eletrobrás	does	so,	Eletropaulo	will	be required	to	provide	security	in	the	amount	of	its	alleged	liability.	In	that	case,	if	Eletrobrás	requests	the	seizure	of	such	security	and	the	Fifth	District	Court	grants	such request,	Eletropaulo's	results	of	operations	may	be	materially	adversely	affected,	and	in	turn	the	Company's	results	of	operations	could	be	materially	adversely	affected. In	addition,	in	February	2008,	CTEEP	filed	a	lawsuit	in	the	Fifth	District	Court	against	Eletrobrás	and	Eletropaulo	seeking	a	declaration	that	CTEEP	is	not	liable	for	any debt	under	the	financing	agreement.	The	parties	are	disputing	the	proper	venue	for	the	CTEEP	lawsuit.	Eletropaulo	believes	it	has	meritorious	defenses	to	the	claims asserted	against	it	and	will	defend	itself	vigorously	in	these	proceedings;	however,	there	can	be	no	assurances	that	it	will	be	successful	in	its	efforts.

In	August	2000,	the	FERC	announced	an	investigation	into	the	organized	California	wholesale	power	markets	to	determine	whether	rates	were	just	and reasonable.	Further	investigations	involved	alleged	market	manipulation.	FERC	requested	documents	from	each	of	the	AES	Southland,	LLC	plants	and	AES Placerita,	Inc.	AES	Southland	and	AES	Placerita	have	cooperated	fully	with	the	FERC	investigations.	AES	Southland	was	not	subject	to	refund	liability	because	it	did not	sell	into	the	organized	spot	markets	due	to	the	nature	of	its	tolling	agreement.	After	hearings	at	FERC,	AES	Placerita	was	found	subject	to	refund	liability	of $588,000	plus	interest	for	spot	sales	to	the	California	Power	Exchange	from	October	2,	2000	to	June	20,	2001.	As	FERC	investigations	and	hearings	progressed, numerous	appeals	on	related	issues	were	filed	with	the	U.S.	Court	of	Appeals	for	the	Ninth	Circuit.	Over	the	years,	the	Ninth	Circuit	issued	several	opinions	that	had	the potential	to	expand	the	scope	of	the	FERC	proceedings	and	increase	refund	exposure	for	AES	Placerita	and	other	sellers	of	electricity.	Following	remand	of	one	of	the Ninth	Circuit	appeals	in	March	2009,	FERC	started	a	new	hearing	process	involving	AES	Placerita	and	other	sellers.	In	May	2009,	AES	Placerita	entered	into	a settlement,	approved	by	FERC	in	July	2009,	concerning	the	claims	before	FERC	against	AES	Placerita	relating	to	the	California	energy	crisis	of	2000-2001,	including the	California	refund	proceeding.	Pursuant	to	the	settlement,	AES	Placerita	paid	$6	million	and	assigned	a	receivable	of	$168,119	due	to	it	from	the	California	Power Exchange	in	return	for	a	release	of	all	claims	against	it	at	FERC	by	the	settling	parties	and	other	consideration.	More	than	98%	of	the	buyers	in	the	market	elected	to	join the	settlement.	A	small	amount	of	AES	Placerita's	settlement	payment	was	placed	in	escrow	for	buyers	that	did	not	join	the	settlement	("non-settling	parties").	It	is unclear	whether	the	escrowed	funds	will	be	enough	to	satisfy	any	additional	sums	that	might	be	determined	to	be	owed	to

non-settling	parties	at	the	conclusion	of	the	FERC	proceedings	concerning	the	California	energy	crisis.	However,	any	such	additional	sums	are	expected	to	be immaterial	to	the	Company's	consolidated	financial	statements.	In	November	2009,	one	non-settling	party,	the	Sacramento	Municipal	Utility	District	("SMUD"),	filed an	appeal	of	the	FERC's	approval	of	the	settlement	which	is	pending	in	the	Ninth	Circuit.	SMUD's	appeal	has	been	stayed	pending	further	order	of	the	court.	The settlement	agreement	is	still	effective	and	will	continue	to	remain	effective	unless	it	is	vacated	by	the	Ninth	Circuit.	SMUD	has	reached	a	settlement	in	principal	with buyers	of	electricity	that,	if	approved	by	FERC,	will	leave	only	immaterial	claims	of	non-settling	parties	against	AES	Placerita.

In	August	2001,	the	Grid	Corporation	of	Orissa,	India,	now	Gridco	Ltd.	("Gridco"),	filed	a	petition	against	the	Central	Electricity	Supply	Company	of	Orissa	Ltd. ("CESCO"),	an	affiliate	of	the	Company,	with	the	Orissa	Electricity	Regulatory	Commission	("OERC"),	alleging	that	CESCO	had	defaulted	on	its	obligations	as	an OERC-licensed	distribution	company,	that	CESCO	management	abandoned	the	management	of	CESCO,	and	asking	for	interim	measures	of	protection,	including	the appointment	of	an	administrator	to	manage	CESCO.	Gridco,	a	state-owned	entity,	is	the	sole	wholesale	energy	provider	to	CESCO.	Pursuant	to	the	OERC's August	2001	order,	the	management	of	CESCO	was	replaced	with	a	government	administrator	who	was	appointed	by	the	OERC.	The	OERC	later	held	that	the Company	and	other	CESCO	shareholders	were	not	necessary	or	proper	parties	to	the	OERC	proceeding.	In	August	2004,	the	OERC	issued	a	notice	to	CESCO,	the Company	and	others	giving	the	recipients	of	the	notice	until	November	2004	to	show	cause	why	CESCO's	distribution	license	should	not	be	revoked.	In	response, CESCO	submitted	a	business	plan	to	the	OERC.	In	February	2005,	the	OERC	issued	an	order	rejecting	the	proposed	business	plan.	The	order	also	stated	that	the CESCO	distribution	license	would	be	revoked	if	an	acceptable	business	plan	for	CESCO	was	not	submitted	to	and	approved	by	the	OERC	prior	to	March	31,	2005.	In its	April	2,	2005	order,	the	OERC	revoked	the	CESCO	distribution	license.	CESCO	has	filed	an	appeal	against	the	April	2,	2005	OERC	order	and	that	appeal	remains pending	in	the	Indian	courts.	In	addition,	Gridco	asserted	that	a	comfort	letter	issued	by	the	Company	in	connection	with	the	Company's	indirect	investment	in	CESCO obligates	the	Company	to	provide	additional	financial	support	to	cover	all	of	CESCO's	financial	obligations	to	Gridco.	In	December	2001,	Gridco	served	a	notice	to arbitrate	pursuant	to	the	Indian	Arbitration	and	Conciliation	Act	of	1996	on	the	Company,	AES	Orissa	Distribution	Private	Limited	("AES	ODPL"),	and	Jyoti	Structures ("Jyoti")	pursuant	to	the	terms	of	the	CESCO	Shareholders	Agreement	between	Gridco,	the	Company,	AES	ODPL,	Jyoti	and	CESCO	(the	"CESCO	arbitration").	In	the arbitration,	Gridco	appeared	to	be	seeking	approximately	$189	million	in	damages,	plus	undisclosed	penalties	and	interest,	but	a	detailed	alleged	damage	analysis	was not	filed	by	Gridco.	The	Company	counterclaimed	against	Gridco	for	damages.	In	June	2007,	a	2-to-1	majority	of	the	arbitral	tribunal	rendered	its	award	rejecting Gridco's	claims	and	holding	that	none	of	the	respondents,	the	Company,	AES	ODPL,	or	Jyoti,	had	any	liability	to	Gridco.	The	respondents'	counterclaims	were	also rejected.	In	September	2007,	Gridco	filed	a	challenge	of	the	arbitration	award	with	the	local	Indian	court.	In	June	2008,	Gridco	filed	a	separate	application	with	the	local Indian	court	for	an	order	enjoining	the	Company	from	selling	or	otherwise	transferring	its	shares	in	Orissa	Power	Generation	Corporation	Ltd.'s	("OPGC"),	an	equity method	investment,	and	requiring	the	Company	to	provide	security	in	the	amount	of	the	contested	damages	in	the	CESCO	arbitration	until	Gridco's	challenge	to	the arbitration	award	is	resolved.	In	June	2010,	a	2-to-1	majority	of	the	arbitral	tribunal	awarded	the	Company	some	of	its	costs	relating	to	the	arbitration.	In	August	2010, Gridco	filed	a	challenge	of	the	cost	award	with	the	local	Indian	court.	The	Company	believes	that	it	has	meritorious	defenses	to	the	claims	asserted	against	it	and	will defend	itself	vigorously	in	these	proceedings;	however,	there	can	be	no	assurances	that	it	will	be	successful	in	its	efforts.

In	early	2002,	Gridco	made	an	application	to	the	OERC	requesting	that	the	OERC	initiate	proceedings	regarding	the	terms	of	OPGC's	existing	PPA	with	Gridco. In	response,	OPGC	filed	a	petition	in	the	Indian	courts	to	block	any	such	OERC	proceedings.	In	early	2005,	the	Orissa	High	Court	upheld	the	OERC's	jurisdiction	to initiate	such	proceedings	as	requested	by	Gridco.	OPGC	appealed	that	High	Court's	decision	to	the	Supreme	Court	and	sought	stays	of	both	the	High	Court's	decision and	the	underlying	OERC	proceedings	regarding	the	PPAs	terms.	In	April	2005,	the	Supreme	Court	granted	OPGC's	requests	and	ordered	stays	of	the	High	Court's decision	and	the	OERC	proceedings	with	respect	to	the	PPA's	terms.	The	matter	is	awaiting	further	hearing.

Unless	the	Supreme	Court	finds	in	favor	of	OPGC's	appeal	or	otherwise	prevents	the	OERC's	proceedings	regarding	the	PPA's	terms,	the	OERC	will	likely	lower	the tariff	payable	to	OPGC	under	the	PPA,	which	would	have	an	adverse	impact	on	OPGC's	financials.	OPGC	believes	that	it	has	meritorious	claims	and	defenses	and	will assert	them	vigorously	in	these	proceedings;	however,	there	can	be	no	assurances	that	it	will	be	successful	in	its	efforts.

In	March	2003,	the	office	of	the	Federal	Public	Prosecutor	for	the	State	of	São	Paulo,	Brazil	("MPF")	notified	AES	Eletropaulo	that	it	had	commenced	an	inquiry related	to	the	BNDES	financings	provided	to	AES	Elpa	and	AES	Transgás	and	the	rationing	loan	provided	to	Eletropaulo,	changes	in	the	control	of	Eletropaulo,	sales	of assets	by	Eletropaulo	and	the	quality	of	service	provided	by	Eletropaulo	to	its	customers,	and	requested	various	documents	from	Eletropaulo	relating	to	these	matters.	In July	2004,	the	MPF	filed	a	public	civil	lawsuit	in	the	Federal	Court	of	São	Paulo	("FSCP")	alleging	that	BNDES	violated	Law	8429/92	(the	Administrative	Misconduct Act)	and	BNDES's	internal	rules	by:	(1)	approving	the	AES	Elpa	and	AES	Transgás	loans;	(2)	extending	the	payment	terms	on	the	AES	Elpa	and	AES	Transgás	loans; (3)	authorizing	the	sale	of	Eletropaulo's	preferred	shares	at	a	stock-market	auction;	(4)	accepting	Eletropaulo's	preferred	shares	to	secure	the	loan	provided	to Eletropaulo;	and	(5)	allowing	the	restructurings	of	Light	Serviços	de	Eletricidade	S.A.	and	Eletropaulo.	The	MPF	also	named	AES	Elpa	and	AES	Transgás	as	defendants in	the	lawsuit	because	they	allegedly	benefited	from	BNDES's	alleged	violations.	In	May	2006,	the	FCSP	ruled	that	the	MPF	could	pursue	its	claims	based	on	the	first, second,	and	fourth	alleged	violations	noted	above.	The	MPF	subsequently	filed	an	interlocutory	appeal	with	the	Federal	Court	of	Appeals	("FCA")	seeking	to	require	the FCSP	to	consider	all	five	alleged	violations.	Also,	in	July	2006,	AES	Elpa	and	AES	Transgás	filed	an	interlocutory	appeal	with	the	FCA,	which	was	subsequently consolidated	with	the	MPF's	interlocutory	appeal,	seeking	a	transfer	of	venue	and	to	enjoin	the	FCSP	from	considering	any	of	the	alleged	violations.	In	June	2009,	the FCA	granted	the	injunction	sought	by	AES	Elpa	and	AES	Transgás	and	transferred	the	case	to	the	Federal	Court	of	Rio	de	Janeiro.	In	May	2010,	the	MPF	filed	an appeal	with	the	Superior	Court	of	Justice	challenging	the	transfer.	The	MPF's	lawsuit	before	the	FCSP	has	been	stayed	pending	a	final	decision	on	the	interlocutory appeals.	AES	Elpa	and	AES	Brasiliana	(the	successor	of	AES	Transgás)	believe	they	have	meritorious	defenses	to	the	allegations	asserted	against	them	and	will	defend themselves	vigorously	in	these	proceedings;	however,	there	can	be	no	assurances	that	they	will	be	successful	in	their	efforts.

AES	Florestal,	Ltd.	("Florestal"),	had	been	operating	a	pole	factory	and	had	other	assets,	including	a	wooded	area	known	as	"Horto	Renner,"	in	the	State	of	Rio Grande	do	Sul,	Brazil	(collectively,	"Property").	Florestal	had	been	under	the	control	of	AES	Sul	("Sul")	since	October	1997,	when	Sul	was	created	pursuant	to	a privatization	by	the	Government	of	the	State	of	Rio	Grande	do	Sul.	After	it	came	under	the	control	of	Sul,	Florestal	performed	an	environmental	audit	of	the	entire operational	cycle	at	the	pole	factory.	The	audit	discovered	200	barrels	of	solid	creosote	waste	and	other	contaminants	at	the	pole	factory.	The	audit	concluded	that	the prior	operator	of	the	pole	factory,	Companhia	Estadual	de	Energia	Elétrica	("CEEE"),	had	been	using	those	contaminants	to	treat	the	poles	that	were	manufactured	at	the factory.	Sul	and	Florestal	subsequently	took	the	initiative	of	communicating	with	Brazilian	authorities,	as	well	as	CEEE,	about	the	adoption	of	containment	and remediation	measures.	The	Public	Attorney's	Office	has	initiated	a	civil	inquiry	(Civil	Inquiry	n.	24/05)	to	investigate	potential	civil	liability	and	has	requested	that	the police	station	of	Triunfo	institute	a	police	investigation	(IP	number	1041/05)	to	investigate	potential	criminal	liability	regarding	the	contamination	at	the	pole	factory. The	parties	filed	defenses	in	response	to	the	civil	inquiry.	The	Public	Attorney's	Office	then	requested	an	injunction	which	the	judge	rejected	on	September	26,	2008. The	Public	Attorney's	office	has	a	right	to	appeal	the	decision.	The	environmental	agency	("FEPAM")	has	also	started	a	procedure	(Procedure	n.	088200567/059)	to analyze	the	measures	that	shall	be	taken	to	contain	and	remediate	the	contamination.	Also,	in	March	2000,	Sul	filed	suit	against	CEEE	in	the	2nd	Court	of	Public Treasure	of	Porto	Alegre	seeking	to	register	in	Sul's	name	the	Property	that	it	acquired	through	the	privatization	but	that	remained	registered	in	CEEE's	name.	During those	proceedings,	AES	subsequently	waived	its	claim	to	re-register	the	Property	and	asserted	a	claim	to	recover	the	amounts	paid	for	the	Property.	That	claim	is pending.	In	November	2005,	the	7th	Court	of	Public	Treasure	of	Porto	Alegre	ruled	that	the	Property	must	be	returned	to	CEEE.	CEEE	has	had	sole	possession	of	Horto Renner	since	September	2006	and	of	the	rest	of	the	Property	since	April	2006.	In	February	2008,	Sul

and	CEEE	signed	a	"Technical	Cooperation	Protocol"	pursuant	to	which	they	requested	a	new	deadline	from	FEPAM	in	order	to	present	a	proposal.	In	March	2008,	the State	Prosecution	office	filed	a	Public	Class	Action	against	AES	Florestal,	AES	Sul	and	CEEE,	requiring	an	injunction	for	the	removal	of	the	alleged	sources	of contamination	and	the	payment	of	an	indemnity	in	the	amount	of	R$6	million	($4	million).	The	injunction	was	rejected	and	the	case	is	in	the	evidentiary	stage	awaiting the	judge's	determination	concerning	the	production	of	expert	evidence.	The	above-referenced	proposal	was	delivered	on	April	8,	2008.	FEPAM	responded	by indicating	that	the	parties	should	undertake	the	first	step	of	the	proposal	which	would	be	to	retain	a	contractor.	In	its	response,	Sul	indicated	that	such	step	should	be undertaken	by	CEEE	as	the	relevant	environmental	events	resulted	from	CEEE's	operations.	It	is	estimated	that	remediation	could	cost	approximately	R$14.7	million ($9	million).	Discussions	between	Sul	and	CEEE	are	ongoing.

In	January	2004,	the	Company	received	notice	of	a	"Formulation	of	Charges"	filed	against	the	Company	by	the	Superintendence	of	Electricity	of	the	Dominican Republic.	In	the	"Formulation	of	Charges,"	the	Superintendence	asserts	that	the	existence	of	three	generation	companies	(Empresa	Generadora	de	Electricidad Itabo,	S.A.	("Itabo"),	Dominican	Power	Partners,	and	AES	Andres	BV)	and	one	distribution	company	(Empresa	Distribuidora	de	Electricidad	del	Este,	S.A.	("Este"))	in the	Dominican	Republic,	violates	certain	cross-ownership	restrictions	contained	in	the	General	Electricity	Law	of	the	Dominican	Republic.	In	February	2004,	the Company	filed	in	the	First	Instance	Court	of	the	National	District	of	the	Dominican	Republic	an	action	seeking	injunctive	relief	based	on	several	constitutional	due process	violations	contained	in	the	"Formulation	of	Charges"	("Constitutional	Injunction").	In	February	2004,	the	Court	granted	the	Constitutional	Injunction	and ordered	the	immediate	cessation	of	any	effects	of	the	"Formulation	of	Charges,"	and	the	enactment	by	the	Superintendence	of	Electricity	of	a	special	procedure	to prosecute	alleged	antitrust	complaints	under	the	General	Electricity	Law.	In	March	2004,	the	Superintendence	of	Electricity	appealed	the	Court's	decision.	In	July	2004, the	Company	divested	any	interest	in	Este.	The	Superintendence	of	Electricity's	appeal	is	pending.	The	Company	believes	it	has	meritorious	defenses	to	the	claims asserted	against	it	and	will	defend	itself	vigorously	in	these	proceedings;	however,	there	can	be	no	assurances	that	it	will	be	successful	in	its	efforts.

In	July	2004,	the	Corporación	Dominicana	de	Empresas	Eléctricas	Estatales	("CDEEE")	filed	lawsuits	against	Itabo,	an	affiliate	of	the	Company,	in	the	First	and Fifth	Chambers	of	the	Civil	and	Commercial	Court	of	First	Instance	for	the	National	District.	CDEEE	alleges	in	both	lawsuits	that	Itabo	spent	more	than	was	necessary to	rehabilitate	two	generation	units	of	an	Itabo	power	plant	and,	in	the	Fifth	Chamber	lawsuit,	that	those	funds	were	paid	to	affiliates	and	subsidiaries	of	AES	Gener	and Coastal	Itabo,	Ltd.	("Coastal"),	a	former	shareholder	of	Itabo,	without	the	required	approval	of	Itabo's	board	of	administration.	In	the	First	Chamber	lawsuit,	CDEEE seeks	an	accounting	of	Itabo's	transactions	relating	to	the	rehabilitation.	In	November	2004,	the	First	Chamber	dismissed	the	case	for	lack	of	legal	basis.	On	appeal,	in October	2005	the	Court	of	Appeals	of	Santo	Domingo	ruled	in	Itabo's	favor,	reasoning	that	it	lacked	jurisdiction	over	the	dispute	because	the	parties'	contracts	mandated arbitration.	The	Supreme	Court	of	Justice	is	considering	CDEEE's	appeal	of	the	Court	of	Appeals'	decision.	In	the	Fifth	Chamber	lawsuit,	which	also	names	Itabo's former	president	as	a	defendant,	CDEEE	seeks	$15	million	in	damages	and	the	seizure	of	Itabo's	assets.	In	October	2005,	the	Fifth	Chamber	held	that	it	lacked jurisdiction	to	adjudicate	the	dispute	given	the	arbitration	provisions	in	the	parties'	contracts.	The	First	Chamber	of	the	Court	of	Appeal	ratified	that	decision	in September	2006.	In	a	related	proceeding,	in	May	2005,	Itabo	filed	a	lawsuit	in	the	U.S.	District	Court	for	the	Southern	District	of	New	York	seeking	to	compel	CDEEE to	arbitrate	its	claims.	The	petition	was	denied	in	July	2005.	Itabo's	appeal	of	that	decision	to	the	U.S.	Court	of	Appeals	for	the	Second	Circuit	has	been	stayed	since September	2006.	Further,	in	September	2006,	in	an	International	Chamber	of	Commerce	arbitration,	an	arbitral	tribunal	determined	that	it	lacked	jurisdiction	to	decide arbitration	claims	concerning	these	disputes.	Itabo	believes	it	has	meritorious	claims	and	defenses	and	will	assert	them	vigorously	in	these	proceedings;	however,	there can	be	no	assurances	that	it	will	be	successful	in	its	efforts.

In	April	2006,	a	putative	class	action	was	filed	in	the	U.S.	District	Court	for	the	Southern	District	of	Mississippi	("District	Court")	on	behalf	of	certain	individual plaintiffs	and	all	residents	and/or	property	owners	in	the	State	of	Mississippi	who	allegedly	suffered	harm	as	a	result	of	Hurricane	Katrina,	and	against	the	Company	and numerous	unrelated	companies,	whose	alleged	greenhouse	gas	emissions	contributed	to	alleged	global

warming	which,	in	turn,	allegedly	increased	the	destructive	capacity	of	Hurricane	Katrina.	The	plaintiffs	assert	unjust	enrichment,	civil	conspiracy/aiding	and	abetting, public	and	private	nuisance,	trespass,	negligence,	and	fraudulent	misrepresentation	and	concealment	claims	against	the	defendants.	The	plaintiffs	seek	damages	relating to	loss	of	property,	loss	of	business,	clean-up	costs,	personal	injuries	and	death,	but	do	not	quantify	their	alleged	damages.	In	August	2007,	the	District	Court	dismissed the	case.	The	plaintiffs	subsequently	appealed	to	the	U.S.	Court	of	Appeals	for	the	Fifth	Circuit,	which,	in	October	2009,	affirmed	the	District	Court's	dismissal	of	the plaintiffs'	unjust	enrichment,	fraudulent	misrepresentation,	and	civil	conspiracy	claims.	However,	the	Fifth	Circuit	reversed	the	District	Court's	dismissal	of	the plaintiffs'	public	and	private	nuisance,	trespass,	and	negligence	claims,	and	remanded	those	claims	to	the	District	Court	for	further	proceedings.	In	February	2010,	the Fifth	Circuit	granted	the	petitions	for	en	banc	rehearing	filed	by	the	Company	and	other	defendants,	and	thereby	vacated	its	October	2009	decision.	In	May	2010,	the Fifth	Circuit	dismissed	the	appeal	on	the	ground	that	it	had	lost	its	quorum	for	en	banc	review.	In	August	2010,	the	plaintiffs	filed	a	petition	for	a	writ	of	mandamus	in the	U.S.	Supreme	Court,	requesting	the	Supreme	Court	to	direct	the	Fifth	Circuit	to	reinstate	the	appeal	and	return	it	to	the	panel	that	issued	the	October	2009	decision.	In January	2011,	the	Supreme	Court	denied	the	petition,	ending	the	case.

In	July	2007,	the	Competition	Committee	of	the	Ministry	of	Industry	and	Trade	of	the	Republic	of	Kazakhstan	(the	"Competition	Committee")	ordered Nurenergoservice,	an	AES	subsidiary,	to	pay	approximately	KZT	18	billion	($120	million)	for	alleged	antimonopoly	violations	in	2005	through	the	first	quarter	of	2007. The	Competition	Committee's	order	was	affirmed	by	the	economic	court	in	April	2008	("April	2008	Decision").	The	economic	court	also	issued	an	injunction	to	secure Nurenergoservice's	alleged	liability,	freezing	Nurenergoservice's	bank	accounts	and	prohibiting	Nurenergoservice	from	transferring	or	disposing	of	its	property.

Nurenergoservice's	subsequent	appeals	to	the	court	of	appeals	were	rejected.	In	February	2009,	the	Antimonopoly	Agency	(the	Competition	Committee's	successor) seized	approximately	KZT	783	million	($5	million)	from	a	frozen	Nurenergoservice	bank	account	in	partial	satisfaction	of	Nurenergoservice's	alleged	damages	liability. However,	on	appeal	to	the	Kazakhstan	Supreme	Court,	in	October	2009,	the	Supreme	Court	annulled	the	decisions	of	the	lower	courts	because	of	procedural irregularities	and	remanded	the	case	to	the	economic	court	for	reconsideration.	On	remand,	in	January	2010,	the	economic	court	reaffirmed	its	April	2008	Decision. Nurenergoservice's	appeals	in	the	court	of	appeals	(first	panel)	and	the	court	of	appeals	(second	panel)	were	unsuccessful.	Nurenergoservice	intends	to	file	a	further appeal	to	the	Kazakhstan	Supreme	Court.	In	separate	but	related	proceedings,	in	August	2007,	the	Competition	Committee	ordered	Nurenergoservice	to	pay approximately	KZT	1.8	billion	($12	million)	in	administrative	fines	for	its	alleged	antimonopoly	violations.	Nurenergoservice's	appeal	to	the	administrative	court	was rejected	in	February	2009.	Given	the	adverse	court	decisions	against	Nurenergoservice,	the	Antimonopoly	Agency	may	attempt	to	seize	Nurenergoservice's	remaining assets,	which	are	immaterial	to	the	Company's	consolidated	financial	statements.	The	Antimonopoly	Agency	has	not	indicated	whether	it	intends	to	assert	claims	against Nurenergoservice	for	alleged	antimonopoly	violations	post	first	quarter	2007.	Nurenergoservice	believes	it	has	meritorious	defenses	to	the	claims	asserted	against	it; however,	there	can	be	no	assurances	that	it	will	prevail	in	these	proceedings.

In	April	2009,	the	Antimonopoly	Agency	initiated	an	investigation	of	the	power	sales	of	Ust-Kamenogorsk	HPP	("UK	HPP")	and	Shulbinsk	HPP,	hydroelectric plants	under	AES	concession	(collectively,	the	"Hydros"),	in	January	through	February	2009.	The	investigation	of	Shulbinsk	HPP	is	ongoing,	but	the	investigation	of UK	HPP	has	been	completed.	The	Antimonopoly	Agency	determined	that	UK	HPP	abused	its	market	position	and	charged	monopolistically	high	prices	for	power	in January	through	February	2009.	The	Agency	sought	an	order	from	the	administrative	court	requiring	UK	HPP	to	pay	an	administrative	fine	of	approximately	KZT 120	million	($1	million)	and	to	disgorge	profits	for	the	period	at	issue,	estimated	by	the	Antimonopoly	Agency	to	be	approximately	KZT	440	million	($3	million).	No fines	or	damages	have	been	paid	to	date,	however,	as	the	proceedings	in	the	administrative	court	have	been	suspended	due	to	the	initiation	of	related	criminal proceedings	against	officials	of	UK	HPP.	The	Hydros	believe	they	have	meritorious	defenses	and	will	assert	them	vigorously	in	these	proceedings;	however,	there	can be	no	assurances	that	they	will	be	successful	in	their	efforts.

In	April	2009,	the	Antimonopoly	Agency	initiated	an	investigation	of	Ust-Kamenogorsk	TETS	LLP's	("UKT")	power	sales	in	2008	through	February	2009.	The Antimonopoly	Agency	subsequently	concluded	that	UKT	abused	its	market	position	and	charged	monopolistically	high	prices	for	power	and	should	pay	an administrative	fine	of	approximately	KZT	136	million	($1	million).	The	Antimonopoly	Agency	later	sought	an	order	from	the	administrative	court	requiring	UKT	to	pay the	fine.	The	administrative	court	proceedings	have	been	suspended	due	to	a	related	criminal	investigation	of	UKT	employees.	If	the	investigation	is	terminated	and	the Antimonopoly	Agency	prevails	in	the	administrative	proceedings,	UKT	may	be	ordered	to	pay	the	administrative	fine	and	disgorge	the	profits	from	the	sales	at	issue, estimated	by	the	Antimonopoly	Agency	to	be	approximately	514	million	KZT	($3	million).	UKT	believes	it	has	meritorious	defenses	and	will	assert	them	vigorously	in these	proceedings;	however,	there	can	be	no	assurances	that	it	will	be	successful	in	its	efforts.

In	December	2007,	an	arbitral	tribunal	terminated	ESSA's	gas	supply	contracts	with	members	of	the	Sierra	Chata	Consortium	in	light	of	the	restrictions	that	had been	placed	on	the	export	of	gas	by	the	Argentine	Republic.	ESSA	thereafter	terminated	its	gas	transportation	contract	with	Transportadora	de	Gas	del	Norte	S.A. ("TGN"),	and	initiated	arbitration	seeking	relief	from	the	obligation	to	pay	the	firm	tariff	under	ESSA's	gas	transportation	contracts	with	Gasoducto	GasAndes (Argentina)	S.A.	("GasAndes	Argentina")	and	Gasoducto	GasAndes	S.A.	("GasAndes	Chile")	or	in	the	alternative,	termination	of	such	contracts.	TGN	(which	later	filed a	lawsuit	against	ESSA	in	Argentina),	GasAndes	Argentina,	and	GasAndes	Chile	disputed	that	the	restrictions	on	the	export	of	gas	justified	the	adjustment	or termination	of	the	respective	gas	transportation	contracts	and	sought	due	tariff	payments.	On	December	29,	2010,	ESSA	reached	settlement	agreements	with	GasAndes Argentina,	GasAndes	Chile,	and	TGN	terminating	the	respective	gas	transportation	contracts	and	resolving	all	pending	legal	disputes	and	potential	future	claims.	ESSA recognized	approximately	$72	million	as	other	expense	for	the	three	months	ended	December	31,	2010	related	to	the	settlement	agreements.	Upon	termination	of	the TGN	gas	transportation	contract,	ESSA	is	no	longer	required	to	pay	certain	charges	imposed	by	the	Argentine	Republic	relating	to	gas	supply	infrastructure.

In	February	2008,	the	Native	Village	of	Kivalina	and	the	City	of	Kivalina,	Alaska,	filed	a	complaint	in	the	U.S.	District	Court	for	the	Northern	District	of California	against	the	Company	and	numerous	unrelated	companies,	claiming	that	the	defendants'	alleged	GHG	emissions	have	contributed	to	alleged	global	warming which,	in	turn,	allegedly	has	led	to	the	erosion	of	the	plaintiffs'	alleged	land.	The	plaintiffs	assert	nuisance	and	concert	of	action	claims	against	the	Company	and	the other	defendants,	and	a	conspiracy	claim	against	a	subset	of	the	other	defendants.	The	plaintiffs	seek	to	recover	relocation	costs,	indicated	in	the	complaint	to	be	from $95	million	to	$400	million,	and	other	unspecified	damages	from	the	defendants.	The	Company	filed	a	motion	to	dismiss	the	case,	which	the	District	Court	granted	in October	2009.	The	plaintiffs	have	appealed	to	the	U.S.	Court	of	Appeals	for	the	Ninth	Circuit.	The	parties	have	briefed	the	appeal	and	are	awaiting	a	date	for	oral argument.	The	Company	believes	it	has	meritorious	defenses	to	the	claims	asserted	against	it	and	will	defend	itself	vigorously	in	these	proceedings;	however,	there	can be	no	assurances	that	it	will	be	successful	in	its	efforts.

In	July,	1993	the	Public	Attorney's	office	filed	a	claim	against	Eletropaulo,	the	Sao	Paulo	State	Government,	SABESP	(a	state-owned	company),	CETESB	(a state-owned	company)	and	DAEE	(the	municipal	Water	and	Electric	Energy	Department)	alleging	that	they	were	liable	for	pollution	of	the	Billings	Reservoir	as	a	result of	pumping	water	from	the	Pinheiros	River	into	the	Billings	Reservoir.	The	events	in	question	occurred	while	Eletropaulo	was	a	state-owned	company.	An	initial	lower court	decision	in	2007	found	the	parties	liable	for	the	payment	of	approximately	R$670	million	($401	million)	for	remediation.	Eletropaulo	subsequently	appealed	the decision	to	the	Appellate	Court	of	the	State	of	Sao	Paulo	which	reversed	the	lower	court	decision.	In	2009,	the	Public	Attorney's	Office	has	filed	appeals	to	both Superior	Court	of	Justice	("SCJ")	and	the	Supreme	Court	("SC")	and	such	appeals	were	answered	by	Eletropaulo	in	the	fourth	quarter	of	2009.	Eletropaulo	believes	it has	meritorious	defenses	to	the	claims	asserted	against	it	and	will	defend	itself	vigorously	in	these	proceedings;	however,	there	can	be	no	assurances	that	it	will	be successful	in	its	efforts.

In	September	1996,	a	public	civil	action	was	asserted	against	Eletropaulo	and	Associação	Desportiva	Cultural	Eletropaulo	(the	"Associação")	relating	to	alleged environmental	damage	caused	by	construction	of	the

Associação	near	Guarapiranga	Reservoir.	The	initial	decision	that	was	upheld	by	the	Appellate	Court	of	the	State	of	Sao	Paulo	in	2006	found	that	Eletropaulo	should repair	the	alleged	environmental	damage	by	demolishing	certain	construction	and	reforesting	the	area,	and	either	sponsor	an	environmental	project	which	would	cost approximately	R$1	million	($599	thousand)	as	of	December	31,	2010,	or	pay	an	indemnification	amount	of	approximately	R$10.2	million	($6	million).	Eletropaulo	has appealed	this	decision	to	the	Supreme	Court	and	is	awaiting	a	decision.

In	February	2009,	a	CAA	Section	114	information	request	from	the	EPA	regarding	Cayuga	and	Somerset	was	received.	The	request	seeks	various	operating	and testing	data	and	other	information	regarding	certain	types	of	projects	at	the	Cayuga	and	Somerset	facilities,	generally	for	the	time	period	from	January	1,	2000	through the	date	of	the	information	request.	This	type	of	information	request	has	been	used	in	the	past	to	assist	the	EPA	in	determining	whether	a	plant	is	in	compliance	with applicable	standards	under	the	CAA.	Cayuga	and	Somerset	responded	to	the	EPA's	information	request	in	June	2009,	and	they	are	awaiting	a	response	from	the	EPA regarding	their	submittal.	At	this	time,	it	is	not	possible	to	predict	what	impact,	if	any,	this	request	may	have	on	the	Company,	its	results	of	operations	or	its	financial position.

On	February	2,	2009,	the	Cayuga	facility	received	a	Notice	of	Violation	from	the	New	York	State	Department	of	Environmental	Conservation	("NYSDEC")	that the	facility	had	exceeded	the	permitted	volume	limit	of	coal	ash	that	can	be	disposed	of	in	the	on-site	landfill.	Cayuga	has	met	with	NYSDEC	and	submitted	a	Landfill Liner	Demonstration	Report	to	them.	Such	report	found	that	the	landfill	has	adequate	engineering	integrity	to	support	the	additional	coal	ash	and	there	is	no	inherent environmental	threat.	NYSDEC	has	indicated	they	accept	the	finding	of	the	report.	A	permit	modification	was	approved	by	the	NYSDEC	on	May	14,	2010	and	such permit	modification	allows	for	closure	of	this	approximately	10-acre	portion	of	the	landfill.	The	construction	in	accordance	with	the	approved	permit	modification	was completed	in	November	2010	and	the	certification	report	for	this	construction	project	is	currently	being	drafted	to	submit	to	the	NYSDEC	in	the	second	quarter	of	2011. While	at	this	time	it	is	not	possible	to	predict	what	impact,	if	any,	this	matter	may	have	on	the	Company,	its	results	of	operations	or	its	financial	position,	based	upon	the discussions	to	date,	the	Company	does	not	believe	the	impact	will	be	material.

In	March	2009,	AES	Uruguaiana	Empreendimentos	S.A.	("AESU")	initiated	arbitration	in	the	International	Chamber	of	Commerce	("ICC")	against	YPF	S.A. ("YPF")	seeking	damages	and	other	relief	relating	to	YPF's	breach	of	the	parties'	gas	supply	agreement	("GSA").	Thereafter,	in	April	2009,	YPF	initiated	arbitration	in the	ICC	against	AESU	and	two	unrelated	parties,	Companhia	de	Gas	do	Esado	do	Rio	Grande	do	Sul	and	Transportador	de	Gas	del	Mercosur	S.A.	("TGM"),	claiming that	AESU	wrongfully	terminated	the	GSA	and	caused	the	termination	of	a	transportation	agreement	("TA")	between	YPF	and	TGM	("YPF	Arbitration").	YPF	seeks	an unspecified	amount	of	damages	from	AESU,	a	declaration	that	YPF's	performance	was	excused	under	the	GSA	due	to	certain	alleged	force	majeure	events,	or,	in	the alternative,	a	declaration	that	the	GSA	and	the	TA	should	be	terminated	without	a	finding	of	liability	against	YPF	because	of	the	allegedly	onerous	obligations	imposed on	YPF	by	those	agreements.	In	addition,	in	the	YPF	Arbitration,	TGM	asserts	that	if	it	is	determined	that	AESU	is	responsible	for	the	termination	of	the	GSA,	AESU	is liable	for	TGM's	alleged	losses,	including	losses	under	the	TA.	The	procedural	schedules	for	the	arbitrations	have	been	established	but	the	hearing	dates	have	not	been scheduled	to	date.	AESU	believes	it	has	meritorious	defenses	to	the	claims	asserted	against	it	and	will	defend	itself	vigorously;	however,	there	can	be	no	assurances	that it	will	be	successful	in	its	efforts.

In	June	2009,	the	Supreme	Court	of	Chile	affirmed	a	January	2009	decision	of	the	Valparaiso	Court	of	Appeals	("VCA")	that	the	environmental	permit	for Empresa	Electrica	Campiche's	("EEC")	thermal	power	plant	("Plant")	was	not	properly	granted	and	illegal.	Construction	of	the	Plant	stopped	as	a	consequence	of	the Supreme	Court's	decision.	In	December	2009,	Chilean	authorities	approved	new	land	use	regulations	that	entitled	EEC	to	apply	for	a	new	environmental	permit.	EEC applied	for	a	new	environmental	permit	in	January	2010	and	permit	approval	was	granted	by	the	Environmental	Authority	in	February	2010.	In	March	2010,	the	Mayor of	Puchuncaví	and	another	third	party	challenged	the	new	environmental	permit	before	the	VCA.	The	parties	later	entered	into	a	settlement	agreement	pursuant	to	which the	challenge	to	the	new	environmental	permit

was	withdrawn	in	July	2010.	In	addition,	the	construction	permit	that	is	required	to	resume	construction	of	the	Plant	was	issued	by	the	Municipality	in	August	2010.	In September	2010,	neighbors	of	Puchuncaví	challenged	the	construction	permit	filing	claims	in	the	VCA.	In	November	2010,	the	VCA	rejected	the	claims.	The challenging	parties	subsequently	filed	appeals	with	the	Supreme	Court.	In	January	2011,	the	Supreme	Court	confirmed	the	decision	of	the	VCA,	finally	rejecting	the constitutional	action.	EEC	has	resumed	construction	of	the	Plant.

In	June	2009,	the	Inter-American	Commission	on	Human	Rights	of	the	Organization	of	American	States	("IACHR")	requested	that	the	Republic	of	Panama suspend	the	construction	of	AES	Changuinola	S.A.'s	hydroelectric	project	("Project")	until	the	bodies	of	the	Inter-American	human	rights	system	can	issue	a	final decision	on	a	petition	(286/08)	claiming	that	the	construction	violates	the	human	rights	of	alleged	indigenous	communities.	In	July	2009,	Panama	responded	by informing	the	IACHR	that	it	would	not	suspend	construction	of	the	Project	and	requesting	that	the	IACHR	revoke	its	request.	In	June	2010,	the	Inter-American	Court	of Human	Rights	vacated	the	IACHR's	request.	With	respect	to	the	merits	of	the	underlying	petition,	the	IACHR	heard	arguments	by	the	communities	and	Panama	in November	2009,	but	has	not	issued	a	decision	to	date.	The	Company	cannot	predict	Panama's	response	to	any	determination	on	the	merits	of	the	petition	by	the	bodies of	the	Inter-American	human	rights	system.

In	July	2009,	AES	Energía	Cartagena	S.R.L.	("AES	Cartagena")	received	notices	from	the	Spanish	national	energy	regulator,	Comisión	Nacional	de	Energía ("CNE"),	stating	that	the	proceeds	of	the	sale	of	electricity	from	AES	Cartagena's	plant	should	be	reduced	by	roughly	the	value	of	the	CO 	allowances	that	were	granted to	AES	Cartagena	for	free	for	the	years	2007,	2008,	and	the	first	half	of	2009.	In	particular,	the	notices	stated	that	CNE	intended	to	invoice	AES	Cartagena	to	recover that	value,	which	CNE	calculated	as	approximately	€20	million	($27	million)	for	2007-2008	and	an	amount	to	be	determined	for	the	first	half	of	2009.	In September	2009,	AES	Cartagena	received	invoices	for	€523,548	(approximately	$694,000)	for	the	allowances	granted	for	free	for	2007	and	€19,907,248	(approximately $26	million)	for	2008.	In	July	2010,	AES	Cartagena	received	an	invoice	for	approximately	€5.4	million	($7	million)	for	the	allowances	granted	for	free	for	the	first	half of	2009.	AES	Cartagena	does	not	expect	to	be	charged	for	CO 	allowances	issued	free	of	charge	for	subsequent	periods.	AES	Cartagena	has	paid	the	amounts	invoiced and	has	filed	challenges	to	the	CNE's	demands	in	the	Spanish	judicial	system.	There	can	be	no	assurances	that	the	challenges	will	be	successful.	AES	Cartagena	has demanded	indemnification	from	its	fuel	supply	and	electricity	toller,	GDF-Suez,	in	relation	to	the	CNE	invoices	under	the	long-term	energy	agreement	(the	"Energy Agreement")	with	GDF-Suez.	However,	GDF-Suez	has	disputed	that	it	is	responsible	for	the	CNE	invoices	under	the	Energy	Agreement.	Therefore,	in	September	2009, AES	Cartagena	initiated	arbitration	against	GDF-Suez,	seeking	to	recover	the	payments	made	to	CNE.	In	the	arbitration,	AES	Cartagena	also	seeks	a	determination	that GDF-Suez	is	responsible	for	procuring	and	bearing	the	cost	of	CO 	allowances	that	are	required	to	offset	the	CO	emissions	of	AES	Cartagena's	power	plant,	which	is also	in	dispute	between	the	parties.	To	date,	AES	Cartagena	has	paid	approximately	€20	million	($27	million)	for	the	CO 	allowances	that	have	been	required	to	offset 2008	and	2009	CO 	emissions.	AES	Cartagena	expects	that	allowances	will	need	to	be	purchased	to	offset	emissions	for	subsequent	years.	The	evidentiary	hearing	in	the arbitration	took	place	from	May	31-June	4,	2010,	and	closing	arguments	were	heard	on	September	1,	2010.	In	February	2011,	the	arbitral	tribunal	requested	further briefing	from	the	parties	on	certain	issues	in	the	arbitration.	If	AES	Cartagena	does	not	prevail	in	the	arbitration	and	is	required	to	bear	the	cost	of	carbon	compliance,	its results	of	operations	could	be	materially	adversely	affected	and,	in	turn,	there	could	be	a	material	adverse	effect	on	the	Company	and	its	results	of	operations.	AES Cartagena	believes	it	has	meritorious	claims	and	will	assert	them	vigorously	in	these	proceedings;	however,	there	can	be	no	assurances	that	it	will	be	successful	in	its efforts.

In	September	2009,	the	Public	Defender's	Office	of	the	State	of	Rio	Grande	do	Sul	("PDO")	filed	a	class	action	against	AES	Sul	in	the	16th	District	Court	of Porto	Alegre,	Rio	Grande	do	Sul	("District	Court"),	claiming	that	AES	Sul	has	been	illegally	passing	PIS	and	COFINS	taxes	(taxes	based	on	AES	Sul's	income)	to consumers.	According	to	ANEEL's	Order	No.	93/05,	the	federal	laws	of	Brazil,	and	the	Brazilian	Constitution,	energy	companies	such	as	AES	Sul	are	entitled	to highlight	PIS	and	COFINS	taxes	in	power	bills	to	final	consumers,	as	the	cost	of	those	taxes	is	included	in	the	energy	tariffs	that	are	applicable	to	final	consumers. Before	AES	Sul	had

been	served	with	the	action,	the	District	Court	dismissed	the	lawsuit	in	October	2009	on	the	ground	that	AES	Sul	had	been	properly	highlighting	PIS	and	COFINS	taxes in	consumer	bills	in	accordance	with	Brazilian	law.	In	April	2010,	the	PDO	appealed	to	the	Appellate	Court	of	the	State	of	Rio	Grande	do	Sul	("AC").	In	November 2010,	the	AC	affirmed	the	dismissal.	The	PDO	is	expected	to	appeal.	If	the	dismissal	is	ever	reversed	and	AES	Sul	does	not	prevail	in	the	lawsuit	and	is	ordered	to	cease recovering	PIS	and	COFINS	taxes	pursuant	to	its	energy	tariff,	its	potential	prospective	losses	could	be	approximately	R$9.6	million	($6	million)	per	month,	as estimated	by	AES	Sul.	In	addition,	if	AES	Sul	is	ordered	to	reimburse	consumers,	its	potential	retrospective	liability	could	be	approximately	R$1.2	billion	($718 million),	as	estimated	by	AES	Sul.	AES	Sul	believes	it	has	meritorious	defenses	to	the	claims	asserted	against	it	and	will	defend	itself	vigorously	in	these	proceedings	if it	is	served	with	the	action;	however,	there	can	be	no	assurances	that	it	would	be	successful	in	its	efforts.	Furthermore,	if	AES	Sul	does	not	prevail	in	the	litigation	it	will seek	to	adjust	its	energy	tariff	to	compensate	it	for	its	losses,	but	there	can	be	no	assurances	that	it	would	be	successful	in	obtaining	an	adjusted	energy	tariff.

In	October	2009,	IPL	received	a	Notice	of	Violation	("NOV")	and	Finding	of	Violation	from	EPA	pursuant	to	CAA	Section	113(a).	The	NOV	alleges	violations of	the	CAA	at	IPL's	three	coal-fired	electric	generating	facilities	dating	back	to	1986.	The	alleged	violations	primarily	pertain	to	EPA's	Prevention	of	Significant Deterioration	and	nonattainment	New	Source	Review	("NSR")	requirements	under	the	CAA.	Since	receiving	the	letter,	IPL	management	has	met	with	EPA	staff	and	is currently	in	discussions	with	the	EPA	regarding	possible	resolutions	to	this	NOV.	At	this	time,	we	cannot	predict	the	ultimate	resolution	of	this	matter.	However, settlements	and	litigated	outcomes	of	similar	cases	have	required	companies	to	pay	civil	penalties	and	to	install	additional	pollution	control	technology	on	coal-fired electric	generating	units.	A	similar	outcome	in	this	case	could	have	a	material	impact	to	IPL	and	could,	in	turn,	have	a	material	impact	on	the	Company.	IPL	would	seek recovery	through	customer	rates	of	any	operating	or	capital	expenditures	related	to	pollution	control	technology	systems	to	reduce	regulated	air	emissions;	however, there	can	be	no	assurances	that	it	would	be	successful	in	that	regard.

In	November	2009,	April	2010	and	December	2010,	substantially	similar	personal	injury	lawsuits	were	filed	by	a	total	of	26	residents	and	estates	in	the Dominican	Republic	against	the	Company,	AES	Atlantis,	Inc.,	AES	Puerto	Rico,	LP,	AES	Puerto	Rico,	Inc.,	and	AES	Puerto	Rico	Services,	Inc.,	in	the	Superior	Court for	the	State	of	Delaware.	In	each	lawsuit	the	plaintiffs	allege	that	the	coal	combustion	byproducts	of	AES	Puerto	Rico's	power	plant	were	illegally	placed	in	the Dominican	Republic	in	October	2003	through	March	2004	and	subsequently	caused	the	plaintiffs'	birth	defects,	other	personal	injuries,	and/or	deaths.	The	plaintiffs	do not	quantify	their	alleged	damages,	but	generally	allege	that	they	are	entitled	to	compensatory	and	punitive	damages.	The	AES	defendants	have	moved	for	partial dismissal	of	both	the	November	2009	and	April	2010	lawsuits	on	various	grounds.	(The	AES	Defendants	have	until	mid-February	to	respond	to	the	December	2010 lawsuit.)	In	September	2010,	the	Superior	Court	heard	arguments	on	the	motions.	The	Superior	Court	dismissed	the	plaintiffs'	fraud	allegations	without	prejudice	to replead,	and	the	plaintiffs	filed	amended	complaints	in	November	2010.	The	AES	defendants	have	filed	a	renewed	motion	to	dismiss	the	amended	issues.	The	remaining claims	(other	than	fraud)	addressed	in	the	AES	defendants'	original	motion	to	dismiss	are	still	pending.	The	AES	defendants	believe	they	have	meritorious	defenses	to the	claims	asserted	against	them	and	will	defend	themselves	vigorously;	however,	there	can	be	no	assurances	that	they	will	be	successful	in	their	efforts.

On	December	21,	2010,	AES-3C	Maritza	East	1	EOOD,	which	owns	an	unfinished	670MW	lignite-fired	power	plant	in	Bulgaria,	made	the	first	in	a	series	of demands	on	the	performance	bond	securing	the	construction	Contractor's	obligations	under	the	parties'	EPC	Contract.	The	Contractor	failed	to	complete	the	plant	on schedule.	The	total	amount	demanded	by	Maritza	under	the	performance	bond	is	approximately	€155	million	($205	million).	However,	the	Contractor	obtained	a temporary	injunction	from	a	French	court	preventing	the	issuing	bank	from	honoring	the	bond	demands.	As	the	performance	bond	is	governed	by	English	law,	Maritza obtained	a	judgment	from	an	English	court	that	the	bond	should	be	paid,	and	then	presented	this	judgment	to	the	French	court	which	issued	the	temporary	injunction. However,	on	February	10,	2011,	the	French	court	issued	a	decision	enjoining	the	issuing	bank	from	honoring	the	demands	on	the	performance	bond	pending	the determination	of	the	arbitration	between	Maritza	and	the	Contractor,	described	below.	Maritza	is	attempting	to

lift	that	injunction	or	otherwise	obtain	payment	on	its	demands.	In	addition,	in	December	2010,	the	Contractor	issued	a	notice	of	dispute	alleging	that	the	lignite	that	has been	supplied	by	Maritza	for	commissioning	of	the	power	plant	is	out	of	specification,	allegedly	entitling	the	Contractor	to	an	extension	of	time	to	complete	the	power plant,	an	increase	to	the	contract	price	of	approximately	€62	million	($82	million),	and	other	relief.	The	Contractor	thereafter	advised	Maritza	that	it	had	stopped commissioning	of	the	power	plant's	two	units	because	of	the	characteristics	of	the	lignite	supplied,	and,	in	January	2011,	initiated	arbitration	on	its	lignite	claim.	Maritza disputes	that	the	lignite	is	out	of	specification	and	intends	to	defend	the	arbitration	and	assert	counterclaims	for	delay	liquidated	damages	and	other	relief	relating	to	the Contractor's	failure	to	complete	the	power	plant	and	other	breaches	of	the	EPC	contract.	Maritza	believes	it	has	meritorious	claims	and	defenses	and	will	assert	them vigorously	in	these	proceedings;	however,	there	can	be	no	assurances	that	it	will	be	successful	in	its	efforts.

# ITEM	4. REMOVED	AND	RESERVED

# PART	II

# ITEM	5. MARKET	FOR	REGISTRANT'S	COMMON	EQUITY,	RELATED	STOCKHOLDER	MATTERS	AND	ISSUER	PURCHASES	OF	EQUITY SECURITIES

# Recent	Sales	of	Unregistered	Securities

On	March	12,	2010,	the	Company	and	Terrific	Investment	Corporation	("Investor"),	a	wholly	owned	subsidiary	of	China	Investment	Corporation,	entered	into	a stockholder	agreement	(the	"Stockholder	Agreement")	in	connection	with	the	agreement	discussed	in	the	following	paragraph.	Under	the	Stockholder	Agreement,	as long	as	Investor	holds	more	than	5%	of	the	outstanding	shares	of	common	stock	of	the	Company,	Investor	will	have	the	right	to	designate	one	nominee,	who	must	be reasonably	acceptable	to	the	Board,	for	election	to	the	Board	of	Directors	of	the	Company.	Investor	has	not	designated	its	nominee	for	election	to	the	Board	of	Directors of	the	Company.	In	addition,	until	such	time	as	Investor	holds	5%	or	less	of	the	outstanding	shares	of	common	stock,	Investor	has	agreed	to	vote	its	shares	in	accordance with	the	recommendation	of	the	Company	on	any	matters	submitted	to	a	vote	of	the	stockholders	of	the	Company	relating	to	the	election	of	directors	and	compensation matters.	Otherwise,	Investor	may	vote	its	shares	at	its	discretion.	Further,	under	the	Stockholder	Agreement,	Investor	will	be	subject	to	a	standstill	restriction	which generally	prohibits	Investor	from	purchasing	additional	securities	of	the	Company	beyond	the	level	acquired	by	it	under	the	stock	purchase	agreement	entered	into between	Investor	and	the	Company	on	November	6,	2009.	In	addition,	Investor	has	agreed	to	a	lock-up	restriction	such	that	Investor	would	not	sell	its	shares	for	a period	of	12	months	following	the	closing,	subject	to	certain	exceptions.	The	standstill	and	lock-up	restrictions	also	terminate	at	such	time	as	Investor	holds	5%	or	less	of the	outstanding	shares	of	common	stock.	Investor	will	have	certain	registration	rights	and	preemptive	rights	under	the	Stockholder	Agreement	with	respect	to	its	shares of	common	stock	of	the	Company.

On	March	15,	2010,	the	Company	completed	the	sale	of	125,468,788	shares	of	common	stock	to	Investor.	The	shares	were	sold	for	$12.60	per	share,	for	an aggregate	purchase	price	of	$1.58	billion.	Investor's	ownership	in	the	Company's	common	stock	is	now	approximately	15%	of	the	Company's	total	outstanding	shares of	common	stock	on	a	fully	diluted	basis.

# Purchases	of	Equity	Securities	by	the	Issuer	and	Affiliated	Purchasers

In	July	2010,	the	Company's	Board	of	Directors	approved	a	stock	repurchase	program	under	which	the	Company	may	repurchase	up	to	$500	million	of	AES common	stock.	The	Board	authorization	permits	the	Company	to	repurchase	stock	through	a	variety	of	methods,	including	open	market	repurchases	and/or	privately negotiated	transactions.	The	original	authorization	was	set	to	expire	on	December	31,	2010,	however;	in	December	2010,	the	Board	authorized	an	extension	of	the	stock repurchase	program.	There	can	be	no	assurance	as	to	the	amount,	timing	or	prices	of	repurchases,	which	may	vary	based	on	market	conditions	and	other	factors.	The stock	repurchase	program	may	be	modified,	extended	or	terminated	by	the	Board	of	Directors	at	any	time.	During	the	year	ended	December	31,	2010,	shares	of	common stock	repurchased	under	this	plan	totaled	8,382,825	at	a	total	cost	of	$99	million	plus	a	nominal	amount	of	commissions	(average	of	$11.86	per	share	including commissions).	There	was	$401	million	remaining	under	the	stock	repurchase	program	available	for	future	repurchases	at	December	31,	2010.

The	following	table	presents	information	regarding	purchases	made	by	The	AES	Corporation	of	its	common	stock	in	the	fourth	quarter	of	2010:

|  | Total	Number |  | Repurchased	as	Part | Dollar	Value	of	Maximum |
| :--- | :--- | :--- | :--- | :--- |
|  | of\tShares | Average\tPrice | of\ta\tPublicly\tAnnounced | Number\tof\tShares\tTo\tBe |
| Repurchase\tPeriod | Purchased | Paid\tper\tShare | Repurchase\tPlan | Purchased\tUnder\tthe\tPlan |
| 10/1/10—10/31/10 | 6,086,345 | $12.30 | 6,086,345 | $409,713,649 |
| 11/1/10—11/30/10 | — | $— | — | $409,713,649 |
| 12/1/10—12/31/10 | 755,000 | $11.89 | 755,000 | $400,732,931 |
| Total | 6,841,345 | $12.26 | 6,841,345 |  |

# Market	Information

Our	common	stock	is	currently	traded	on	the	New	York	Stock	Exchange	("NYSE")	under	the	symbol	"AES."	The	closing	price	of	our	common	stock	as	reported by	the	NYSE	on	February	23,	2011,	was	$12.25,	per	share.	The	Company	repurchased	8,382,825	and	10,691,267	shares	of	its	common	stock	in	2010	and	2008, respectively,	and	did	not	repurchase	any	of	its	common	stock	in	2009.	The	following	tables	set	forth	the	high	and	low	sale	prices,	and	performance	trends	for	our common	stock	as	reported	by	the	NYSE	for	the	periods	indicated:

|  | 2010 | 2010 | 2009 | 2009 |
| :--- | :--- | :--- | :--- | :--- |
| Price\tRange\tof\tCommon\tStock | High | Low | High | Low |
| First\tQuarter | $14.24 | $10.73 | $9.48 | $4.80 |
| Second\tQuarter | \t 12.46 | 8.94 | \t 11.64 | 5.62 |
| Third\tQuarter | \t 11.57 | 8.82 | \t 15.37 | \t 10.67 |
| Fourth\tQuarter | \t 12.54 | \t 10.70 | \t 15.44 | \t 12.50 |

# Performance	Graph

# PEER	GROUP	INDEX/STOCK	PRICE	PERFORMANCE

# Source:	Bloomberg

We	have	selected	the	Standard	and	Poor's	("S&P")	500	Utilities	Index	as	our	peer	group	index.	The	S&P	500	Utilities	Index	is	a	published	sector	index comprising	the	32	electric	and	gas	utilities	included	in	the	S&P	500.

The	five	year	total	return	chart	assumes	$100	invested	on	December	31,	2005	in	AES	Common	Stock,	the	S&P	500	Index	and	the	S&P	500	Utilities	Index.	The information	included	under	the	heading	"Performance	Graph"	shall	not	be	considered	"filed"	for	purposes	of	Section	18	of	the	Securities	Exchange	Act	of	1934	or incorporated	by	reference	in	any	filing	under	the	Securities	Act	of	1933	or	the	Securities	Exchange	Act	of	1934.

# Holders

As	of	February	23,	2011,	there	were	approximately	7,379	record	holders	of	our	common	stock.

# Dividends

We	do	not	currently	pay	dividends	on	our	common	stock.	We	intend	to	retain	our	future	earnings,	if	any,	to	finance	the	future	development	and	operation	of	our business.	Accordingly,	we	do	not	anticipate	paying	any	dividends	on	our	common	stock	in	the	foreseeable	future.

Under	the	terms	of	our	senior	secured	credit	facility,	which	we	entered	into	with	a	commercial	bank	syndicate,	we	have	limitations	on	our	ability	to	pay	cash dividends	and/or	repurchase	stock.	In	addition,	under	the	terms	of	a	guaranty	we	provided	to	the	utility	customer	in	connection	with	the	AES	Thames	project,	we	are precluded	from	paying	cash	dividends	on	our	common	stock	if	we	do	not	meet	certain	net	worth	and	liquidity	tests.

Our	project	subsidiaries'	ability	to	declare	and	pay	cash	dividends	to	us	is	subject	to	certain	limitations	contained	in	the	project	loans,	governmental	provisions and	other	agreements	to	which	our	project	subsidiaries	are	subject.

See	the	information	contained	under	the	caption	"Securities	Authorized	for	Issuance	under	Equity	Compensation	Plans"	of	the	Proxy	Statement	for	the	2010 Annual	Meeting	of	Shareholders	of	the	Registrant,	which	information	is	incorporated	herein	by	reference.

# ITEM	6. SELECTED	FINANCIAL	DATA

The	following	table	sets	forth	our	selected	financial	data	as	of	the	dates	and	for	the	periods	indicated.	You	should	read	this	data	together	with	Item	7.— Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations	and	the	Consolidated	Financial	Statements	and	the	notes	thereto	included	in Item	8	of	this	Form	10-K.	The	selected	financial	data	for	each	of	the	years	in	the	five	year	period	ended	December	31,	2010	have	been	derived	from	our	audited Consolidated	Financial	Statements.	Our	historical	results	are	not	necessarily	indicative	of	our	future	results.

Acquisitions,	disposals,	reclassifications	and	changes	in	accounting	principles	affect	the	comparability	of	information	included	in	the	tables	below.	Please	refer	to the	Notes	to	the	Consolidated	Financial	Statements	included	in	Item	8.—Financial	Statements	and	Supplementary	Data	of	this	Form	10-K	for	further	explanation	of	the effect	of	such	activities.	Please	also	refer	to	Item	1A.—Risk	Factors	of	this	Form	10-K	and	Note	24—Risks	and	Uncertainties	to	the	Consolidated	Financial	Statements included	in	Item	8	of	this	Form	10-K	for	certain	risks	and	uncertainties	that	may	cause	the	data	reflected	herein	not	to	be	indicative	of	our	future	financial	condition	or results	of	operations.

# SELECTED	FINANCIAL	DATA

| Statement	of	Operations	Data | 2010 | 2009 | 2008 | 2007 | 2006 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  | (in\tmillions,\texcept\tper\tshare\tamounts) | (in\tmillions,\texcept\tper\tshare\tamounts) | (in\tmillions,\texcept\tper\tshare\tamounts) |  |
| Revenue | $16,647 | $13,954 | $15,197 | $12,835 | $10,909 |
| Income\tfrom\tcontinuing\toperations^(1) | 920 | 1,809 | 1,929 | 814 | 545 |
| Income\t(loss)\tfrom\tcontinuing\toperations\tattributable\tto\tThe\tAES\tCorporation,\tnet\tof\ttax | (86) | 710 | 1,170 | 428 | 123 |
| Discontinued\toperations,\tnet\tof\ttax | 95 | (52) | 64 | (523) | 102 |
| Extraordinary\titems,\tnet\tof\ttax | — | — | — | — | 22 |
| Net\tincome\t(loss)\tattributable\tto\tThe\nAES\tCorporation | $9 | $658 | $1,234 | $(95) | $247 |
| Basic\t(loss)\tearnings\tper\tshare: |  |  |  |  |  |
| Income\t(loss)\tfrom\tcontinuing\toperations\tattributable\tto\tThe\tAES\tCorporation,\tnet\tof\ttax | $(0.11) | $1.06 | $1.75 | $0.64 | $0.19 |
| Discontinued\toperations,\tnet\tof\ttax | 0.12 | (0.07) | 0.09 | (0.78) | 0.15 |
| Extraordinary\titems,\tnet\tof\ttax | — | — | — | — | 0.03 |
| Basic\tearnings\t(loss)\tper\tshare | $0.01 | $0.99 | $1.84 | $(0.14) | $0.37 |
| Diluted\t(loss)\tearnings\tper\tshare: |  |  |  |  |  |
| Income\t(loss)\tfrom\tcontinuing\toperations\tattributable\tto\tThe\tAES\tCorporation,\tnet\tof\ttax | $(0.11) | $1.06 | $1.73 | $0.63 | $0.19 |
| Discontinued\toperations,\tnet\tof\ttax | 0.12 | (0.08) | $0.09 | (0.77) | 0.15 |
| Extraordinary\titems,\tnet\tof\ttax | — | — | — | — | 0.03 |
| Diluted\tearnings\t(loss)\tper\tshare | $0.01 | $0.98 | $1.82 | $(0.14) | $0.37 |

|  |  |  | December	31, |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Balance\tSheet\tData: | 2010 | 2009 | 2008 | 2007 | 2006 |
|  |  |  | (in\tmillions) |  |  |
| Total\tassets | $40,511 | $39,535 | $34,806 | $34,453 | $31,274 |
| Non-recourse\tdebt\t(long-term) | $12,544 | $12,304 | $11,254 | $10,621 | $9,136 |
| Non-recourse\tdebt\t(long-term)—Discontinued\toperations | $— | $560 | $615 | $709 | $1,046 |
| Recourse\tdebt\t(long-term) | $4,149 | $5,301 | $4,994 | $5,332 | $4,790 |
| Cumulative\tpreferred\tstock\tof\ta\tsubsidiary | $60 | $60 | $60 | $60 | $60 |
| Retained\tearnings\t(accumulated\tdeficit) | $620 | $650 | $(8) | $(1,241) | $(1,093) |
| The\tAES\tCorporation\tstockholders'\tequity | $6,473 | $4,675 | $3,669 | $3,164 | $2,979 |

# ITEM	7. MANAGEMENT'S	DISCUSSION	AND	ANALYSIS	OF	FINANCIAL	CONDITION	AND	RESULTS	OF	OPERATIONS

# Overview	of	Our	Business

We	are	a	global	power	company.	We	operate	two	primary	lines	of	business.	The	first	is	our	Generation	business,	where	we	own	and/or	operate	power	plants	to generate	and	sell	power	to	wholesale	customers	such	as	utilities,	other	intermediaries	and	certain	end-users.	The	second	is	our	Utilities	business,	where	we	own	and/or operate	utilities	to	distribute,	transmit	and	sell	electricity	to	end-user	customers	in	the	residential,	commercial,	industrial	and	governmental	sectors	within	a	defined service	area.	For	the	year	ended	December	31,	2010,	our	Generation	and	Utilities	businesses	comprised	approximately	45%	and	55%	of	our	consolidated	revenue, respectively.

We	are	also	continuing	to	expand	our	wind	and	solar	generation	businesses.	These	initiatives	are	not	material	contributors	to	our	operating	results	at	this	time,	but we	believe	that	certain	of	these	initiatives	may	become	material	in	the	future.	For	additional	information	regarding	our	business,	see	Item	1.—Business	of	this	Form	10- K.

Our	Organization	and	Segments.	Our	management	reporting	structure	is	organized	along	our	two	lines	of	business	(Generation	and	Utilities)	and	three	regions: (1)	Latin	America	&	Africa;	(2)	North	America;	and	(3)	Europe,	Middle	East	&	Asia	(collectively	"EMEA"),	each	managed	by	a	regional	president.	The	financial reporting	segment	structure	uses	our	management	reporting	structure	as	its	foundation	and	reflects	how	we	manage	the	business	internally.	Based	on	our	application	of the	segment	reporting	accounting	guidance,	which	provides	certain	quantitative	thresholds	and	aggregation	criteria,	we	have	concluded	that	the	Company	has	the following	six	reportable	segments:

We	report	the	Company's	Europe	Utilities,	Africa	Utilities,	Africa	Generation,	Wind	Generation	and	Climate	Solutions	operating	segments	within	"Corporate	and Other"	because	they	do	not	meet	the	criteria	to	allow	for	aggregation	with	another	operating	segment	or	the	quantitative	thresholds	that	would	require	separate	disclosure under	segment	reporting	accounting	guidance.	None	of	these	operating	segments	are	currently	material	to	our	financial	statement	presentation	of	reportable	segments, individually	or	in	the	aggregate.	"Corporate	and	Other"	also	includes	corporate	overhead	costs	which	are	not	directly	associated	with	the	operations	of	our	six	reportable segments	and	other	intercompany	charges	such	as	self-insurance	premiums	which	are	fully	eliminated	in	consolidation.

During	the	second	quarter	of	2010,	the	Company	modified	its	internal	reporting	structure	to	move	the	management	of	the	Company's	generation	business	in Jordan,	Amman	East,	from	Asia	to	Europe.	Accordingly,	Amman	East	is	now	reported	within	the	Europe—Generation	segment.	All	prior	periods	have	been retrospectively	restated	to	reflect	this	change	and	conform	to	current	period	presentation.

Key	Drivers	of	Our	Results	of	Operations.	Our	Generation	and	Utilities	businesses	are	distinguished	by	the	nature	of	their	customers,	operational	differences,	cost structure,	regulatory	environment	and	risk	exposure.	As	a	result,	each	line	of	business	has	slightly	different	drivers	which	affect	operating	results.	Performance	drivers for	our	Generation	businesses	include,	among	other	things,	plant	reliability	and	efficiency,	power	prices,	volume,

management	of	fixed	and	variable	operating	costs,	management	of	working	capital	including	collection	of	receivables,	and	the	extent	to	which	our	plants	have	hedged their	exposure	to	currency	and	commodities	such	as	fuel.	For	our	Generation	businesses	which	sell	power	under	short-term	contracts	or	in	the	spot	market,	the	most crucial	factors	are	the	current	market	price	of	electricity	and	the	marginal	costs	of	production.	Growth	in	our	Generation	business	is	largely	tied	to	securing	new	PPAs, expanding	capacity	in	our	existing	facilities	and	building	or	acquiring	new	power	plants.	Performance	drivers	for	our	Utilities	businesses	include,	but	are	not	limited	to, reliability	of	service;	management	of	working	capital,	including	collection	of	receivables;	negotiation	of	tariff	adjustments;	compliance	with	extensive	regulatory requirements;	and	in	developing	countries,	reduction	of	commercial	and	technical	losses.	The	operating	results	of	our	Utilities	businesses	are	sensitive	to	changes	in economic	growth	and	weather	conditions	in	areas	in	which	they	operate.	In	addition	to	these	drivers,	as	further	explained	below,	the	Company	also	has	exposure	to currency	exchange	rate	fluctuations.

One	of	the	key	factors	which	affect	our	Generation	business	is	our	ability	to	enter	into	contracts	for	the	sale	of	electricity	and	the	purchase	of	fuel	used	to	produce that	electricity.	Long-term	contracts	are	intended	to	reduce	exposure	to	volatility	associated	with	fuel	prices	in	the	market	and	the	price	of	electricity	by	fixing	the	revenue and	costs	for	these	businesses.	The	majority	of	the	electricity	produced	by	our	Generation	businesses	is	sold	under	long-term	contracts,	or	PPAs,	to	wholesale	customers. In	turn,	most	of	these	businesses	enter	into	long-term	fuel	supply	contracts	or	fuel	tolling	arrangements	where	the	customer	assumes	full	responsibility	for	purchasing and	supplying	the	fuel	to	the	power	plant.	While	these	long-term	contractual	agreements	reduce	exposure	to	volatility	in	the	market	price	for	electricity	and	fuel,	the predictability	of	operating	results	and	cash	flows	vary	by	business	based	on	the	extent	to	which	a	facility's	generation	capacity	and	fuel	requirements	are	contracted	and the	negotiated	terms	of	these	agreements.	Entering	into	these	contracts	exposes	us	to	counterparty	credit	risk.	For	further	discussion	of	these	risks,	see	"Supplier	and/or customer	concentration	may	expose	the	Company	to	significant	financial	credit	or	performance	risks"	in	Item	1A.—Risk	Factors	of	this	Form	10-K.

When	fuel	costs	increase,	many	of	our	businesses	are	able	to	pass	these	costs	on	to	their	customers.	Generation	businesses	with	long-term	contracts	in	place	do this	by	including	fuel	pass-through	or	fuel	indexing	arrangements	in	their	contracts.	Utilities	businesses	can	pass	costs	on	to	their	customers	through	increases	in	current or	future	tariff	rates.	Therefore,	in	a	rising	fuel	cost	environment,	the	increased	fuel	costs	for	these	businesses	often	result	in	an	increase	in	revenue	to	the	extent	these costs	can	be	passed	through	(though	not	necessarily	on	a	one-for-one	basis).	Conversely,	in	a	declining	fuel	cost	environment,	the	decreased	fuel	costs	can	result	in	a decrease	in	revenue.	Increases	or	decreases	in	revenue	at	these	businesses	that	have	the	ability	to	pass	through	costs	to	the	customer	have	a	corresponding	impact	on	cost of	sales,	to	the	extent	the	costs	can	be	passed	through,	resulting	in	a	limited	impact	on	gross	margin,	if	any.	Although	these	circumstances	may	not	have	a	large	impact on	gross	margin,	they	can	significantly	affect	gross	margin	as	a	percentage	of	revenue.	As	a	result,	gross	margin	as	a	percentage	of	revenue	is	a	less	relevant	measure when	evaluating	our	operating	performance.	To	the	extent	our	businesses	are	unable	to	pass	through	fuel	cost	increases	to	their	customers,	gross	margin	may	be adversely	affected.

Global	diversification	also	helps	us	mitigate	risk.	Our	presence	in	mature	markets	helps	mitigate	the	exposure	associated	with	our	businesses	in	emerging	markets. Additionally,	our	portfolio	employs	a	broad	range	of	fuels,	including	coal,	gas,	fuel	oil,	water	(hydroelectric	power),	wind	and	solar,	which	reduces	the	risks	associated with	dependence	on	any	one	fuel	source.	However,	to	the	extent	the	mix	of	fuel	sources	enabling	our	generation	capabilities	in	any	one	market	is	not	diversified,	the spread	in	costs	of	different	fuels	or	the	availability	of	natural	resources	such	as	water	for	hydroelectric	power	production	or	wind	may	also	influence	the	operating performance	and	the	ability	of	our	subsidiaries	to	compete	within	that	market.	For	example,	in	a	market	where	gas	prices	fall	to	a	low	level	compared	to	coal	prices, power	prices	may	be	set	by	low	gas	prices	which	can	affect	the	profitability	of	our	coal	plants	in	that	market.	In	certain	cases,	we	may	attempt	to	hedge	fuel	prices	to manage	this	risk,	but	there	can	be	no	assurance	that	these	strategies	will	be	effective.

We	also	attempt	to	limit	risk	by	hedging	much	of	our	interest	rate	and	commodity	risk,	and	by	matching	the	currency	of	most	of	our	subsidiary	debt	to	the	revenue of	the	underlying	business.	However,	we	only	hedge	a

portion	of	our	currency	and	commodity	risks,	and	our	businesses	are	still	subject	to	these	risks,	as	further	described	in	Item	1A.—Risk	Factors	of	this	Form	10-K,	"We may	not	be	adequately	hedged	against	our	exposure	to	changes	in	commodity	prices	or	interest	rates."	Commodity	and	power	price	volatility	could	continue	to	impact our	financial	metrics	to	the	extent	this	volatility	is	not	hedged.	For	a	discussion	of	our	sensitivities	to	commodity,	currency	and	interest	rate	risk,	see	Item	7A.— Quantitative	and	Qualitative	Disclosures	About	Market	Risk	in	this	Form	10-K.

Due	to	our	global	presence,	the	Company	has	significant	exposure	to	foreign	currency	fluctuations.	The	exposure	is	primarily	associated	with	the	impact	of	the translation	of	our	foreign	subsidiaries'	operating	results	from	their	local	currency	to	U.S.	Dollars	that	is	required	for	the	preparation	of	our	consolidated	financial statements.	Additionally,	there	is	foreign	currency	transaction	exposure	when	an	entity	enters	into	transactions,	including	debt	agreements,	in	currencies	other	than	their functional	currency.	These	risks	are	further	described	in	Item	1A.—Risk	Factors	of	this	Form	10-K,	"Our	financial	position	and	results	of	operations	may	fluctuate significantly	due	to	fluctuations	in	currency	exchange	rates	experienced	at	our	foreign	operations."	During	2010,	changes	in	foreign	currency	exchange	rates	had	a significant	impact	on	our	operating	results.	If	the	current	foreign	currency	exchange	rate	volatility	continues,	our	gross	margin	and	other	financial	metrics	could	continue to	be	affected.

Another	key	driver	of	our	results	is	our	ability	to	bring	new	businesses	into	commercial	operation	successfully.	We	currently	have	approximately	1,300	MW	of projects	under	construction	in	eight	countries.	Our	prospects	for	improved	operating	results	and	cash	flows	are	dependent	upon	successful	completion	of	these	projects	on time	and	within	budget.	However,	as	disclosed	in	Item	1A.—Risk	Factors	of	this	Form	10-K,	"Our	business	is	subject	to	substantial	development	uncertainties," construction	is	subject	to	a	number	of	risks,	including	risks	associated	with	site	identification,	financing,	permitting	and	our	ability	to	meet	construction	deadlines. Delays	or	the	inability	to	complete	projects	and	commence	commercial	operations	can	result	in	increased	costs,	impairment	of	assets	and	other	challenges	involving partners	and	counterparties	to	our	construction	agreements,	PPAs	and	other	agreements.

Our	gross	margin	is	also	impacted	by	the	fact	that	in	each	country	in	which	we	conduct	business,	we	are	subject	to	extensive	and	complex	governmental regulations,	such	as	regulations	governing	the	generation	and	distribution	of	electricity,	and	environmental	regulations	which	affect	most	aspects	of	our	business. Regulations	differ	on	a	country	by	country	basis	(and	even	at	the	state	and	local	municipality	levels)	and	are	based	upon	the	type	of	business	we	operate	in	a	particular country,	and	affect	many	aspects	of	our	operations	and	development	projects.	Our	ability	to	negotiate	tariffs,	enter	into	long-term	contracts,	pass	through	costs	related	to capital	expenditures	and	otherwise	navigate	these	regulations	can	have	an	impact	on	our	revenue,	costs	and	gross	margin.	Environmental	and	land	use	regulations, including	existing	and	proposed	regulation	of	GHG	emissions,	could	substantially	increase	our	capital	expenditures	or	other	compliance	costs,	which	could	in	turn	have a	material	adverse	affect	on	our	business	and	results	of	operations.	For	a	further	discussion	of	the	Regulatory	Environment,	see	Note	12—Contingencies	and Commitments—Environmental,	included	in	Item	8.—Financial	Statements,	Item	1.—Business—Regulatory	Matters—Environmental	and	Land	Use	Regulations	and Item	1A.—Risk	Factors—Risks	Associated	with	Government	Regulation	and	Laws	of	this	Form	10-K.

# Key	Drivers	of	Results	in	2010

In	2010,	the	Company's	gross	margin	and	cash	flow	from	operations	increased	$531	million	and	$1.3	billion,	respectively,	while	net	income	attributable	to	The AES	Corporation	decreased	$649	million	compared	to	the	prior	year.

During	2010,	our	North	American	generation	businesses	continued	to	face	challenges	associated	with	relatively	lower	gas	prices	and	a	decline	in	power	prices relative	to	coal	and	other	fuel.	In	particular,	lower	gas	and	power	prices	have	affected	the	generation	volume	and	financial	results	of	our	coal-fired	plants	in	New	York and	our	petroleum	coke-fired	plant	in	Texas	which	are	merchant	businesses	and	not	subject	to	PPAs.	We	expect

this	trend	to	continue.	In	2010,	these	challenges	were	partially	mitigated	by	hedging	arrangements.	In	North	America,	current	dark	spreads	and	the	corresponding forward	curves	do	not	present	a	long-term	opportunity	to	engage	in	hedging	activity	for	2011	and	we	have	very	limited	hedges	in	place.	As	short-term	opportunities occur	or	should	dark	spreads	improve,	the	Company	may	engage	in	additional	hedging	in	2011.	As	a	result	of	these	and	other	challenges	that	arose	from	new	regulatory concerns,	we	impaired	$1.1	billion	of	assets	and	goodwill	in	North	America	as	described	in	Impairments	below.	In	addition,	AES	Thames,	our	208	MW	coal-fired generation	business	in	Connecticut,	filed	for	bankruptcy	protection	in	January	2011.

Despite	these	challenges,	many	of	our	financial	measures	have	improved	when	compared	to	2009.	Gross	margin	increased	due	to	the	favorable	impact	of	foreign currency	translation	caused	by	a	weaker	U.S.	dollar	compared	to	most	foreign	currencies	in	2010	and	better	operating	performance	at	certain	businesses.	For	instance, certain	of	the	Company's	Latin	American	businesses	experienced	continued	increases	in	market	demand	due	to	the	local	economic	recovery	in	Latin	America.	The Company	also	benefited	from	higher	demand	and	favorable	market	conditions	at	Masinloc,	our	generation	business	in	the	Philippines.	Masinloc's	higher	availability enabled	the	Company	to	benefit	from	increased	contract	and	spot	market	sales	and	favorable	market	prices	in	the	Philippines.	In	addition,	cash	provided	by	operating activities	increased	due	to	the	improved	operating	results	at	Latin	America	generation	businesses	and	Masinloc;	contributions	from	the	consolidation	of	Cartagena	and the	Ballylumford	acquisition	in	2010;	and	changes	in	working	capital	in	Latin	America.

Despite	the	increase	in	gross	margin	in	2010,	net	income	attributable	to	The	AES	Corporation	decreased	primarily	from	the	impact	of	long-lived	asset impairments	recognized	related	to	four	businesses:	Eastern	Energy	in	New	York,	Southland	in	California,	Tisza	II	in	Hungary	and	Deepwater	in	Texas.	These	were partially	offset	by	gains	from	the	sale	of	our	discontinued	businesses	in	Oman	and	Qatar	and	a	decrease	in	goodwill	impairment	charges.

In	2011,	we	expect	to	face	continued	challenges	in	our	business,	including	the	trends	in	North	America	described	above.	In	addition,	the	impact	of	fluctuating foreign	exchange	rates	and	commodity	prices	on	our	operations	may	continue	into	2011.	In	2011,	the	components	of	the	tariff	reset	in	Brazil	and	its	potential	impact	on our	Brazilian	utilities	are	uncertain	at	this	time	and	we	expect	continued	challenges	in	our	merchant	businesses	such	as	those	in	the	U.S.,	Hungary	and	Northern	Ireland. However,	management	expects	that	improved	operating	performance	at	certain	businesses	and	growth	from	new	businesses	acquired,	that	commenced	operations	in 2010	or	are	expected	to	commence	operations	in	2011,	may	lessen	or	offset	the	impact	of	these	challenges	described	above,	as	they	did	in	2010.	However,	if	these favorable	effects	do	not	occur,	or	if	the	challenges	described	above	or	elsewhere	in	this	section	impact	us	more	than	we	currently	anticipate,	or	if	volatile	foreign currencies	and	commodities	move	unfavorably,	then	these	adverse	factors	(or	other	adverse	factors	unknown	to	us)	may	impact	our	gross	margin	and	net	income attributable	to	The	AES	Corporation.	In	addition,	we	do	not	expect	the	trend	of	an	increase	in	net	cash	provided	by	operating	activities	realized	in	2010	to	continue	in 2011.	Such	cash	flows	may	be	influenced	by	the	operating	challenges	presented	above	and	will	also	not	include	the	cash	flows	from	operations	which	were	sold	in	2010 or	the	increases	experienced	from	the	cash	flows	provided	by	the	initial	consolidation	of	Cartagena,	the	acquisition	of	Ballylumford	and	several	working	capital transactions	at	our	Latin	American	utilities	in	2010	as	discussed	in	Capital	Resources	and	Liquidity.

The	following	briefly	describes	the	key	changes	in	our	reported	revenue,	gross	margin,	net	income	attributable	to	The	AES	Corporation,	diluted	earnings	per share	from	continuing	operations,	Adjusted	Earnings	per	Share	(a	non-GAAP	measure)	and	net	cash	provided	by	operating	activities	for	the	year	ended	December	31, 2010	compared	to	2009	and	2008	and	should	be	read	in	conjunction	with	our	Consolidated	Results	of	Operations	and	Segment	Analysis	discussion	within	Management's Discussion	and	Analysis	of	Financial	Condition.

# Performance	Highlights

| Revenue | $16,647 | $13,954 | $15,197 |
| :--- | :--- | :--- | :--- |
| Gross\tMargin | $3,964 | $3,433 | $3,568 |
| Net\tIncome\tAttributable\tto\tThe\tAES\tCorporation | $9 | $658 | $1,234 |
| Diluted\tEarnings\t(Loss)\tper\tShare\tfrom\tContinuing\tOperations | $(0.11) | $1.06 | $1.73 |
| Adjusted\tEarnings\tPer\tShare\t(a\tnon-GAAP\tmeasure)^(1) | $0.94 | $1.06 | $1.06 |
| Net\tCash\tProvided\tby\tOperating\tActivities | $3,510 | $2,202 | $2,160 |

See	reconciliation	and	definition	below	under	Non-GAAP	Measure.

•the	favorable	impact	of	foreign	currency	of	$805	million;

•increased	volume	and	rates	at	our	Brazilian	utilities	attributable	to	increased	demand	due	to	the	recovery	of	the	local	economy	and	the	favorable	impact	of the	June	2009	tariff	reset;

•the	impact	of	the	consolidation	of	Cartagena,	in	Spain,	in	accordance	with	the	new	consolidation	accounting	guidance	which	became	effective	January	1, 2010;

•the	favorable	impact	of	rates	at	our	generation	businesses	in	Argentina;

•higher	generation	rates	and	volume	at	Masinloc	in	the	Philippines;

•higher	demand	at	Gener	in	Chile;

•the	impact	of	the	Company's	new	business	in	Northern	Ireland,	acquired	in	August	2010;	and

•higher	demand	and	rates	at	Indianapolis	Power	and	Light.

•the	favorable	impact	of	foreign	currency	of	$219	million;

•an	increase	in	demand	at	our	generation	and	utilities	businesses	in	Latin	America;

•higher	generation	rates	and	volume	at	Masinloc	in	the	Philippines;	and

These	increases	were	partially	offset	by:

•an	increase	in	fixed	costs	in	Latin	America,	largely	driven	by	bad	debt	recoveries	and	a	reduction	in	bad	debt	expense	in	Brazil	in	2009	that	did	not	recur; and

•lower	rates	at	our	generation	businesses	in	New	York.

Net	income	attributable	to	The	AES	Corporation	decreased	$649	million	to	$9	million	in	2010,	compared	to	$658	million	in	2009.	Key	drivers	of	the	decrease included:

•Impairment	losses	in	New	York	related	to	our	Eastern	Energy	facilities,	in	California	related	to	our	Southland	(Huntington	Beach)	generation	facility,	in Hungary	related	to	our	Tisza	II	generation	facility	and	in	Texas	related	to	our	Deepwater	facility;

•	 A	decrease	in	gain	on	sale	of	investments	due	to	the	sale	of	our	businesses	in	Northern	Kazakhstan	which	occurred	in	2009;	and

•	 A	decrease	in	other	income	due	to	the	reduction	in	interest	and	penalties	in	2009	associated	with	federal	tax	debts	at	Eletropaulo	and	Sul	as	a	result	of	the Programa	de	Recuperacao	Fiscal	("REFIS")	program	and	a	favorable	court	decision	in	2009	enabling	Eletropaulo	to	receive	reimbursement	of	excess	non- income	taxes	paid	from	1989	to	1992	in	the	form	of	tax	credits	to	be	applied	against	future	tax	liabilities.

# These	decreases	were	partially	offset	by:

•The	gain	on	sale	of	discontinued	operations	related	to	the	sale	of	Barka	which	occurred	in	August	2010;

•	 An	increase	in	net	equity	in	earnings	of	affiliates	partially	offset	by	income	tax	expense	related	to	the	sale	of	the	Company's	indirect	investment	in Companhia	Energética	de	Minas	Gerais	("CEMIG");

•Lower	impairment	expenses	related	to	a	goodwill	impairment	of	our	business	in	Kilroot	that	occurred	in	2009;

•Lower	income	tax	expense	due	to	2010	asset	impairments	primarily	recorded	at	certain	U.S.	subsidiaries;	and

•	 An	increase	in	gross	margin	as	described	above.

Net	cash	provided	by	operating	activities	increased	$1.3	billion,	or	59%,	to	$3.5	billion	in	2010	compared	with	$2.2	billion	in	2009.	This	net	increase	was primarily	due	to	the	following:

•an	increase	of	$837	million	at	our	Latin	American	Utilities	businesses	due	to	increased	tax	payments	in	2009	associated	with	a	tax	amnesty	program	of $326	million,	higher	working	capital	requirements	during	2009	related	to	payments	on	the	settlement	of	swap	agreements	of	$65	million	and	in	2010,	a	$50 million	decrease	in	employer	contributions	to	pension	plans	and	lower	payments	for	contingencies;

•an	increase	of	$215	million	at	our	Latin	American	Generation	businesses	due	to	the	higher	gross	margin	in	2010	combined	with	improved	working	capital mainly	as	a	result	of	higher	collections	of	value	added	taxes	and	accounts	receivable;

•an	increase	of	$99	million	at	Masinloc	in	the	Philippines	due	to	higher	gross	margin;	and

•an	increase	of	$58	million	as	a	result	of	our	consolidation	of	Cartagena	in	2010	and	the	acquisition	of	Ballylumford	in	Northern	Ireland.

•a	decrease	of	$136	million	in	operating	cash	flows	from	discontinued	operations	of	businesses	sold	in	2010	compared	to	2009.	In	2010,	net	cash	provided by	operating	activities	of	businesses	sold	was	$33	million	and	will	not	recur	in	2011.

In	2010	the	increase	in	net	cash	provided	by	operating	activities	at	our	Latin	American	Utilities	businesses	included	several	items	such	as	the	tax	amnesty	program and	settlement	of	swap	agreements,	as	described	above,	that	are	not	expected	to	recur.	In	addition,	2010	net	cash	provided	by	operating	activities	benefited	from	the	one time	cash	savings	related	to	the	utilization	of	tax	credits	received	as	a	result	of	the	REFIS	program.	As	such,	the	Company	does	not	expect	the	trend	of	an	increase	in	net cash	provided	by	operating	activities	realized	in	2010	to	continue	in	2011.

•the	unfavorable	impact	of	foreign	currency	of	$997	million,	largely	driven	by	the	Brazilian	Real;

•decreases	in	volume	at	Uruguaiana	due	to	the	renegotiation	of	its	power	sales	agreements	in	2009	to	reduce	the	energy	volume	sold,	as	well	as	in	New	York and	Hungary	and	lower	dispatch	in	Northern	Ireland	due	to	unfavorable	gas	prices	compared	to	coal;

•the	impact	of	lower	spot	and	contract	energy	prices	at	our	generation	business	in	Chile;	and

•lower	energy	prices	and	volume	at	our	generation	businesses	in	the	Dominican	Republic.

•an	increase	in	tariff	rates	at	our	utilities	businesses	in	Latin	America	primarily	reflecting	the	recovery	of	energy	purchases	that	were	passed	through	to	our customers.

Gross	margin	decreased	$135	million,	or	4%,	to	$3.4	billion	in	2009	compared	with	$3.6	billion	in	2008.	Key	drivers	of	the	decrease	included:

•lower	energy	prices	and	higher	purchased	energy	costs	at	our	generation	businesses	in	the	Dominican	Republic	and	Argentina;

•increased	pension	costs	in	Brazil	and	the	U.S.;	and

•lower	volume	in	New	York	due	to	lower	spot	market	rates.

•improved	operating	performance	at	our	generation	businesses	in	Chile	and	the	Philippines;

•higher	tariffs	in	Brazil	and	El	Salvador;	and

•bad	debt	recoveries	and	a	reduction	in	bad	debt	expense	in	Brazil.

Net	income	attributable	to	The	AES	Corporation	decreased	$576	million	to	$658	million	in	2009,	compared	to	$1.2	billion	in	2008.	Key	drivers	of	the	decrease included:

•a	gain	recognized	in	2008	from	the	sale	of	two	wholly-owned	subsidiaries	in	Northern	Kazakhstan	partially	offset	by	a	performance	incentive	bonus recognized	in	2009	for	management	services	provided	to	these	subsidiaries	and	a	settlement	upon	termination	of	the	management	agreement	in	2009;

•the	reduction	in	gross	margin	in	2009	as	described	above;	and

•higher	impairment	expenses	in	2009	as	a	result	of	an	impairment	of	goodwill	at	Kilroot	in	Northern	Ireland,	and	an	impairment	recognized	on	our	assets	in Pakistan	which	is	reflected	in	discontinued	operations,	offset	by	a	decline	in	long-lived	asset	impairment	compared	to	2008.

•a	reduction	in	foreign	currency	transaction	losses	on	net	monetary	position	as	a	result	of	reduced	losses	at	our	businesses	in	Chile	and	the	Philippines; •a	reduction	in	interest	expense	due	primarily	to	lower	interest	rates	and	debt	balances	in	Brazil	and	favorable	foreign	currency	translation;	and

•lower	income	tax	expenses	driven	in	part	by	lower	pre-tax	income	and	a	decrease	in	the	effective	tax	rate	from	29%	in	2008	to	26%	in	2009	due,	in	part,	to tax	benefits	recorded	in	2009	upon	the	release	of

valuation	allowances	at	U.S.	and	Brazilian	subsidiaries,	$165	million	of	non-taxable	income	recognized	in	Brazil	as	a	result	of	the	REFIS	program	in	2009 and	an	increase	in	U.S.	taxes	on	distributions	from	the	Company's	primary	holding	company	in	the	second	quarter	of	2008.

In	2008,	the	$905	million	gain	recognized	on	the	sale	of	our	two	Northern	Kazakhstan	businesses	had	a	significant	impact	on	net	income	attributable	to	The	AES Corporation.	In	2009,	the	Company	recognized	a	performance	incentive	bonus	of	$80	million	in	the	first	quarter	for	management	services	provided	to	these	sold businesses,	reflected	as	other	income.	Additionally,	in	the	second	quarter	of	2009,	the	Company	recognized	an	additional	gain	on	the	sale	of	the	businesses	of	$98.5 million	upon	the	termination	of	the	management	agreement.	While	the	Company	engages	in	the	sale	of	assets	and	businesses	from	time	to	time,	the	gain	or	loss recognized	in	any	such	sale	will	depend	on	a	number	of	factors	related	to	the	asset	or	business	that	may	be	sold.	Therefore,	the	Company	does	not	believe	that	the decline	in	net	income	between	2008	and	2009	represents	a	trend.	All	of	the	amounts	related	to	our	two	Northern	Kazakhstan	businesses	were	reported	in	continuing operations	and	will	not	recur	in	2010	or	future	years.

Net	cash	from	operating	activities	increased	$42	million,	or	2%,	to	$2.2	billion	in	2009	compared	with	$2.2	billion	in	2008.	This	net	increase	was	primarily	due	to the	following:

•an	increase	of	$238	million	at	our	Latin	American	Generation	businesses	due	to	improved	working	capital	management;

•an	increase	of	$148	million	at	our	Asia	Generation	businesses	due	to	improved	working	capital	management	and	improved	gross	margin;	and

•an	increase	of	$115	million	at	our	Europe	Generation	businesses	primarily	due	to	the	collection	of	the	$80	million	Kazakhstan	management	performance incentive	bonus	in	the	first	quarter	2009.

•a	decrease	of	$391	million	at	our	Latin	American	Utilities	businesses	due	to	increased	working	capital	requirements,	including	the	payment	of	the settlement	of	a	swap	agreement,	increased	tax	payments	associated	with	a	tax	amnesty	program	and	increased	payments	related	to	the	settlement	of contingencies	and	energy	purchases,	partially	offset	by	increased	operating	results;	and

•a	decrease	of	$77	million	at	our	North	America	Generation	businesses,	primarily	due	to	reduced	operating	results.

# Non-GAAP	Measure

We	define	adjusted	earnings	per	share	("Adjusted	EPS")	as	diluted	earnings	per	share	from	continuing	operations	excluding	gains	or	losses	of	the	consolidated entity	due	to	(a)	mark-to-market	amounts	related	to	derivative	transactions,	(b)	unrealized	foreign	currency	gains	or	losses,	(c)	significant	gains	or	losses	due	to dispositions	and	acquisitions	of	business	interests,	(d)	significant	losses	due	to	impairments,	and	(e)	costs	due	to	the	early	retirement	of	debt.	The	GAAP	measure	most comparable	to	Adjusted	EPS	is	diluted	earnings	per	share	from	continuing	operations.	AES	believes	that	Adjusted	EPS	better	reflects	the	underlying	business performance	of	the	Company	and	is	considered	in	the	Company's	internal	evaluation	of	financial	performance.	Factors	in	this	determination	include	the	variability	due to	mark-to-market	gains	or	losses	related	to	derivative	transactions,	currency	gains	or	losses,	losses	due	to	impairments	and	strategic	decisions	to	dispose	or	acquire business	interests	or	retire	debt,	which	affect	results	in	a	given	period	or	periods.	Adjusted	EPS	should	not	be	construed	as	an	alternative	to	diluted	earnings	per	share from	continuing	operations,	which	is	determined	in	accordance	with	GAAP.

For	the	year	ended	December	31,	2010,	the	Company	reported	a	loss	from	continuing	operations	of	$0.11	per	share.	For	purposes	of	measuring	loss	per	share under	GAAP,	common	stock	equivalents	were	excluded	from	weighted	average	shares	as	their	inclusion	would	be	antidilutive.	However,	for	purposes	of	computing Adjusted

EPS	(a	non-GAAP	measure),	the	Company	has	included	the	impact	of	dilutive	common	stock	equivalents	as	the	inclusion	of	the	defined	adjustments	result	in	income	for Adjusted	EPS.	The	table	below	reconciles	the	weighted	average	shares	used	in	GAAP	diluted	earnings	per	share	to	the	weighted	average	shares	used	in	calculating	the non-GAAP	measure	of	Adjusted	EPS:

| Reconciliation	of	Denominator	used	for	Adjusted	Earnings	Per	Share | Loss | Shares | $	per	Share |
| :--- | :--- | :--- | :--- |
| GAAP\tDILUTED\tEARNINGS\tPER\tSHARE |  |  |  |
| Loss\tfrom\tcontinuing\toperations\tattributable\tto\tThe\tAES\tCorporation\tcommon\tstockholders | $(86) | 769 | $(0.11) |
| EFFECT\tOF\tDILUTIVE\tSECURITIES |  |  |  |
| Stock\toptions | — | 2 | — |
| Restricted\tstock\tunits | — | 3 | — |
| NON-GAAP\tDILUTED\tEARNINGS\t(LOSS)\tPER\tSHARE | $(86) | 774 | $(0.11) |

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
| Reconciliation\tof\tAdjusted\tEarnings\tPer\tShare | 2010 | 2009 | 2008 |
| Diluted\tearnings\t(loss)\tper\tshare\tfrom\tcontinuing\toperations | $(0.11) | $1.06 | $1.73 |
| Derivative\tmark-to-market\t(gains)\tlosses^(1) | (0.01) | 0.02 | 0.05 |
| Currency\ttransaction\t(gains)\tlosses^(2) | (0.04) | (0.04) | 0.17 |
| Disposition/acquisition\t(gains)\tlosses | —\t\t(3) | (0.19)^(4) | (1.27)^(5) |
| Impairment\tlosses | 1.07^(6) | 0.21^(7) | 0.13^(8) |
| Debt\tretirement\t(gains)\tlosses | 0.03^(9) | — | 0.25^(10) |
| Adjusted\tearnings\tper\tshare | $0.94 | $1.06 | $1.06 |

Unrealized	foreign	currency	transaction	(gains)	losses	were	net	of	income	tax	per	share	of	$0.00,	$0.01	and	$0.00	in	2010,	2009	and	2008,	respectively. The	Company	has	not	adjusted	for	the	gain	or	the	related	tax	effect	from	the	sale	of	its	indirect	investment	in	CEMIG,	disclosed	in	Note	7—Investments	in	and Advances	to	Affiliates,	in	its	determination	of	Adjusted	EPS	because	the	gain	was	recognized	by	an	equity	method	investee.	The	Company	does	not	adjust	for transactions	of	its	equity	method	investees	in	its	determination	of	adjusted	EPS.

Amount	includes:	Kazakhstan	gain	of	$98	million,	or	$0.15	per	share,	related	to	the	termination	of	a	management	agreement	as	well	as	a	gain	of	$13	million,	or $0.02	per	share,	related	to	the	reversal	of	a	withholding	tax	contingency.	In	addition,	there	was	a	gain	on	sale	associated	with	the	shutdown	of	the	Hefei	plant	in China	of	$14	million,	or	$0.02	per	share.	There	were	no	taxes	associated	with	any	of	these	transactions.

Amount	includes:	Net	gain	on	Kazakhstan	sale	of	$905	million,	or	$1.31	per	share,	and	net	loss	on	sale	of	subsidiary	interests	in	Gener	of	$31	million,	or	$0.04 per	share.	There	was	no	income	tax	impact	associated	with	these	transactions.

Amount	primarily	includes	asset	impairments	at	Eastern	Energy	of	$827	million,	Southland	(Huntington	Beach)	of	$200	million,	Tisza	of	$85	million,	and Deepwater	of	$79	million	($537	million,	or	$0.69	per	share,	$130	million,	or	$0.17	per	share,	$69	million,	or	$0.09	per	share,	and	$51	million,	or	$0.07	per	share, net	of	income	tax,	respectively)	and	goodwill	impairment	at	Deepwater	of	$18	million	(or	$0.02	per	share,	with	no	income	tax	impact).

Amount	includes:	Goodwill	impairments	at	Kilroot	of	$118	million,	or	$0.18	per	share,	and	in	the	Ukraine	of	$4	million,	or	$0.01	per	share;	write-off	of development	project	costs	in	Latin	America	and	Asia	of	$19	million	($11	million	net	of	noncontrolling	interests,	or	$0.01	per	share)	and	an	impairment	of	$10 million,	or	$0.01	per	share,	of	the	Company's	investment	in	a	company	developing	"blue	gas"	(coal	to	gas)	technology.	There	was	no	income	tax	impact associated	with	any	of	these	transactions.

Amount	includes:	Impairment	charges	primarily	associated	with	development	projects	in	North	America	of	$75	million	($34	million	net	of	noncontrolling interests	and	income	tax,	or	$0.06	per	share);	Uruguaiana	asset	write-down	of	$36	million	($17	million	net	of	noncontrolling	interest,	or	$0.02	per	share);	South Africa	peaker	development	cost	write-off	of	$31	million	($28	million	net	of	income	tax,	or	$0.04	per	share)	and	a	nontaxable	impairment	of	the	Company's investment	in	"blue	gas"	(coal	to	gas)	technology	of	$10	million,	or	$0.01	per	share.	Impairment	losses	are	net	of	an	income	tax	benefit	of	$0.02	per	share	in 2008.

Amount	includes	loss	on	retirement	of	debt	at	the	Parent	Company	of	$15	million,	at	Andres	of	$10	million,	and	at	Itabo	of	$8	million	($10	million,	or	$0.01	per share,	net	of	income	tax	at	the	Parent	Company,	$0.01	per	share	at	Andres,	and	$4	million,	or	$0.01	per	share,	net	of	noncontrolling	interest	at	Itabo). Amount	includes:	$55	million	($34	million	net	of	income	tax,	or	$0.05	per	share)	loss	on	the	retirement	of	Parent	Company	debt;	$131	million,	or	$0.19	per share,	which	represented	the	tax	impact	on	the	repatriation	of	a	portion	of	the	Kazakhstan	sale	proceeds	that	were	used	to	fund	the	early	retirement	of	Parent Company	debt;	and	$14	million	($9	million	net	of	income	tax,	or	$0.01	per	share)	of	debt	refinancing	at	IPALCO.	Debt	retirement	(gains)	losses	are	net	of	an income	tax	benefit	of	$0.04	per	share	in	2008.

# Management's	Priorities

Management	continues	to	focus	on	the	following	priorities:

•Execution	of	our	balanced	capital	allocation	strategy	including	funds	received	in	2010	from	asset	and	equity	sales:

•investing	in	value-accretive	projects;

•delevering	to	increase	financial	flexibility,	reduce	risk	and	to	create	future	borrowing	capacity;	and

•executing	its	stock	repurchase	program;	from	July	through	December	2010	we	have	repurchased	a	total	of	$99	million,	or	approximately 8.4	million	shares	of	AES	common	stock,	at	an	average	price	per	share	of	$11.86,	including	commissions.

•Improvement	of	operations	in	the	existing	portfolio;

•	 Achieve	cost	savings	through	the	alignment	of	overhead	costs	with	business	requirements,	systems	automation	and	optimal	allocation	of	business development	spending;

•Strategic	portfolio	management	of	existing	projects	including	restructuring	and	potential	sales	of	certain	North	American	generation	subsidiaries;

•	 Completion	of	an	approximately	1,300	MW	active	construction	program	on	time	and	within	budget;

•	 Achieving	commercial	operation	at	Maritza	in	Bulgaria.	At	the	end	of	2010,	the	Company	experienced	certain	commissioning	delays,	as	further	described in	Key	Trends	and	Uncertainties—Development	below;	and

•Integration	of	new	projects.	During	2010,	the	following	projects	were	acquired	or	commenced	commercial	operations:

|  |  |  | Gross | AES	Equity	Interest |
| :--- | :--- | :--- | :--- | :--- |
| Project | Location | Fuel | MW | (Percent,\tRounded) |
| Ballylumford | United\tKingdom | Gas | \t1,246 | 100% |
| JHRH^(1) | China | Hydro | 379 | 35% |
| Nueva\tVentanas | Chile | Coal | 272 | 71% |
| St.\tNikola | Bulgaria | Wind | 156 | 89% |
| Guacolda\t4^(2) | Chile | Coal | 152 | 35% |
| Dong\tQi^(3) | China | Wind | 49 | 49% |
| Huanghua\tII^(3) | China | Wind | 49 | 49% |
| St.\tPatrick | France | Wind | 35 | 100% |
| North\tRhins | Scotland | Wind | 22 | 100% |
| Kepezkaya | Turkey | Hydro | 28 | 51% |
| Damlapinar^(4) | Turkey | Hydro | 16 | 51% |

# Key	Trends	and	Uncertainties

Our	operations	continue	to	face	many	risks	as	discussed	in	Item	1A.—Risk	Factors	of	this	Form	10-K.	Some	of	these	challenges	are	also	described	above	in	Key Drivers	of	Results	in	2010.	We	continue	to	monitor	our	operations	and	address	challenges	as	they	arise.

Development.	During	the	past	year,	the	Company	has	successfully	acquired	and	completed	construction	of	a	number	of	projects,	totaling	approximately	2,404	MW, including	the	acquisition	of	Ballylumford	in	the	United	Kingdom	and	completion	of	construction	of	a	number	of	projects	in	Europe,	Chile	and	China.	However,	as discussed	in	Item	1A.—Risk	Factors—Our	business	is	subject	to	substantial	development	uncertainties	of	this	Form	10-K,	our	development	projects	are	subject	to uncertainties.	Certain	delays	have	occurred	at	the	670	MW	Maritza	coal-fired	project	in	Bulgaria,	and	the	project	has	not	yet	begun	commercial	operations.	As	noted	in Note	10—Debt	included	in	Item	8	of	this	Form	10-K,	as	a	result	of	these	delays	the	project	debt	is	in	default	and	the	Company	is	working	with	its	lenders	to	resolve	the default.	In	addition,	as	noted	in	Item	3.—Legal	Proceedings,	the	Company	is	in	litigation	with	the	contractor	regarding	the	cause	of	delays.	At	this	time,	we	believe	that Maritza	will	commence	commercial	operations	for	at	least	some	of	the	project's	capacity	by	the	second	half	of	2011.	However,	commencement	of	commercial operations	could	be	delayed	beyond	this	time	frame.	There	can	be	no	assurance	that	Maritza	will	achieve	commercial	operations,	in	whole	or	in	part,	by	the	second	half of	2011,	resolve	the	default	with	the	lenders	or	prevail	in	the	litigation	referenced	above,	which	could	result	in	the	loss	of	some	or	all	of	our	investment	or	require additional	funding	for	the	project.	Any	of	these	events	could	have	a	material	adverse	effect	on	the	Company's	operating	results	or	financial	position.

Global	Economic	Conditions.	During	the	past	few	years,	economic	conditions	in	some	countries	where	our	subsidiaries	conduct	business	have	deteriorated. Although	the	economic	conditions	in	several	of	these	countries	have	improved	in	recent	months,	our	businesses	could	be	impacted	in	the	event	these	recent	trends	do	not continue.

Our	business	or	results	of	operations	could	be	impacted	if	our	subsidiaries	are	unable	to	access	the	capital	markets	on	favorable	terms	or	at	all,	are	unable	to	raise funds	through	the	sale	of	assets	or	are	otherwise	unable	to	finance	or	refinance	their	activities.	The	Company	could	also	be	adversely	affected	if	capital	market disruptions	result	in	increased	borrowing	costs	(including	with	respect	to	interest	payments	on	the	Company's	or	our	subsidiaries'	variable	rate	debt)	or	if	commodity prices	affect	the	profitability	of	our	plants	or	their	ability	to	continue	operations.	Additionally,	the	Company	could	be	adversely	affected	if	general	economic	or	political conditions	in	the	markets	where	our	subsidiaries	operate	deteriorate,	resulting	in	a	reduction	in	cash	flow	from	operations,	a	reduction	in	the	availability	and/or	an increase	in	the	cost	of	capital,	or	if	the	value	of	our	assets	remain	depressed	or	decline	further.	Any	of	the	foregoing	events	or	a	combination	thereof	could	have	a material	impact	on	the	Company,	its	results	of	operations,	liquidity,	financial	covenants,	and/or	its	credit	rating.

Our	subsidiaries	are	subject	to	credit	risk,	which	includes	risk	related	to	the	ability	of	counterparties	(such	as	parties	to	our	PPAs,	fuel	supply	agreements,	hedging agreements	and	other	contractual	arrangements)	to	deliver	contracted	commodities	or	services	at	the	contracted	price	or	to	satisfy	their	financial	or	other	contractual obligations.	The	Company	has	not	suffered	any	material	effects	related	to	its	counterparties	during	2010.	However,	if	macroeconomic	conditions	impact	our counterparties,	they	may	be	unable	to	meet	their	commitments	which	could	result	in	the	loss	of	favorable	contractual	positions,	which	could	have	a	material	impact	on our	business.

In	addition,	during	the	past	year,	certain	European	countries	have	faced	a	sovereign	debt	crisis	and	it	is	possible	that	other	nations	could	be	affected.	This	crisis has	resulted	in	an	increased	risk	of	default	by	governments	and	the	implementation	of	austerity	measures	in	countries.	If	the	crisis	continues,	worsens,	or	spreads,	there could	be	a	material	adverse	impact	on	the	Company.	Our	businesses	may	be	impacted	if	they	are	unable	to	access	the	capital	markets,	face	increased	taxes	or	labor	costs, or	if	governments	fail	to	fulfill	their	obligations	to	us	or	adopt	austerity	measures	which	adversely	impact	our	projects.	In	addition,	as	noted	in	the	Risk	Factor	entitled, "Our	renewable	energy	projects	and	other	initiatives	face	considerable	uncertainties	including	development,	operational	and	regulatory	challenges,"	our	renewables businesses	are	dependent	on	favorable	regulatory	incentives,	including	subsidies,	which	are	provided	by	sovereign	governments.	If	these	subsidies	or	other	incentives	are reduced	or	repealed,	or	sovereign	governments	are	unable	or	unwilling	to	fulfill	their	commitments	or	maintain	favorable	regulatory	incentives	for	renewables,	in	whole or	in	part,	this	could	impact	the	ability	of	the	affected	businesses	to	continue	to	grow	their	operations.	For	example,	the	Spanish	government	recently	issued	a	decree which	limits	the	feed-in-tariff	and	number	of	photovoltaic	hours	eligible	for	the	tariff,	which	could	adversely	impact	AES	Solar	in	Spain.	For	further	information	on	the decree	see	Item	1.—	Regulatory—Spain	of	this	Form	10-K.	In	addition,	any	of	the	foregoing	could	also	impact	contractual	counterparties	of	our	subsidiaries	in	core power	or	renewables.	If	such	counterparties	are	adversely	impacted,	then	they	may	be	unable	to	meet	their	commitments	to	our	subsidiaries.	For	further	information	on the	importance	of	long-term	contracts	and	our	counterparty	credit	risk,	see	the	Risk	Factor	from	this	Form	10-K	titled,	"We	may	not	be	able	to	enter	into	long-term contracts,	which	reduce	volatility	in	our	results	of	operations…".	As	a	result	of	any	of	the	foregoing	events,	we	may	have	to	provide	loans	or	equity	to	support	affected businesses	or	projects,	restructure	them,	write	down	their	value	and/or	face	the	possibility	that	these	projects	cannot	continue	operations	or	provide	returns	consistent with	our	expectations,	any	of	which	could	have	a	material	impact	on	the	Company.	The	Company's	investment	in	AES	Solar,	whose	primary	operations	are	in	Europe,	at December	31,	2010	was	$312	million.

For	a	discussion	of	the	risks	associated	with	commodity	prices,	see	"We	may	not	be	adequately	hedged	against	our	exposure	to	changes	in	commodity	prices	or interest	rates"	in	Item	1A.—Risk	Factors	of	this	Form	10-K.	It	is	also	possible	that	commodity	or	power	price	volatility	could	continue	to	impact	our	financial	results. As	noted	in	Key	Drivers	of	Results	in	2010,	and	Item	7A.—Quantitative	and	Qualitative	Disclosures	About	Market	Risk—Commodity	Price	Risk	of	this	Form	10-K,	the Company's	North	American	businesses	continue	to	face	pressure	as	a	result	of	high	coal	prices	relative	to	natural	gas,	which	has	affected	the	results	of	certain	of	our coal	plants	in	the	region,	particularly	those	which	are	merchant	plants	that	are	exposed	to	market	risk	and	those	that	have	hybrid	merchant	risk,	meaning	those businesses	that	have	a	PPA	in	place,	but	purchase

fuel	at	market	prices	or	under	short	term	contracts.	If	these	conditions	continue	or	worsen,	these	businesses	may	need	to	restructure	their	obligations	or	seek	additional funding	(including	from	the	Parent)	or	face	the	possibility	that	they	may	be	unable	to	meet	their	obligations	and	continue	operations.	Presently,	Eastern	Energy, Deepwater	and	Thames	are	seeking	to	restructure	their	financial	obligations	and/or	place	certain	of	their	plants	in	protective	layup	status	to	mitigate	operating	risks caused	by	high	fuel	costs	and	other	competitive	pressures.	There	can	be	no	assurance	the	Company	will	be	successful	in	these	efforts.

The	Company	presently	manages	its	commodity	risk	with	hedging	activities	to	mitigate	earnings	volatility.	However,	at	present	in	North	America,	dark	spreads and	the	corresponding	forward	curves	do	not	currently	present	an	opportunity	to	engage	in	additional	hedging	activity	for	2011.	As	a	result,	there	are	hedging arrangements	in	place	for	only	a	relatively	small	portion	of	2011.	As	short-term	opportunities	occur	or	should	dark	spreads	improve,	the	Company	may	engage	in additional	hedging	in	2011.	Specifically,	the	operating	results	of	the	Company's	Eastern	Energy	generation	business	in	New	York	could	be	adversely	impacted	by continued	higher	coal	prices	relative	to	electricity	prices	if	hedging	continues	to	be	uneconomic.

If	global	economic	conditions	worsen,	it	could	also	affect	the	rates	we	receive	for	the	electricity	we	generate	or	transmit.	Utility	regulators	or	parties	to	our generation	contracts	may	seek	to	lower	our	rates	based	on	prevailing	market	conditions	as	PPAs,	concession	agreements	or	other	contracts	come	up	for	renewal	or	reset. In	addition,	rising	fuel	and	other	costs	coupled	with	contractual	rate	or	tariff	decreases	could	restrict	our	ability	to	operate	profitably	in	a	given	market.	Each	of	these factors,	as	well	as	those	discussed	above,	could	result	in	a	decline	in	the	value	of	our	assets	including	those	at	the	businesses	we	operate,	our	equity	investments	and projects	under	development	and	could	result	in	asset	impairments	that	could	be	material	to	our	operations.	We	continue	to	monitor	our	projects	and	businesses.

# Impairments.

Long-lived	assets.	The	global	economic	conditions	and	other	adverse	factors	discussed	above	heighten	the	risk	of	a	significant	asset	impairment.	Examples	of conditions	that	could	be	indicative	of	impairment	which	would	require	us	to	evaluate	the	recovery	of	a	long-lived	asset	or	asset	group	include:

•current	period	operating	or	cash	flow	losses	combined	with	a	history	of	operating	or	cash	flow	losses	or	a	projection	that	demonstrates	continuing	losses associated	with	the	use	of	a	long-lived	asset	group;

•a	significant	adverse	change	in	legal	factors,	including	changes	in	environmental	or	other	regulations	or	in	the	business	climate	that	could	affect	the	value	of a	long-lived	asset	group,	including	an	adverse	action	or	assessment	by	a	regulator;	and

•a	significant	adverse	change	in	the	extent	or	manner	in	which	a	long-lived	asset	group	is	being	used	or	in	its	physical	condition.

As	further	described	in	Item	1.—Regulatory	Matters—United	Kingdom,	the	Northern	Ireland	Authority	for	Utility	Regulation	("NIAUR")	had	the	right	to	require the	termination	of	the	long-term	PPAs	under	which	Kilroot,	our	generation	business	in	the	United	Kingdom,	supplies	electricity	to	NIE	Energy	as	early	as	2010.	One	of the	conditions	to	the	early	termination	was	180	days'	notice,	which	was	provided	to	Kilroot	on	April	30,	2010.	At	March	31,	2010,	management	evaluated	Kilroot's long-lived	assets	for	potential	impairment	assuming	the	early	termination	of	the	PPA	and	concluded	that	no	impairment	existed	at	that	time.	On	October	28,	2010, Kilroot	received	final	notice	from	NIAUR	directing	Kilroot	and	NIE	Energy	to	terminate	the	PPA	effective	November	1,	2010.	Kilroot	may	not	be	able	to	replace	the contract	on	competitive	terms	and,	upon	cancellation	of	the	PPA	effective	November	1,	2010,	became	a	merchant	plant.	It	will	operate	under	the	gross	mandatory	pool of	the	SEM	in	Northern	Ireland.	There	have	been	no	additional	impairment	indicators	since	March	31,	2010.

AES	Eastern	Energy	("AEE")	operates	four	coal-fired	power	plants:	Cayuga,	Greenidge,	Somerset	and	Westover,	representing	generation	capacity	of	1,169	MW in	the	western	New	York	power	market.	During	2010,	the	power	prices	in	the	New	York	power	market	trended	downward,	similar	to	North	America	natural	gas	prices.

The	New	York	Independent	System	Operator	("NYISO")	continues	to	move	forward	with	the	potential	addition	of	a	new	capacity	zone,	which	is	expected	to	put	further downward	pressure	on	the	capacity	prices	paid	to	the	AEE	facilities.	In	November	2010,	legislation	was	proposed	in	the	state	of	New	Jersey	for	the	addition	of	state subsidized	capacity	additions	serving	to	lower	PJM	capacity	price	expectations.	Similar	changes	to	capacity	pricing	may	be	made	in	the	future	in	New	York.	Continued pressure	on	energy	prices,	driven	by	falling	natural	gas	prices	and	state	actions,	indicate	that	capacity	prices	are	unlikely	to	reach	levels	significantly	in	excess	of	those achieved	historically.	Accordingly,	management's	view	of	long-term	capacity	markets	in	western	New	York	was	revised	downward.	In	December	2010,	management revised	its	cash	flow	forecasts	based	on	these	developments	and	forecasted	continuing	negative	operating	cash	flow	and	losses	through	2034.	The	forecasted	energy prices	are	such	that	a	hedge	strategy	significantly	beyond	those	in	place	at	December	31,	2010	would	not	be	economical.	Additionally,	on	November	15,	2010, Standard	&	Poor's	downgraded	the	bond	rating	of	AEE	from	BB	to	B+.	Collectively,	in	the	fourth	quarter	of	2010,	these	events	were	considered	an	impairment	indicator for	the	AES	New	York	asset	group,	of	which	AEE	is	the	most	significant	component	and	necessitated	an	impairment	evaluation	of	the	asset	group.

The	long-lived	asset	group	subject	to	the	impairment	evaluation	was	determined	to	include	all	of	the	generating	plants	of	AEE.	This	determination	was	based	on the	assessment	of	the	plants'	inability	to	generate	independent	cash	flow.	When	the	recoverability	test	of	the	asset	group	was	performed,	management	concluded	that,	on an	undiscounted	cash	flow	basis,	the	carrying	amount	of	the	asset	group	was	not	recoverable.	To	measure	the	amount	of	impairment	loss,	management	was	required	to determine	the	fair	value	of	the	asset	group.	To	this	end,	an	independent	valuation	firm	was	engaged	to	assist	management	in	its	estimation	of	fair	value.	Cash	flow forecasts	and	the	underlying	assumptions	for	the	valuation	were	developed	by	management.	While	there	were	numerous	assumptions	that	impact	the	fair	value,	potential state	actions	that	impact	capacity	pricing	and	forward	energy	prices	were	the	most	significant.

In	determining	the	fair	value	of	the	asset	group,	the	three	valuation	approaches	prescribed	by	the	fair	value	measurement	accounting	guidance	were	considered. The	fair	value	under	the	income	approach	was	considered	the	most	appropriate	and	resulted	in	a	zero	fair	value.	Any	salvage	value	of	the	asset	group	is	expected	to	be offset	by	environmental	and	other	remediation	costs.	Accordingly,	the	long-lived	asset	group	was	considered	fully	impaired	and	$827	million	of	impairment	expense	was recognized	in	the	fourth	quarter	of	2010.

In	March	2010,	Deepwater,	our	160	MW	petroleum	coke	("pet	coke")-fired	merchant	power	plant	located	in	Texas,	experienced	deteriorating	market	conditions due	to	increasing	pet	coke	prices	and	diminishing	power	prices.	As	a	result,	Deepwater	incurred	an	operating	loss	for	the	period	and	forecasted	short	term	losses.	These conditions	gradually	worsened	in	the	second	quarter	of	2010	and	management	determined	it	could	not	operate	the	plant	at	certain	times	during	the	year	without generating	negative	operating	margin.

As	the	contraction	of	energy	margin	continued	in	the	second	quarter	of	2010,	management	determined	the	collective	events	to	be	an	indicator	of	impairment	and performed	an	impairment	evaluation	of	Deepwater's	goodwill	and	recoverability	test	for	the	long-lived	asset	group.	Based	on	the	results	of	these	tests,	in	the	second quarter	of	2010,	management	concluded	no	impairment	was	necessary.	In	the	third	quarter	of	2010,	these	downward	trends	continued	and	management,	after determining	that	there	was	an	indicator	of	impairment,	performed	another	impairment	evaluation	of	Deepwater's	goodwill	and	a	recoverability	test	of	the	long-lived	asset group.	The	results	in	the	third	quarter	indicated	no	impairment	was	necessary	for	the	asset	group,	but	the	goodwill	associated	with	the	reporting	unit	was	deemed	to	be impaired	and	the	$18	million	goodwill	balance	was	written-off	during	the	quarter	ended	September	30,	2010.

In	the	fourth	quarter	of	2010,	further	adverse	trends	in	energy	and	pet	coke	pricing	curves	were	observed	in	management's	review	of	external	market	analyses. The	most	significant	impact	on	the	forecasted	energy	prices	reviewed	by	management	in	November	2010	related	to	the	general	external	market	consensus	that	Federal CO 	cap	and	trade	legislation	was	less	likely,	resulting	in	a	drop	in	long-term	energy	price	projections.	At	that	time,	Deepwater's	revised	forecasts	indicated	that Deepwater	would	have	operating	losses	which	would	extend	beyond

2020	and	negative	cash	flows	through	2019.	Management	concluded	that,	on	an	undiscounted	cash	flow	basis,	the	carrying	amount	of	the	asset	group	was	no	longer recoverable.	To	measure	the	amount	of	impairment	loss,	management	was	required	to	determine	the	fair	value	of	the	asset	group.	To	this	end,	an	independent	valuation firm	was	engaged	to	assist	management	in	its	estimation	of	fair	value.	Cash	flow	forecasts	and	the	underlying	assumptions	for	the	valuation	were	developed	by management.	In	determining	the	fair	value	of	the	asset	group,	all	three	valuation	approaches	described	by	the	fair	value	measurement	accounting	guidance	were considered.	The	fair	value	under	the	income	approach	was	considered	most	appropriate.	On	that	basis,	the	carrying	value	of	the	asset	group	was	determined	to	be impaired	and	$79	million	of	impairment	expense	was	recognized	in	the	fourth	quarter	of	2010.

In	May	2010,	the	California	State	Water	Board	approved	a	policy	to	reduce	the	number	of	marine	animals	killed	by	seawater	cooling	systems	in	coastal	power plants	in	California.	At	that	time,	since	the	policy	required	the	approval	of	California's	Office	of	Administrative	Law,	it	was	unclear	whether	the	policy	would	be approved	and	what	form	the	regulations	would	take.	In	September	2010,	the	Office	of	Administrative	Law	in	California	approved	the	policy	that	will	require	the Company	to	change	the	process	through	which	it	uses	ocean	water	to	cool	the	generation	turbines	at	its	Alamitos,	Huntington	Beach	and	Redondo	Beach	(collectively "Southland")	gas-fired	generation	facilities	in	California.	The	policy	requires	compliance	with	the	new	regulations	by	December	31,	2020.	The	change	in	the	water cooling	process	will	result	in	significant	future	capital	expenditures	to	ensure	compliance	with	the	new	regulations.	This	was	considered	as	an	impairment	indicator	for the	long-lived	asset	groups.	The	recoverability	test	of	the	long-lived	asset	groups	indicated	that	the	carrying	amount	of	the	Huntington	Beach	asset	group	was	not recoverable	on	an	undiscounted	cash	flows	basis.	To	assist	management	in	determining	the	fair	value	of	the	asset	group,	an	independent	valuation	firm	was	engaged. Cash	flow	forecasts	and	the	underlying	assumptions	for	the	valuation	were	developed	by	management.	The	carrying	amount	of	the	Huntington	Beach	asset	group exceeded	its	fair	value	by	$200	million	which	was	recognized	as	an	impairment	expense.	The	carrying	amounts	of	the	Alamitos	and	Redondo	Beach	long-lived	asset groups	were	determined	to	be	recoverable	on	an	undiscounted	cash	flows	basis	at	September	30,	2010	and	no	impairment	was	necessary.

During	the	third	quarter	of	2010,	we	also	recognized	impairment	on	the	long-lived	assets	at	our	Tisza	II	generation	plant	in	Hungary.	Tisza	II	operates	under	an annual	contract	with	an	off-taker.	In	the	third	quarter	of	2010,	when	Tisza	II	began	the	negotiation	of	its	2011	contract,	future	undiscounted	cash	flows	of	the	plant	were no	longer	expected	to	recover	the	long-lived	assets	group's	carrying	amount	due	to	prevailing	market	rates,	higher	generation	costs	and	lower	demand	expectations. Accordingly,	the	Company	measured	the	fair	value	of	the	long-lived	asset	group	and	recorded	an	impairment	expense	of	$85	million,	representing	the	excess	of	carrying amount	over	the	fair	value	at	September	30,	2010.

Goodwill.	The	Company	seeks	business	acquisitions	as	one	of	its	growth	strategies.	We	have	achieved	significant	growth	in	the	past	as	a	result	of	several	business acquisitions,	which	also	resulted	in	the	recognition	of	goodwill.	As	noted	in	Item	1A.—Risk	Factors	of	this	Form	10-K,	there	is	always	a	risk	that	"Our	acquisitions	may not	perform	as	expected."	The	benefits	of	goodwill	are	typically	realized	through	the	future	operating	results	of	an	acquired	business.	Management	believes	that	the recoverability	of	goodwill	is	positively	correlated	with	the	economic	environments	in	which	our	acquired	businesses	operate	and	a	severe	economic	downturn	could negatively	impact	the	recoverability	of	goodwill.	Also,	the	evolving	environmental	regulations,	including	GHG	regulations,	around	the	globe	continue	to	increase	the operating	costs	of	our	generation	businesses.	In	extreme	situations,	the	environmental	regulations	could	even	make	a	once	profitable	business	uneconomical.	In	addition, most	of	our	generation	businesses	have	a	finite	life	and	as	the	acquired	businesses	reach	the	end	of	their	finite	lives,	the	carrying	amount	of	goodwill	is	gradually recovered	through	their	periodic	operating	results.	The	accounting	guidance,	however,	prohibits	the	systematic	amortization	of	goodwill	and	rather	requires	an	annual impairment	evaluation.	Thus,	as	some	of	our	acquired	businesses	approach	the	end	of	their	finite	lives,	they	may	incur	goodwill	impairment	charges	even	if	there	are	no discrete	adverse	changes	in	the	economic	environment.

As	noted	in	Long-lived	assets	above,	adverse	market	conditions	at	Deepwater	were	also	considered	an	interim	impairment	indicator	for	its	goodwill.	Accordingly, in	the	second	and	third	quarters	of	2010,	interim

goodwill	impairment	evaluations	were	performed	at	the	Deepwater	reporting	unit	level.	The	reporting	unit	passed	Step	1	of	goodwill	impairment	evaluation	in	the	second quarter	and	no	impairment	was	recognized.	In	the	third	quarter,	however,	the	reporting	unit	failed	Step	1	of	goodwill	impairment	evaluation.	Upon	measurement	of impairment	loss	in	Step	2,	the	entire	$18	million	goodwill	balance	was	considered	impaired	and	recognized	as	goodwill	impairment.

In	the	fourth	quarter	of	2010,	the	Company	completed	its	annual	goodwill	impairment	evaluation	and	did	not	have	any	reporting	units	that	were	considered	"at risk."	A	reporting	unit	is	considered	"at	risk"	when	its	fair	value	is	not	higher	than	its	carrying	amount	by	more	than	10%.	While	there	were	no	potential	impairment indicators	that	could	result	in	the	recognition	of	goodwill	impairment	for	any	of	these	reporting	units,	it	is	possible	we	may	incur	goodwill	impairment	on	these	reporting units	in	future	years	if	any	of	the	following	events	occur:	a	significant	adverse	change	in	business	climate	or	legal	factors,	an	adverse	action	or	assessment	by	a	regulator, a	sale	of	assets	at	less	than	carrying	amount,	unanticipated	competition,	a	loss	of	key	personnel,	an	acquisition	not	performing	as	expected,	changing	environmental regulations	that	significantly	increase	the	cost	of	doing	business,	or	a	business	reaches	the	end	of	its	finite	life.	The	likelihood	of	the	occurrence	of	these	events	may increase	because	of	the	challenging	global	macroeconomic	conditions.

Regulatory—	Environment.	The	Company	faces	certain	risks	and	uncertainties	related	to	numerous	environmental	laws	and	regulations,	including	existing	and potential	GHG	legislation	or	regulations,	and	actual	or	potential	laws	and	regulations	pertaining	to	water	discharges,	waste	management	(including	disposal	of	coal combustion	byproducts),	and	certain	air	emissions,	such	as	SO ,	NO ,	particulate	matter	and	mercury.	For	a	description	of	material	regulations	faced	by	the	Company, see	Item	1.	—Business	—Regulatory	Matters.	Such	risks	and	uncertainties	could	result	in	increased	capital	expenditures	or	other	compliance	costs	which	could	have	a material	adverse	effect	on	certain	of	our	United	States	or	international	subsidiaries	and	our	consolidated	results	of	operations.	For	further	information	about	these	risks, see	Item	1A.—Risk	Factors,	"Our	businesses	are	subject	to	stringent	environmental	laws	and	regulations",	"Our	businesses	are	subject	to	enforcement	initiatives	from environmental	regulatory	agencies"	and	"Regulators,	politicians,	non-governmental	organizations	and	other	private	parties	have	expressed	concern	about	greenhouse gas,	or	GHG,	emissions	and	the	potential	risks	associated	with	climate	change	and	are	taking	actions	which	could	have	a	material	adverse	impact	on	our	consolidated results	of	operations,	financial	condition	and	cash	flows"	set	forth	in	this	Form	10-K.

# Recent	Events

# Consolidated	Results	of	Operations

|  |  |  |  | $	change | $	change |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Results\tof\toperations | 2010 | 2009 | 2008 | 2010\tvs.\t2009 | 2009\tvs.\t2008 |
|  |  | (in\tmillions,\texcept\tper\tshare\tamounts) | (in\tmillions,\texcept\tper\tshare\tamounts) |  |  |
| Revenue: |  |  |  |  |  |
| Latin\tAmerica\tGeneration | $4,281 | $3,651 | $4,468 | $630 | $(817) |
| Latin\tAmerica\tUtilities | 7,222 | 6,092 | 5,907 | 1,130 | 185 |
| North\tAmerica\tGeneration | 1,972 | 1,940 | 2,234 | 32 | (294) |
| North\tAmerica\tUtilities | 1,145 | 1,068 | 1,079 | 77 | (11) |
| Europe\tGeneration | 1,362 | 820 | 1,143 | 542 | (323) |
| Asia\tGeneration | 618 | 375 | 345 | 243 | 30 |
| Corporate\tand\tOther^(1) | 1,066 | 870 | 1,012 | 196 | (142) |
| Eliminations^(2) | (1,019) | (862) | (991) | (157) | 129 |
| Total\tRevenue | $16,647 | $13,954 | $15,197 | $2,693 | $(1,243) |
| Gross\tMargin: |  |  |  |  |  |
| Latin\tAmerica\tGeneration | $1,497 | $1,357 | $1,398 | $140 | $(41) |
| Latin\tAmerica\tUtilities | 1,072 | 918 | 886 | 154 | 32 |
| North\tAmerica\tGeneration | 435 | 477 | 660 | (42) | (183) |
| North\tAmerica\tUtilities | 249 | 239 | 261 | 10 | (22) |
| Europe\tGeneration | 268 | 212 | 273 | 56 | (61) |
| Asia\tGeneration | 240 | 93 | (10) | 147 | 103 |
| Corporate\tand\tOther^(3) | 186 | 117 | 62 | 69 | 55 |
| Eliminations^(4) | 17 | 20 | 38 | (3) | (18) |
| General\tand\tadministrative\texpenses | (392) | (339) | (368) | (53) | 29 |
| Interest\texpense | (1,526) | (1,485) | (1,770) | (41) | 285 |
| Interest\tincome | 411 | 348 | 519 | 63 | (171) |
| Other\texpense | (239) | (111) | (161) | (128) | 50 |
| Other\tincome | 108 | 465 | 375 | (357) | 90 |
| Gain\ton\tsale\tof\tinvestments | — | 131 | 909 | (131) | (778) |
| Loss\ton\tsale\tof\tsubsidiary\tstock | — | — | (31) | — | 31 |
| Goodwill\timpairment | (21) | (122) | — | 101 | (122) |
| Asset\timpairment\texpense | (1,221) | (25) | (175) | (1,196) | 150 |
| Foreign\tcurrency\ttransaction\tgains\t(losses)\ton\tnet\tmonetary\tposition | (33) | 33 | (184) | (66) | 217 |
| Other\tnon-operating\texpense | (7) | (12) | (15) | 5 | 3 |
| Income\ttax\texpense | (307) | (599) | (771) | 292 | 172 |
| Net\tequity\tin\tearnings\tof\taffiliates | 183 | 92 | 33 | 91 | 59 |
| Income\tfrom\tcontinuing\toperations | 920 | 1,809 | 1,929 | (889) | (120) |
| Income\tfrom\toperations\tof\tdiscontinued\tbusinesses | 75 | 96 | 97 | (21) | (1) |
| Gain\t(loss)\tfrom\tdisposal\tof\tdiscontinued\tbusinesses | 64 | (150) | 6 | 214 | (156) |
| Net\tincome | 1,059 | 1,755 | 2,032 | (696) | (277) |
| Noncontrolling\tinterests: |  |  |  |  |  |
| Income\tfrom\tcontinuing\toperations\tattributable\tto\tnoncontrolling\tinterests | (1,006) | (1,099) | (759) | 93 | (340) |
| (Income)\tloss\tfrom\tdiscontinuing\toperations\tattributable\tto\tnoncontrolling\tinterests | (44) | 2 | (39) | (46) | 41 |
| Net\tincome\tattributable\tto\tThe\tAES\tCorporation | $9 | $658 | $1,234 | $(649) | $(576) |
| Per\tShare\tData: |  |  |  |  |  |
| Basic\tincome\tper\tshare\tfrom\tcontinuing\toperations | $(0.11) | $1.06 | $1.75 | $(1.17) | $(0.69) |
| Diluted\tincome\tper\tshare\tfrom\tcontinuing\toperations | $(0.11) | $1.06 | $1.73 | $(1.17) | $(0.67) |

Corporate	and	Other	includes	revenue	from	our	generation	and	utilities	businesses	in	Africa,	utilities	businesses	in	Europe,	Wind	Generation	and	other	renewables initiatives.

Represents	inter-segment	eliminations	of	revenue	related	to	transfers	of	electricity	from	Tietê	(generation)	to	Eletropaulo	(utility).

Corporate	and	Other	gross	margin	includes	gross	margin	from	our	generation	and	utilities	businesses	in	Africa,	utilities	businesses	in	Europe,	Wind	Generation and	other	renewables	initiatives.

Represents	inter-segment	eliminations	of	gross	margin	related	to	corporate	charges	for	self	insurance	premiums.

# Segment	Analysis

The	following	table	summarizes	revenue	and	gross	margin	for	our	Generation	segment	in	Latin	America	for	the	periods	indicated:

|  | 2010 | 2009 | 2008 | %	Change<br>2010	vs.	2009 | %	Change<br>2009	vs.	2008 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | ($'s\tin\tmillions) |  |  |
| Latin\tAmerica\tGeneration |  |  |  |  |  |
| Revenue | $4,281 | $3,651 | $4,468 | 17% | -18% |
| Gross\tMargin | $1,497 | $1,357 | $1,398 | 10% | -3% |

Excluding	the	favorable	impact	of	foreign	currency	translation	and	remeasurement	of	$133	million,	generation	revenue	for	2010	increased	$497	million,	or	14%, from	2009	primarily	due	to:

•higher	spot	prices	of	$221	million	associated	with	increased	fuel	prices	in	Argentina;

•higher	volume	of	$139	million	at	Gener	in	Chile	due	to	higher	demand;

•higher	volume	and	ancillary	services	of	$115	million,	and	higher	contract	prices	from	PPAs	indexed	to	gas	and	higher	spot	prices	of	$27	million	in	the Dominican	Republic;

•higher	contract	prices	of	$58	million	in	Colombia	and	Tietê	in	Brazil;

•the	positive	impact	of	$28	million	resulting	from	the	final	settlement	of	the	power	sales	agreement	between	Sul	and	Uruguaiana,	our	businesses	in	Brazil; and

•higher	volume	of	$21	million	in	Panama	due	to	higher	water	inflows	into	the	system.

•lower	volume	sold	at	Uruguaiana	of	$53	million	as	a	result	of	renegotiation	of	its	power	sales	agreements;

•lower	volume	due	to	unfavorable	hydrology	in	Colombia	and	Argentina	of	$41	million;

•lower	contract	prices	at	Gener	of	$32	million;	and

•lower	contract	prices	on	PPAs	indexed	to	international	coal	prices	in	the	Dominican	Republic	of	$22	million.

Excluding	the	favorable	impact	of	foreign	currency	translation	and	remeasurement	of	$106	million,	generation	gross	margin	for	2010	increased	$34	million,	or 3%,	from	2009	primarily	due	to:

•higher	spot	prices	in	Argentina	of	$69	million;

•higher	volume	and	ancillary	services	in	the	Dominican	Republic	of	$55	million;

•higher	contract	prices	of	$33	million	in	Colombia;

•the	positive	impact	of	$28	million	resulting	from	the	final	settlement	of	the	power	sales	agreement	between	Sul	and	Uruguaiana,	as	mentioned	above;	and •higher	volume	of	$23	million	in	Panama.

•higher	fuel	and	purchased	energy	prices	at	Gener	of	$48	million;

•the	net	effect	of	lower	PPA	prices	and	higher	fuel	costs	in	the	Dominican	Republic	of	$38	million;

•the	impact	of	a	reversal	of	bad	debt	expense	during	the	first	quarter	of	2009	of	$36	million	at	Uruguaiana	as	a	result	of	the	renegotiation	of	one	of	its	power sales	agreements;	and

•higher	fixed	costs	of	$30	million	at	Gener	primarily	due	to	higher	employee	costs,	increased	maintenance	expenses	and	costs	incurred	due	to	construction delays	at	Campiche.

For	the	year	ended	December	31,	2010,	revenue	increased	17%	while	gross	margin	increased	10%,	primarily	due	to	higher	spot	purchases	and	fuel	prices	at	Gener and	the	reversal	of	bad	debt	expense	as	a	result	of	the	renegotiation	of	one	of	the	power	sales	agreements	at	Uruguaiana	in	the	first	quarter	of	2009.

Excluding	the	unfavorable	impact	of	foreign	currency	translation	and	remeasurement	of	$181	million,	driven	by	Brazil	and	Argentina,	generation	revenue	for 2009	decreased	$636	million,	or	14%,	from	2008	primarily	due	to:

•lower	spot	and	contract	prices	of	$295	million	at	Gener;

•lower	volume	of	$227	million	at	Uruguaiana	as	a	result	of	the	renegotiation	of	its	power	sales	agreements	in	2009	to	reduce	the	energy	volume	sold;	and

•lower	energy	prices	and	volume	of	$174	million	in	the	Dominican	Republic.

•and	increase	of	$100	million	due	to	fewer	outages	at	Gener	and	in	Argentina	in	2009;	and

•higher	prices	of	energy	sold	of	$66	million	at	Tietê.

Excluding	the	unfavorable	impact	of	foreign	currency	translation	and	remeasurement	of	$94	million,	driven	by	Brazil	and	Argentina,	generation	gross	margin	for 2009	increased	$53	million,	or	4%,	from	2008	primarily	due	to:

•fewer	outages	of	$60	million	at	Gener	and	in	Argentina;

•lower	diesel	consumption,	partially	offset	by	higher	energy	purchases	and	higher	gas	consumption,	at	Gener	of	$47	million;

•lower	volume	of	energy	purchased	at	Uruguaiana	of	$44	million	as	a	result	of	the	renegotiated	power	sales	agreements;	and

•the	favorable	impact	of	$28	million	of	a	decrease	in	bad	debt	expense	at	Uruguaiana	as	a	result	of	the	renegotiated	power	sales	agreements.

•the	unfavorable	impact	of	lower	energy	prices	of	$75	million	in	the	Dominican	Republic;

•lower	volume	and	energy	prices	of	$66	million	in	Argentina;

•higher	purchased	energy	prices	of	$48	million	at	Uruguaiana;	and

•lower	spot	sales	of	$48	million	at	Panama.

For	the	year	ended	December	31,	2009,	revenue	decreased	by	18%	while	gross	margin	decreased	3%,	primarily	due	to	reduced	energy	purchases,	fewer	outages and	lower	bad	debt	expense.

The	following	table	summarizes	revenue	and	gross	margin	for	our	Utilities	segment	in	Latin	America	for	the	periods	indicated:

|  |  |  |  | %	Change | %	Change |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2010 | 2009 | 2008 | 2010\tvs.\t2009 | 2009\tvs.\t2008 |
|  |  |  | ($'s\tin\tmillions) |  |  |
| Latin\tAmerica\tUtilities |  |  |  |  |  |
| Revenue | $7,222 | $6,092 | $5,907 | 19% | 3% |
| Gross\tMargin | $1,072 | $918 | $886 | 17% | 4% |

Excluding	the	favorable	impact	of	foreign	currency	translation	of	$697	million,	primarily	in	Brazil,	utilities	revenue	for	2010	increased	$433	million,	or	7%,	from 2009	primarily	due	to:

•increased	volume	of	$316	million,	primarily	in	Brazil,	due	to	increased	market	demand;	and

•higher	tariffs	of	$114	million	primarily	related	to	the	July	2009	tariff	reset	in	Brazil	partially	offset	by	the	unfavorable	impact	on	rates	at	Eletropaulo	in Brazil	of	a	cumulative	adjustment	to	regulatory	liabilities	and	higher	energy	prices	across	our	Latin	America	utility	businesses	associated	with	energy purchases	passed	through	to	customers	of	$97	million.

Excluding	the	favorable	impact	of	foreign	currency	translation	of	$107	million,	primarily	in	Brazil,	utilities	gross	margin	for	2010	increased	$47	million,	or	5%, from	2009	primarily	due	to:

•increased	volume	of	$163	million,	primarily	in	Brazil,	due	to	the	increased	market	demand;	and

•lower	contingencies	of	$142	million	in	Eletropaulo	primarily	related	to	labor	contingencies	which	included	a	one-time	reversal,	reflecting	an	agreement with	Fundação	CESP,	the	pension	plan	administrator,	of	$51	million	associated	with	claims	for	past	benefit	obligations	which	will	now	be	accounted	for	as a	component	of	the	pension	plan.

•higher	fixed	costs	of	$238	million	primarily	due	to	the	recovery	in	2009	of	a	municipality	receivable	previously	written	off	in	Brazil	and	higher	salaries	and other	employee	related	costs,	provisions	for	commercial	losses,	regulatory	penalties	and	maintenance	costs;	and

•$28	million	related	to	the	final	settlement	of	the	power	sales	agreement	between	Sul	and	Uruguaiana.

Excluding	the	unfavorable	impact	of	foreign	currency	translation	of	$442	million,	primarily	in	Brazil,	utilities	revenue	for	2009	increased	$627	million,	or	11%, from	2008	primarily	due	to:

•higher	tariffs	of	$560	million	reflecting	the	recovery	of	energy	purchases	of	$453	million	that	were	passed	through	to	customers	at	our	utilities	in	Brazil	and El	Salvador;	and

•higher	volume	in	Brazil	of	$62	million.

Excluding	the	unfavorable	impact	of	foreign	currency	translation	of	$62	million,	primarily	in	Brazil,	utilities	gross	margin	for	2009	increased	$94	million,	or	11%, from	2008	primarily	due	to:

•higher	tariffs	of	$107	million	in	El	Salvador	and	Brazil;

•a	$64	million	recovery	of	a	municipality	receivable	previously	written	off;

# •a	non-recurring	PIS/COFINS	fine	in	2008	of	$33	million;	and

•higher	volume	of	$32	million	across	the	region.

•the	unfavorable	impact	of	higher	fixed	costs	of	$120	million	mainly	related	to	pension	expense,	labor	contingencies	and	maintenance	costs	in	Brazil.

The	following	table	summarizes	revenue	and	gross	margin	for	our	Generation	segment	in	North	America	for	the	periods	indicated:

|  | 2010 | 2009 | 2008 | %	Change<br>2010	vs.	2009 | %	Change<br>2009	vs.	2008 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | ($'s\tin\tmillions) |  |  |
| North\tAmerica\tGeneration |  |  |  |  |  |
| Revenue | $1,972 | $1,940 | $2,234 | 2% | -13% |
| Gross\tMargin | $435 | $477 | $660 | -9% | -28% |

Excluding	the	favorable	impact	of	foreign	currency	translation	of	$19	million,	generation	revenue	for	2010	increased	$13	million,	or	1%,	from	2009	primarily	due to:

•increased	rates,	volume	and	an	availability	bonus	at	TEG/TEP	in	Mexico	of	$41	million;

•higher	volume,	primarily	due	to	fewer	outages	and	higher	rates,	of	$22	million	at	Merida	in	Mexico;

•higher	volume	of	$19	million	at	Warrior	Run	in	Maryland	due	to	fewer	outages;	and

•an	increase	of	$13	million	in	New	York	due	to	the	favorable	impact	of	mark-to-market	derivative	adjustments.

•a	net	decrease	of	$50	million	in	New	York	due	to	lower	rates	partially	offset	by	higher	volume	of	electricity	sold	due	to	fewer	outages;

•a	net	decrease	of	$18	million	at	Deepwater	in	Texas	primarily	due	to	lower	volume;	and

•a	net	decrease	of	$14	million	in	Puerto	Rico	primarily	due	to	a	penalty	from	a	forced	outage.

Excluding	the	favorable	impact	of	foreign	currency	translation	of	$3	million,	generation	gross	margin	for	2010	decreased	$45	million,	or	9%,	from	2009	primarily due	to:

•a	net	decrease	of	$94	million	in	New	York	due	to	lower	rates	and	higher	coal	prices	partially	offset	by	higher	volume	of	electricity	sold	due	to	fewer outages;

•a	decrease	of	$16	million	at	Deepwater	due	to	lower	volume	and	rates;

•a	decrease	of	$9	million	in	Hawaii	due	to	an	unfavorable	impact	of	mark-to-market	derivatives;	and

•a	decrease	of	$7	million	in	Puerto	Rico	due	to	higher	fixed	costs.

•an	increase	of	$39	million	in	New	York	primarily	due	to	lower	fixed	costs	as	a	result	of	lower	contract	and	maintenance	costs,	and	other	employee	related costs;

•a	net	increase	of	$26	million	at	TEG/TEP	due	to	a	current	year	availability	bonus	and	fewer	outages	partially	offset	by	higher	fuel	prices;

•higher	volume	of	$14	million	at	Warrior	Run	due	to	fewer	outages;	and

For	the	year	ended	December	31,	2010,	revenue	increased	by	2%	while	gross	margin	decreased	9%,	primarily	due	to	the	change	in	rates	in	New	York	having	a greater	impact	on	gross	margin	than	revenue.

Excluding	the	unfavorable	impact	of	foreign	currency	translation	of	$44	million,	primarily	in	Mexico,	generation	revenue	for	2009	decreased	$250	million,	or 11%,	from	2008	primarily	due	to:

•a	net	decrease	of	$107	million	in	New	York	due	to	a	reduction	in	the	volume	of	electricity	sold	in	the	spot	market	as	a	result	of	lower	spot	rates,	partially offset	by	a	rate	increase	on	electricity	sold	under	favorable	contracts;

•a	decrease	of	$80	million	due	to	a	reduction	in	natural	gas	prices	at	Merida;

•increased	outages	of	$22	million,	$21	million	and	$17	million	at	Warrior	Run,	TEG/TEP	and	New	York,	respectively;

•lower	rates	of	$20	million	at	Deepwater;

•the	unfavorable	impact	of	commodity	derivatives	in	New	York	of	$11	million;	and

•the	unfavorable	impact	in	2009	of	derivative	amortization	at	Warrior	Run	of	$9	million.

•a	$15	million	revenue	adjustment	at	Merida	in	2008.

Excluding	the	unfavorable	impact	of	foreign	currency	translation	of	$9	million,	generation	gross	margin	for	2009	decreased	$174	million,	or	26%,	from	2008 primarily	due	to:

•a	net	decrease	of	$72	million	in	New	York	driven	by	a	reduction	in	the	volume	of	electricity	sold	in	the	spot	market	as	a	result	of	lower	spot	rates,	partially offset	by	a	rate	increase	on	electricity	sold	under	favorable	contracts;

•a	$29	million	unfavorable	impact	of	mark-to-market	derivative	adjustments	on	coal	supply	contracts	in	Hawaii	as	a	result	of	a	gain	of	$22	million	in	2008 compared	to	a	loss	of	$7	million	in	2009;

•an	increase	in	outages	of	$22	million	and	$6	million	at	Warrior	Run	and	in	New	York,	respectively;

•the	unfavorable	impact	of	commodity	derivatives	of	$11	million	and	higher	emission	allowance	purchases	of	$13	million	in	New	York;	and

•the	unfavorable	impact	of	$9	million	in	2009	of	derivative	amortization	at	Warrior	Run.

For	the	year	ended	December	31,	2009,	revenue	decreased	by	13%	while	gross	margin	decreased	28%,	primarily	due	to	the	increase	in	coal	prices	in	New	York and	the	unfavorable	impact	of	derivatives	in	2009	in	Hawaii	that	had	no	corresponding	impact	on	revenue.

The	following	table	summarizes	revenue	and	gross	margin	for	our	Utilities	segment	in	North	America	for	the	periods	indicated:

|  |  |  |  | %	Change | %	Change |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2010 | 2009 | 2008 | 2010\tvs.\t2009 | 2009\tvs.\t2008 |
|  |  |  | ($'s\tin\tmillions) |  |  |
| North\tAmerica\tUtilities |  |  |  |  |  |
| Revenue | $1,145 | $1,068 | $1,079 | 7% | -1% |
| Gross\tMargin | $249 | $239 | $261 | 4% | -8% |

Utilities	revenue	for	2010	increased	$77	million,	or	7%,	from	2009	primarily	due	to:

•higher	retail	demand	of	$64	million	as	a	result	of	warmer	weather	and	higher	fuel	adjustment	charges;	and •increased	wholesale	revenue	of	$11	million	primarily	due	to	higher	prices.

Utilities	gross	margin	for	2010	increased	$10	million,	or	4%,	from	2009	primarily	due	to:

•higher	retail	margin	of	$20	million	due	to	increased	demand;

•lower	pension	expense	of	$12	million;	and

•lower	emission	allowance	expense	of	$5	million.

•increased	maintenance	expenses	of	$16	million	due	to	the	timing	of	major	generating	unit	overhauls;	and

•increased	fixed	costs	of	$14	million.

For	the	year	ended	December	31,	2010,	revenue	increased	by	7%	while	gross	margin	increased	4%,	primarily	due	to	increased	fuel	and	maintenance	costs.

Utilities	revenue	for	2009	decreased	$11	million,	or	1%,	from	2008	primarily	due	to:

•lower	retail	volume	of	$31	million	due	primarily	to	milder	weather	and	the	economic	recession;	and

•decreased	wholesale	revenue	of	$7	million	driven	by	lower	market	prices.

•$32	million	of	voluntary	credits	IPL	provided	to	retail	customers	in	2008.	See	Item	1.—Business—Regulatory	Matters—North	America	of	this	Form	10-K for	further	information	regarding	these	credits.

Utilities	gross	margin	for	2009	decreased	$22	million,	or	8%,	from	2008	primarily	due	to:

•decreased	wholesale	margin	of	$16	million	due	to	unfavorable	prices;	and

•increased	pension	expense	of	$25	million	largely	due	to	the	decline	in	market	value	of	IPL's	pension	assets	during	2008.

•increased	retail	margin	of	$15	million,	primarily	due	to	the	$32	million	of	voluntary	customer	credits	IPL	issued	to	its	retail	customers	in	2008,	partially offset	by	lower	retail	sales	volumes	in	2009;	and

•decreased	property	tax	expense	of	$5	million.

For	the	year	ended	December	31,	2009,	revenue	decreased	by	1%	while	gross	margin	decreased	8%,	primarily	due	to	the	$25	million	increase	in	pension	expense and	the	$32	million	of	voluntary	customer	credits	IPL	issued	to	its	retail	customers	in	2008,	both	of	which	had	an	unfavorable	impact	on	gross	margin.

The	following	table	summarizes	revenue	and	gross	margin	for	our	Generation	segment	in	Europe	for	the	periods	indicated:

|  | 2010 | 2009 | 2008 | %	Change<br>2010	vs.	2009 | %	Change<br>2009	vs.	2008 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | ($'s\tin\tmillions) |  |  |
| Europe\tGeneration |  |  |  |  |  |
| Revenue | $1,362 | $820 | $1,143 | 66% | -28% |
| Gross\tMargin | $268 | $212 | $273 | 26% | -22% |

Excluding	the	unfavorable	impact	of	foreign	currency	translation	of	$41	million,	generation	revenue	for	2010	increased	$583	million,	or	71%,	from	2009 primarily	due	to:

•$409	million	from	the	adoption	of	new	accounting	guidance	on	the	consolidation	of	variable	interest	entities	("VIEs")	which	resulted	in	the	consolidation	of Cartagena	in	Spain,	a	generation	business	previously	accounted	for	under	the	equity	method	of	accounting;

•$117	million	from	the	operations	of	Ballylumford	in	the	United	Kingdom,	which	was	acquired	in	August	2010;

•$16	million	from	a	full	year	of	combined	cycle	operations	at	our	Amman	East	plant	in	Jordan,	which	was	single	cycle	until	August	2009;

•higher	tariffs	of	$16	million	at	Altai	in	Kazakhstan;

•higher	volume	of	$15	million	at	Kilroot	in	the	United	Kingdom	largely	driven	by	coal	pass-through	and	increased	demand,	partially	offset	by	lower capacity	revenue	due	to	the	termination	of	the	long	term	PPA	and	related	supplementary	agreements.

•lower	volume	and	sales	of	emissions	allowances	in	Hungary	of	$16	million.

Excluding	the	unfavorable	impact	of	foreign	currency	translation	of	$1	million,	generation	gross	margin	for	2010	increased	$57	million,	or	27%,	from	2009 primarily	due	to:

•$62	million	from	the	consolidation	of	Cartagena	as	discussed	above;

•higher	tariffs	and	lower	fixed	costs	at	Altai	of	$29	million;	and

•$13	million	from	the	operations	of	Ballylumford	since	its	acquisition.

•lower	gross	margin	of	$28	million	primarily	from	the	termination	of	the	long-term	PPA	at	Kilroot;	and

•lower	gross	margin	of	$20	million	in	Hungary	primarily	attributable	to	higher	fuel	costs	that	could	not	be	passed	through	and	lower	sales	of	emission allowances.

For	the	year	ended	December	31,	2010,	revenue	increased	66%	while	gross	margin	increased	26%,	primarily	due	to	the	consolidation	of	Cartagena	and	acquisition of	Ballylumford	that	have	a	larger	positive	impact	on	revenue	than	gross	margin,	and	the	positive	impact	of	higher	energy	revenue	at	Kilroot,	which	as	a	pass-through had	no	corresponding	impact	on	gross	margin.

Excluding	the	unfavorable	impact	of	foreign	currency	translation	of	$146	million,	driven	mainly	by	Kilroot,	Hungary	and	Kazakhstan,	generation	revenue	for 2009	decreased	$177	million,	or	15%,	from	2008	primarily	due	to:

•lower	revenue	of	$101	million	as	a	result	of	the	sale	of	Ekibastuz	and	Maikuben	in	May	2008;

•lower	volume	of	$81	million	in	Hungary	due	to	the	combined	impact	of	the	cancellation	of	one	of	our	PPAs	and	reduced	demand;	and

•lower	volume	of	$67	million	at	Kilroot,	a	coal-fired	plant,	mainly	driven	by	lower	dispatch	due	to	favorable	gas	prices	compared	to	coal.

•the	benefit	of	new	business	of	$50	million	at	Amman	East,	which	commenced	single	cycle	operations	in	July	2008;	and

•higher	rates	of	$15	million	in	Kazakhstan.

Excluding	the	unfavorable	impact	of	foreign	currency	translation	of	$35	million,	driven	mainly	by	Kilroot	and	Kazakhstan,	generation	gross	margin	for	2009 decreased	$26	million,	or	10%,	from	2008	primarily	due	to:

•lower	gross	margin	of	$41	million	as	a	result	of	the	sale	of	Ekibastuz	and	Maikuben	in	May	2008;

•lower	demand	of	$12	million	in	Hungary;	and

•an	overall	increase	of	$22	million	in	fixed	costs	across	the	region.

•higher	capacity	revenue	at	Kilroot;

•higher	energy	prices	in	Kazakhstan;	and

•the	benefit	of	new	business	at	Amman	East.

The	following	table	summarizes	revenue	and	gross	margin	for	our	Generation	segment	in	Asia	for	the	periods	indicated:

|  | 2010 | 2009 | 2008 | %	Change<br>2010	vs.	2009 | %	Change<br>2009	vs.	2008 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | ($'s\tin\tmillions) |  |  |
| Asia\tGeneration |  |  |  |  |  |
| Revenue | $618 | $375 | $345 | 65% | 9% |
| Gross\tMargin | $240 | $93 | $ (10) | 158% | 1030% |

Excluding	the	favorable	impact	of	foreign	currency	translation	of	$28	million,	generation	revenue	for	2010	increased	$215	million,	or	57%,	from	2009	primarily

# due	to:

•favorable	generation	rates	and	volume	of	$210	million	at	Masinloc	in	the	Philippines	as	a	result	of	increased	market	demand	and	improved	plant availability	subsequent	to	the	completion	of	its	overhaul	at	the	beginning	of	2010;	and

•higher	demand	from	both	new	and	existing	contract	and	spot	customers	as	a	result	of	lower	supply	shortages	in	the	Philippines	power	market	due	to	a strong	energy	growth	rate.

Excluding	the	favorable	impact	of	foreign	currency	translation	of	$13	million,	generation	gross	margin	for	2010	increased	$134	million,	or	144%,	from	2009 primarily	due	to	a	combination	of	higher	availability	attributable	to	improved	plant	operations,	higher	market	demand	and	favorable	spot	prices	at	Masinloc.

For	the	year	ended	December	31,	2010,	revenue	increased	65%	while	gross	margin	increased	158%,	primarily	due	to	the	positive	influence	on	gross	margin	due	to favorable	spot	rates	and	operational	efficiencies	resulting	from	the	Masinloc	plant	overhauls	in	late	2009	and	early	2010,	which	led	to	higher	availability	and	allowed	for more	efficient	operations	that	have	materially	improved	the	operating	results	for	2010	as	compared	to	2009.

Excluding	the	unfavorable	impact	of	foreign	currency	translation	of	$23	million,	primarily	in	the	Philippines	and	Sri	Lanka,	generation	revenue	for	2009	increased $53	million,	or	15%,	from	2008	primarily	due	to:

•the	benefit	of	$46	million	of	our	new	business	Masinloc,	which	was	acquired	in	April	2008;

•increased	revenue	of	$70	million	in	2009	at	Masinloc	due	to	improved	rates	and	volume	as	a	result	of	improved	availability	and	new	customer	contracts; and

•$18	million	from	a	one-time	favorable	energy	sales	settlement	at	Masinloc.

•the	decrease	in	revenue	of	$71	million	at	Kelanitissa	in	Sri	Lanka	primarily	due	to	a	decline	in	fuel	costs	which	are	largely	passed	through	to	the	customer and	higher	outages	in	2009	as	compared	to	2008	partially	offset	by	higher	capacity	revenue.

Excluding	the	unfavorable	impact	of	foreign	currency	translation	of	$6	million,	primarily	in	the	Philippines,	generation	gross	margin	for	2009	increased $109	million,	or	1,090%,	from	2008	primarily	due	to:

•the	impact	of	our	new	business	at	Masinloc	of	$23	million;

•a	$91	million	increase	at	Masinloc	due	to	higher	contract	sales,	where	margins	are	more	favorable	than	spot	sales,	lower	fuel	prices,	improved	availability and	the	favorable	energy	sales	settlement	described	above;	and

•higher	capacity	revenue	at	Kelanitissa	of	$10	million.

•higher	fixed	costs	of	$20	million	at	Masinloc.

For	the	year	ended	December	31,	2009,	revenue	increased	9%	while	gross	margin	increased	1,030%,	primarily	due	to	higher	contract	margins	at	Masinloc	as	a result	of	improved	operations,	availability	and	lower	fuel	prices,	as	well	as	the	larger	relative	impact	on	gross	margin	from	the	one-time	favorable	energy	sales settlement	described	above.

Corporate	and	other	includes	the	net	operating	results	from	our	generation	and	utilities	businesses	in	Africa,	utilities	businesses	in	Europe,	AES	Wind	Generation and	renewables	projects	which	are	immaterial	for	the	purposes	of	separate	segment	disclosure.	The	following	table	excludes	inter-segment	activity	and	summarizes revenue	and	gross	margin	for	Corporate	and	Other	entities	for	the	periods	indicated:

|  | 2010 | 2009 | 2008 | %	Change<br>2010	vs.	2009 | %	Change<br>2009	vs.	2008 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | ($'s\tin\tmillions) |  |  |
| Revenue |  |  |  |  |  |
| Europe\tUtilities | $356 | $286 | $403 | 24% | -29% |
| Africa\tUtilities | 422 | \t 370 | 379 | 14% | -2% |
| Africa\tGeneration | 61 | 65 | 65 | -6% | 0% |
| Wind\tGeneration | 202 | \t 133 | 128 | 52% | 4% |
| Corp/Other | 25 | 16 | 37 | 56% | -57% |
| Total\tCorporate\tand\tOther | $1,066 | $870 | $1,012 | 23% | -14% |
| Gross\tMargin |  |  |  |  |  |
| Europe\tUtilities | $21 | $16 | $34 | 31% | -53% |
| Africa\tUtilities | 65 | 71 | 30 | -8% | 137% |
| Africa\tGeneration | 54 | 41 | 28 | 32% | 46% |
| Wind\tGeneration | 44 | 11 | 19 | 300% | -42% |
| Corp/Other | 2 | (22) | (49) | -109% | -55% |
| Total\tCorporate\tand\tOther | $186 | $117 | $62 | 59% | 89% |

Excluding	the	unfavorable	impact	of	foreign	currency	translation	of	$30	million,	primarily	in	Cameroon,	Corporate	and	Other	revenue	increased	$226	million	for 2010,	or	26%	from	2009.	The	increase	was	primarily	due	to:

•higher	volume	at	our	utility	businesses	in	Ukraine	driven	by	an	overall	increase	in	market	demand;

•higher	volume	and	utility	tariffs	at	Sonel	in	Cameroon	driven	by	an	increase	in	market	demand;	and

•incremental	revenue	from	new	wind	generation	projects	that	commenced	operations	during	the	year	and	an	overall	volume	increase	across	our	wind businesses.

Excluding	the	unfavorable	impact	of	foreign	currency	translation	of	$8	million,	primarily	in	Cameroon,	Corporate	and	Other	gross	margin	increased	$77	million for	2010,	or	66%	from	2009.	The	increase	was	primarily	due	to:

•an	increase	in	gross	margin	from	our	new	wind	generation	projects	and	higher	volume,	as	discussed	above;	and

•an	increase	in	volume	at	Dibamba,	our	generation	business,	in	Cameroon.

•an	increase	in	fixed	costs	at	Sonel.

Excluding	the	unfavorable	impact	of	foreign	currency	translation	of	$162	million,	primarily	in	Ukraine,	Corporate	and	Other	revenue	increased	$20	million	for 2009,	or	2%,	from	2008.	The	increase	was	primarily	due	to:

•higher	tariffs	in	Ukraine	of	$27	million.

Excluding	the	unfavorable	impact	of	foreign	currency	translation	of	$12	million,	primarily	in	Ukraine,	Corporate	and	Other	gross	margin	increased	$67	million for	2009,	or	108%,	from	2008.	The	increase	was	primarily	due	to:

•a	decrease	in	fixed	costs	across	the	Africa	region.

The	increase	was	partially	offset	by:

•higher	fuel	consumption	attributable	to	lower	hydrology	at	Sonel.

# General	and	Administrative	Expense

General	and	administrative	expense	includes	those	expenses	related	to	corporate	and	region	staff	functions	and/or	initiatives,	executive	management,	finance, legal,	human	resources,	information	systems,	and	development	costs.

General	and	administrative	expenses	increased	$53	million,	or	16%,	to	$392	million	in	2010	from	2009.	The	increase	is	primarily	related	to	business	development costs	associated	with	increased	development	efforts,	primarily	in	Europe,	Turkey	and	India.

General	and	administrative	expenses	decreased	$29	million,	or	8%,	to	$339	million	in	2009	from	2008.	The	decrease	is	primarily	related	to	2008	professional	fees associated	with	remediation	efforts	and	a	reduction	in	business	development	costs.	The	favorable	variance	is	partially	offset	by	an	increase	in	costs	associated	with	the worldwide	implementation	of	SAP.

# Interest	expense

Interest	expense	increased	$41	million,	or	3%,	to	$1.5	billion	in	2010	from	2009.	This	increase	was	primarily	due	to	interest	expense	at	Cartagena	which	is	now	a consolidated	entity,	higher	interest	rates	at	Tietê,	increased	debt	principal	at	Eletropaulo	and	interest	being	expensed	related	to	St.	Nikola,	our	wind	project	in	Bulgaria, due	to	commencement	of	operations	in	2010.	These	increases	were	partially	offset	by	reduced	debt	principal	at	the	Parent	Company.

Interest	expense	decreased	$285	million,	or	16%,	to	$1.5	billion	in	2009	from	2008.	This	decrease	was	primarily	due	to	lower	interest	rates	globally	due	to economic	conditions	and	inflationary	adjustments	to	the	market	price	index	in	Brazil.	In	addition,	interest	expense	decreased	as	a	result	of	favorable	foreign	currency translation,	mainly	in	Brazil	and	lower	interest	expenses	associated	with	decreased	debt	balances	at	Eletropaulo.	These	decreases	were	partially	offset	by	higher	interest expense	at	Masinloc	in	the	Philippines	which	was	acquired	in	April	2008,	and	interest	expense	at	Infovias	in	Brazil	where	a	fee	on	a	non-exercised	credit	line	was written	off.

# Interest	income

Interest	income	increased	$63	million,	or	18%,	to	$411	million	in	2010	from	2009.	This	increase	was	primarily	due	to	a	higher	average	balance	in	short	term investments	at	Eletropaulo	and	the	favorable	impact	of

foreign	currency	translation	in	Brazil	as	well	as	the	settlement	of	a	dispute	related	to	inflation	adjustments	for	energy	sales	at	Tietê.	These	increases	were	partially	offset by	reduced	interest	income	from	a	loan	to	a	wind	development	project	in	Brazil	which	was	repaid	in	June	2010.

Interest	income	decreased	$171	million,	or	33%,	to	$348	million	in	2009	from	2008.	This	decrease	was	primarily	due	to	lower	interest	rates	and	lower	investment balances	in	Brazil,	unfavorable	foreign	currency	translation	in	Brazil,	the	impact	of	decreased	interest	rates	and	inflationary	adjustments	on	accounts	receivable	in	2008 at	Gener	in	Chile	and	a	decreased	cash	balance	at	the	Parent	Company.

# Other	income

|  | 2010 | 2009 | 2008 |
| :--- | :--- | :--- | :--- |
|  |  | (in\tmillions) |  |
| Gain\ton\textinguishment\tof\ttax\tand\tother\tliabilities | $65 | $168 | $199 |
| Tax\tcredit\tsettlement | — | 129 | — |
| Performance\tincentive\tfee | — | 80 | — |
| Insurance\tproceeds | — | — | 40 |
| Gain\ton\tsale\tof\tassets | 12 | 14 | 34 |
| Other | 31 | 74 | 102 |
| Total\tother\tincome | $108 | $465 | $375 |

Other	income	of	$108	million	for	the	year	ended	December	31,	2010	was	primarily	related	to	the	extinguishment	of	a	swap	liability	owed	by	two	of	our	Brazilian subsidiaries,	resulting	in	the	recognition	of	a	$62	million	gain.	The	net	impact	to	the	Company	after	taxes	and	noncontrolling	interest	was	$9	million.	Other	income	also included	a	gain	on	sale	of	assets	at	Eletropaulo.

Other	income	of	$465	million	for	the	year	ended	December	31,	2009	included	$165	million	from	the	reduction	in	interest	and	penalties	associated	with	federal	tax debts	at	Eletropaulo	and	Sul	as	a	result	of	the	REFIS	program	and	a	$129	million	gain	related	to	a	favorable	court	decision	enabling	Eletropaulo	to	receive reimbursement	of	excess	non-income	taxes	paid	from	1989	to	1992	in	the	form	of	tax	credits	to	be	applied	against	future	tax	liabilities.	The	net	impact	to	the	Company after	income	taxes	and	noncontrolling	interests	for	these	items	was	$44	million.	In	addition,	the	Company	recognized	income	in	2009	of	$80	million	from	a	performance incentive	bonus	for	management	services	provided	to	Ekibastuz	and	Maikuben	in	2008.	The	management	agreement	was	related	to	the	sale	of	these	businesses	in Kazakhstan	in	May	2008;	see	further	discussion	of	this	transaction	in	Note	22—Acquisitions	and	Dispositions,	to	the	Consolidated	Financial	Statements	included	in Item	8	of	this	Form	10-K.

Other	income	of	$375	million	for	the	year	ended	December	31,	2008	included	gains	on	the	extinguishment	of	a	gross	receipts	tax	liability	and	a	legal	contingency at	Eletropaulo	of	$117	million	and	$75	million,	respectively,	$32	million	of	cash	proceeds	related	to	a	favorable	legal	settlement	at	Southland	in	California,	$29	million of	insurance	recoveries	for	damaged	turbines	at	Uruguaiana,	$23	million	of	gains	associated	with	a	sale	of	land	at	Eletropaulo	and	sales	of	turbines	at	Itabo,	and compensation	of	$18	million	for	the	impairment	associated	with	the	settlement	agreement	to	shut	down	Hefei.

# Other	expense

|  | 2010 | 2009 | 2008 |
| :--- | :--- | :--- | :--- |
|  |  | (in\tmillions) |  |
| Loss\ton\tsale\tand\tdisposal\tof\tassets | $84 | $42 | $34 |
| Gener\tgas\tsettlement | 72 | \t — | — |
| Loss\ton\textinguishment\tof\tdebt | 37 | \t — | 70 |
| AES\tWind\ttransaction\tcosts | 22 | \t — | — |
| Other | 24 | 69 | 57 |
| Total\tother\texpense | $ 239 | $111 | $161 |

Other	expense	of	$239	million	for	the	year	ended	December	31,	2010	included	$72	million	for	a	settlement	agreement	of	gas	transportation	contracts	at	Gener. There	were	also	previously	capitalized	transaction	costs	of	$22	million	that	were	incurred	in	connection	with	the	preparation	for	the	sale	of	a	noncontrolling	interest	in our	Wind	Generation	business	which	were	written	off	upon	the	expiration	of	the	letter	of	intent	in	June	2010.	In	addition,	there	were	losses	on	the	disposal	of	assets	at Eletropaulo,	Panama,	and	Gener,	an	$18	million	loss	on	debt	extinguishment	at	Andres	and	Itabo	and	a	$15	million	loss	at	the	Parent	Company	from	the	retirement	of senior	notes.

Other	expense	of	$111	million	for	the	year	ended	December	31,	2009	included	a	$13	million	loss	recognized	when	three	of	our	businesses	in	the	Dominican Republic	received	$110	million	par	value	bonds	issued	by	the	Dominican	Republic	government	to	settle	existing	accounts	receivable	for	the	same	amount	from	the government-owned	distribution	companies.	The	loss	represented	an	adjustment	to	reflect	the	fair	value	of	the	bonds	on	the	date	received.	Other	expense	also	included losses	on	the	disposal	of	assets	at	Eletropaulo	and	Andres	and	contingencies	at	our	businesses	in	Kazakhstan	and	Alicura	in	Argentina.

Other	expense	of	$161	million	for	the	year	ended	December	31,	2008	included	$69	million	of	losses	on	the	retirement	of	debt	at	the	Parent	Company	in connection	with	the	refinancing	in	June	2008	and	IPALCO	associated	with	a	$375	million	refinancing	in	April	2008	and	losses	on	disposal	of	assets	primarily	at Eletropaulo.

# Goodwill	Impairment

In	2010,	the	Company	recognized	goodwill	impairment	expense	of	$21	million.	During	the	third	quarter	of	2010,	Deepwater,	our	pet	coke-fired	merchant generation	facility	in	Texas,	determined	that	there	was	an	interim	impairment	indicator	for	its	goodwill.	This	determination	was	primarily	based	on	management's decision	not	to	operate	the	plant	for	more	than	30	days	in	the	third	quarter	of	2010,	current	operating	and	cash	flow	losses,	and	forecasted	operating	and	cash	flow	losses for	the	remainder	of	2010	through	2014	as	a	result	of	declining	trends	in	energy	pricing	curves	and	increasing	pet	coke	prices.	As	a	result,	Deepwater	recognized	a goodwill	impairment	of	$18	million.	Deepwater	is	reported	in	the	North	America	Generation	segment.

In	2009,	the	Company	recognized	goodwill	impairment	expense	of	$122	million.	This	was	a	result	of	impairment	at	certain	of	our	businesses	in	the	United Kingdom	and	Ukraine	as	a	result	of	the	Company's	annual	goodwill	impairment	evaluation	as	of	October	1.	The	most	significant	goodwill	impairment	was	at	Kilroot, our	generation	business	in	the	United	Kingdom.	Factors	contributing	to	the	recognition	of	impairment	included:	reduced	profit	expectations	based	on	latest	estimates	of future	commodity	prices	and	reduced	expectations	on	the	recovery	of	cash	flows	on	the	existing	plant	following	the	Company's	decision	to	forgo	capital	expenditures	to meet	emission	allowance	requirements	taking	effect	in	2024.	The	fair	value	of	the	Company's	reporting	units	are	inherently	sensitive	to	the	assumptions	underlying	the estimates	of	fair	value.	Note	1—General	and	Summary	of	Significant	Accounting	Policies,	Fair	Value,	Goodwill	and	Intangibles	in	Item	8	of	this	Form	10-K	provides	a

more	detailed	discussion	of	those	assumptions.	As	discussed	in	Key	Trends	and	Uncertainties,	in	the	future,	the	fair	values	of	the	Company's	reporting	units	might decline	as	a	result	of	adverse	changes	in	their	operating	environments	or	the	businesses	reaching	the	end	of	their	finite	lives,	which	could	require	the	Company	to	record additional	goodwill	impairment	charges.

The	Company	did	not	incur	any	goodwill	impairment	charges	in	2008.

# Asset	Impairment	Expense

As	discussed	in	Note	19—Impairment	Expense	to	the	Consolidated	Financial	Statements	included	in	Item	8	of	this	Form	10-K,	asset	impairment	expense	for	the year	2010	was	$1,221	million	and	consisted	primarily	of	the	following:

Eastern	Energy—AEE	operates	four	coal-fired	power	plants:	Cayuga,	Greenidge,	Somerset	and	Westover,	representing	generation	capacity	of	1,169	MW	in	the western	New	York	power	market.	During	2010,	the	power	prices	in	the	New	York	power	market	trended	downward,	similar	to	North	America	natural	gas	prices.	The New	York	Independent	System	Operator	("NYISO")	continues	to	move	forward	with	the	potential	addition	of	a	new	capacity	zone,	which	is	expected	to	put	further downward	pressure	on	the	capacity	prices	paid	to	the	AEE	facilities.	In	November	2010,	legislation	was	proposed	in	the	state	of	New	Jersey	for	the	addition	of	state subsidized	capacity	additions	serving	to	lower	PJM	capacity	price	expectations.	Similar	changes	to	capacity	pricing	may	be	made	in	the	future	in	New	York.	Continued pressure	on	energy	prices,	driven	by	falling	natural	gas	prices	and	state	actions,	indicate	that	capacity	prices	are	unlikely	to	reach	levels	significantly	in	excess	of	those achieved	historically.	Accordingly,	management's	view	of	long-term	capacity	markets	in	western	New	York	was	revised	downward.	In	December	2010,	management revised	its	cash	flow	forecasts	based	on	these	developments	and	forecasted	continuing	negative	operating	cash	flow	and	losses	through	2034.	The	forecasted	energy prices	are	such	that	a	hedge	strategy	significantly	beyond	those	in	place	at	December	31,	2010	would	not	be	economical.	Additionally,	on	November	15,	2010, Standard	&	Poor's	downgraded	the	bond	rating	of	AEE	from	BB	to	B+.	Collectively,	in	the	fourth	quarter	of	2010,	these	events	were	considered	an	impairment	indicator for	the	AES	New	York	asset	group,	of	which	AEE	is	the	most	significant	component	and	necessitated	a	recoverability	test	of	the	asset	group.

Southland—In	May	2010,	the	California	State	Water	Board	approved	a	policy	to	reduce	the	number	of	marine	animals	killed	by	seawater	cooling	systems	in coastal	power	plants	in	California.	At	that	time	since	the	policy	required	the	approval	of	California's	Office	of	Administrative	Law,	it	was	unclear	whether	the	policy would	be	approved	and	the	exact	form	the	regulations	would	take.	In	September	2010,	the	Office	of	Administrative	Law	in	California	approved	the	policy	that	will require	the	Company	to	change	the	process

through	which	it	uses	ocean	water	to	cool	the	generation	turbines	at	its	Alamitos,	Huntington	Beach	and	Redondo	Beach	(collectively	"Southland")	gas-fired	generation facilities	in	California.	The	policy	requires	compliance	with	the	new	regulations	by	December	31,	2020.	The	change	in	the	water	cooling	process	will	result	in	significant future	capital	expenditures	to	ensure	compliance	with	the	new	regulations	and	the	Company	determined	that	an	indicator	of	impairment	existed	at	September	30,	2010. The	Company	performed	an	asset	impairment	test	in	accordance	with	the	accounting	guidance	on	property,	plant	and	equipment.	The	asset	group	was	determined	to	be	at the	individual	plant	level	and	based	on	the	undiscounted	cash	flow	analysis,	the	Company	determined	that	the	Huntington	Beach	asset	group	was	not	recoverable.	The fair	value	of	the	Huntington	Beach	asset	group	was	then	determined	using	a	discounted	cash	flow	analysis.	To	assist	management	in	determining	the	fair	value	of	the asset	group,	an	independent	valuation	firm	was	engaged.	Cash	flow	forecasts	and	the	underlying	assumptions	for	the	valuation	were	developed	by	management.	The carrying	value	of	the	Huntington	Beach	plant	of	$288	million	exceeded	the	fair	value	of	$88	million	resulting	in	the	recognition	of	asset	impairment	expense	of	$200 million.	The	undiscounted	cash	flows	of	the	Alamitos	and	Redondo	Beach	generation	facilities	exceeded	their	respective	carrying	values	and	resulted	in	no	impairment. Huntington	Beach	is	reported	in	the	North	America	Generation	reportable	segment.

Tisza	II—During	the	third	quarter	of	2010,	the	Company	entered	into	annual	negotiations	with	the	offtaker	of	its	Tisza	II	generation	plant	in	Hungary.	As	a	result of	these	preliminary	negotiations,	as	well	as	the	further	deterioration	of	the	economic	environment	in	Hungary,	the	Company	determined	that	an	indicator	of	impairment existed	at	September	30,	2010.	Thus,	the	Company	performed	an	asset	impairment	test	in	accordance	with	the	accounting	guidance	on	property,	plant	and	equipment	and determined	that	based	on	the	undiscounted	cash	flow	analysis,	the	carrying	amount	of	the	Tisza	II	asset	group	was	not	recoverable.	The	fair	value	of	the	asset	group	was then	determined	using	a	discounted	cash	flow	analysis.	The	carrying	value	of	the	Tisza	II	asset	group	of	$160	million	exceeded	the	fair	value	of	$75	million	resulting	in the	recognition	of	asset	impairment	expense	of	$85	million.	Tisza	II	is	reported	in	the	Europe	Generation	reportable	segment.

Deepwater—In	March	2010,	Deepwater,	our	160	MW	pet	coke-fired	merchant	power	plant	located	in	Texas,	experienced	deteriorating	market	conditions	due	to increasing	pet	coke	prices	and	diminishing	power	prices.	As	a	result,	Deepwater	incurred	an	operating	loss	for	the	period	and	forecasted	short	term	losses.	These conditions	gradually	worsened	in	the	second	quarter	of	2010	and	management	determined	it	could	not	operate	the	plant	at	certain	times	during	the	year	without generating	negative	operating	margin.

As	the	contraction	of	energy	margin	continued	in	the	second	quarter	of	2010,	management	determined	the	collective	events	to	be	an	indicator	of	impairment	and performed	an	impairment	evaluation	of	Deepwater's	goodwill	and	recoverability	test	for	the	long-lived	asset	group.	Based	on	the	results	of	these	tests,	in	the	second quarter	of	2010,	management	concluded	no	impairment	was	necessary.	In	the	third	quarter	of	2010,	these	downward	trends	continued	and	management,	after determining	that	there	was	an	indicator	of	impairment,	performed	another	impairment	evaluation	of	Deepwater's	goodwill	and	recoverability	test	of	the	long-lived	asset group.	The	results	in	the	third	quarter	indicated	no	impairment	was	necessary	for	the	asset	group,	but	the	goodwill	associated	with	the	reporting	unit	was	deemed	to	be impaired	and	the	$18	million	goodwill	balance	was	written	off	during	the	quarter	ended	September	30,	2010.

In	the	fourth	quarter	of	2010,	further	adverse	trends	in	energy	and	pet	coke	pricing	curves	were	observed	in	management's	review	of	external	market	analyses. The	most	significant	impact	on	the	forecasted	energy	prices	reviewed	by	management	in	November	2010	related	to	the	general	external	market	consensus	that	Federal CO 	cap	and	trade	legislation	was	less	likely,	resulting	in	a	drop	in	long-term	energy	price	projections.	At	that	time,	Deepwater's	revised	forecasts	indicated	that Deepwater	would	have	operating	losses	which	would	extend	beyond	2020	and	negative	cash	flows	through	2019.	Management	concluded	that,	on	an	undiscounted	cash flow	basis,	the	carrying	amount	of	the	asset	group	was	no	longer	recoverable.	To	measure	the	amount	of	impairment	loss,	management	was	required	to	determine	the	fair value	of	the	asset	group.	To	this	end,	an	independent	valuation	firm	was	engaged	to	assist	management	in	its	estimation	of	fair	value.	Cash	flow	forecasts	and	the underlying	assumptions	for	the	valuation	were	developed	by	management.	In	determining	the	fair	value	of	the	asset	group,

all	three	valuation	approaches	described	by	the	fair	value	measurement	accounting	guidance	were	considered.	The	fair	value	under	the	income	approach	was	considered most	appropriate.	On	that	basis,	the	carrying	value	of	the	asset	group	was	determined	to	be	impaired	and	$79	million	of	impairment	expense	was	recognized	in	the	fourth quarter	of	2010.

Asset	impairment	expense	for	the	year	2009	was	$25	million.	In	2009,	the	Company	recognized	a	pre-tax	long-lived	asset	impairment	charge	of	$11	million related	to	the	Company's	Piabanha	hydro	project	in	Brazil.	The	Company	determined	that	the	carrying	value	exceeded	the	future	discounted	cash	flows	and	abandoned the	project.

Asset	impairment	expense	for	the	year	2008	was	$175	million.	In	the	fourth	quarter	of	2008,	and	in	response	to	the	financial	market	crisis,	the	Company	reviewed and	prioritized	projects	in	the	development	pipeline.	From	this	review,	the	Company	determined	that	the	carrying	value	exceeded	the	future	discounted	cash	flows	for certain	projects.	As	a	result,	the	Company	recorded	an	impairment	charge	of	$75	million	($34	million,	net	of	noncontrolling	interests	and	income	taxes)	related	to	two liquefied	natural	gas	projects	in	North	America	and	a	non-power	development	project	at	one	of	our	facilities	in	North	America.	During	2008,	the	Company	recognized additional	impairment	charges	of	$36	million	related	to	long-lived	assets	at	Uruguaiana.	The	impairment	was	triggered	by	a	combination	of	gas	curtailments	and increases	in	the	spot	market	price	of	energy	in	2007	that	continued	in	2008.	Following	an	initial	impairment	charge	in	the	fourth	quarter	of	2007,	further	charges	were incurred	in	2008	due	to	fixed	asset	purchase	agreements	in	place.	During	the	first	half	of	2008,	the	Company	withdrew	from	projects	in	South	Africa	and	Israel	which resulted	in	impairment	charges	of	$36	million.	The	Company	also	recognized	an	impairment	of	$18	million	related	to	the	shutdown	of	the	Hefei	plant	in	China.

# Gain	on	sale	of	investments

There	was	no	gain	on	sale	of	investments	in	2010.

Gain	on	sale	of	investments	of	$131	million	in	2009	consisted	primarily	of	$98	million	recognized	in	May	2009	related	to	the	termination	of	the	management agreement	between	the	Company	and	Kazakhmys	PLC	for	Ekibastuz	and	Maikuben,	a	gain	of	$14	million	from	the	sale	of	the	remaining	assets	associated	with	the shutdown	of	the	Hefei	plant	in	China	and	$13	million	from	the	reversal	of	a	contingent	liability	related	to	the	Kazakhstan	sale	in	2008.

Gain	on	sale	of	investments	of	$909	million	in	2008	consisted	primarily	of	the	sale	in	May	2008	of	two	wholly	owned	subsidiaries	in	Kazakhstan,	Ekibastuz	and Maikuben	for	a	net	gain	of	$905	million.

# Loss	on	sale	of	subsidiary	stock

There	was	no	loss	on	sale	of	subsidiary	stock	in	2010	or	2009.

Loss	on	sale	of	subsidiary	stock	of	$31	million	in	2008	was	the	result	of	sales	of	AES	Gener	shares	made	by	our	wholly	owned	subsidiary	Cachagua.	In November	2008,	Cachagua	sold	9.6%	of	its	ownership	in	Gener	to	a	third	party	reducing	its	ownership	in	Gener	to	70.6%.

# Foreign	currency	transaction	gains	(losses)	on	net	monetary	position

The	following	table	summarizes	the	gains	(losses)	on	the	Company's	net	monetary	position	from	foreign	currency	transaction	activities:

|  |  | Years	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
|  | \t\t\t\t2010 | \t\t\t\t2009 | \t\t\t\t2008 |
|  |  | (in\tmillions) |  |
| AES\tCorporation | $(50) | $13 | $38 |
| Chile | 8 | 65 | (96) |
| Philippines | 8 | 15 | (57) |
| Brazil | (6) | (9) | (44) |
| Argentina | 12 | (10) | (28) |
| Kazakhstan | 1 | (24) | 14 |
| Colombia | (4) | (11) | 5 |
| Other | (2) | (6) | (16) |
| Total^(1) | $(33) | $33 | $(184) |

Includes	(losses)	gains	of	$(10)	million,	$(39)	million	and	$10	million	on	foreign	currency	derivative	contracts	for	the	years	ended	December	31,	2010,	2009	and 2008,	respectively.

The	Company	recognized	foreign	currency	transaction	losses	of	$33	million	for	the	year	ended	December	31,	2010.	These	losses	consisted	primarily	of	losses	at The	AES	Corporation	partially	offset	by	gains	in	Argentina.

•Losses	of	$50	million	at	The	AES	Corporation	were	primarily	due	to	the	devaluation	of	notes	receivable	resulting	from	the	weakening	of	the	Euro	and British	Pound,	and	losses	on	foreign	exchange	swaps	and	options,	partially	offset	by	gains	on	cash	balances	and	debt	denominated	in	British	Pounds.

•	 Gains	of	$12	million	in	Argentina	were	primarily	due	to	a	gain	on	a	foreign	currency	embedded	derivative	related	to	government	receivables,	partially offset	by	losses	due	to	the	devaluation	of	the	Argentine	Peso	by	5%,	resulting	in	losses	at	Alicura	(an	Argentine	Peso	functional	currency	subsidiary) associated	with	its	U.S.	Dollar	denominated	debt.

The	Company	recognized	foreign	currency	transaction	gains	of	$33	million	for	the	year	ended	December	31,	2009.	These	gains	consisted	primarily	of	gains	in Chile,	the	Philippines	and	at	The	AES	Corporation	partially	offset	by	losses	in	Kazakhstan,	Colombia,	Argentina	and	Brazil.

•	 Gains	of	$65	million	in	Chile	were	primarily	due	to	the	appreciation	of	the	Chilean	Peso	of	20%	resulting	in	gains	at	Gener	(a	U.S.	Dollar	functional currency	subsidiary)	associated	with	its	net	working	capital	denominated	in	Chilean	Peso,	mainly	cash	and	accounts	receivables.	This	gain	was	partially offset	by	$14	million	in	losses	on	foreign	currency	derivatives.

•	 Gains	of	$15	million	in	the	Philippines	were	primarily	due	to	the	appreciation	of	the	Philippine	Peso	of	3%,	resulting	in	gains	at	Masinloc	(a	Philippine Peso	functional	currency	subsidiary)	on	the	remeasurement	of	U.S.	Dollar	denominated	debt.

•	 Gains	of	$13	million	at	The	AES	Corporation	were	primarily	due	to	the	settlement	of	the	senior	unsecured	credit	facility	and	the	revaluation	of	notes receivable	denominated	in	the	Euro,	partially	offset	by	losses	on	debt	denominated	in	British	Pounds.

•Losses	of	$24	million	in	Kazakhstan	were	primarily	due	to	net	foreign	currency	transaction	losses	of	$12	million	related	to	energy	sales	denominated	and fixed	in	the	U.S.	Dollar	and	$12	million	of	foreign	currency	transaction	losses	on	debt	and	other	liabilities	denominated	in	currencies	other	than	the	Kazakh Tenge.

•Losses	of	$11	million	in	Colombia	were	primarily	due	to	the	appreciation	of	the	Colombian	Peso	of	9%,	resulting	in	losses	at	Chivor	(a	U.S.	Dollar functional	currency	subsidiary)	associated	with	its	Colombian	Peso	denominated	debt	and	losses	on	foreign	currency	derivatives.

•Losses	of	$10	million	in	Argentina	were	primarily	due	to	the	devaluation	of	the	Argentine	Peso	of	10%	in	2009,	resulting	in	losses	at	Alicura	(an	Argentine Peso	functional	currency	subsidiary)	associated	with	its	U.S.	Dollar	denominated	debt,	partially	offset	by	derivative	gains.

•Losses	of	$9	million	in	Brazil	were	primarily	due	to	energy	purchases	made	by	Eletropaulo	denominated	in	U.S.	Dollar,	resulting	in	foreign	currency transaction	losses	of	$18	million,	partially	offset	by	gains	of	$9	million	due	to	the	appreciation	in	2009	of	the	Brazilian	Real	of	25%,	resulting	in	gains	at Sul	and	Uruguaiana	associated	with	U.S.	Dollar	denominated	liabilities.

The	Company	recognized	foreign	currency	transaction	losses	of	$184	million	for	the	year	ended	December	31,	2008.	These	losses	consisted	primarily	of	losses	in Chile,	the	Philippines,	Brazil	and	Argentina	partially	offset	by	gains	at	The	AES	Corporation	and	in	Kazakhstan.

•Losses	of	$96	million	in	Chile	were	primarily	due	to	the	devaluation	of	the	Chilean	Peso	of	28%	in	2008,	resulting	in	losses	at	Gener	(a	U.S.	Dollar functional	currency	subsidiary)	associated	with	its	net	working	capital	denominated	in	Chilean	Pesos,	mainly	cash,	accounts	receivable	and	value	added	tax ("VAT")	receivables.

•Losses	of	$57	million	in	the	Philippines	were	primarily	due	to	remeasurement	losses	at	Masinloc	(a	Philippine	Peso	functional	currency	subsidiary)	on U.S.	Dollar	denominated	debt	resulting	from	depreciation	of	the	Philippine	Peso	of	14%	in	2008.

•Losses	of	$44	million	in	Brazil	were	primarily	due	to	the	realization	of	deferred	exchange	variance	on	past	energy	purchases	made	by	Eletropaulo denominated	in	U.S.	Dollar.

•Losses	of	$28	million	in	Argentina	were	primarily	due	to	the	devaluation	of	the	Argentine	Peso	of	10%	in	2008,	resulting	in	losses	at	Alicura	(an	Argentine Peso	functional	currency	subsidiary)	associated	with	its	U.S.	Dollar	denominated	debt.

•	 Gains	of	$38	million	at	The	AES	Corporation	were	primarily	due	to	debt	denominated	in	British	Pounds	and	gains	on	foreign	exchange	derivatives, partially	offset	by	losses	on	notes	receivable	denominated	in	the	Euro.

•	 Gains	of	$14	million	in	Kazakhstan	were	primarily	due	to	net	foreign	currency	transaction	gains	of	$16	million	related	to	energy	sales	denominated	and fixed	in	the	U.S.	Dollar,	offset	by	$5	million	of	foreign	currency	transaction	losses	on	external	and	intercompany	debt	denominated	in	other	than	the Kazakh	Tenge	functional	currency.

# Income	taxes

The	net	increase	in	the	2010	effective	tax	rate	was	primarily	due	to	tax	expense	recorded	in	the	second	quarter	of	2010	relating	to	the	CEMIG	sale	transaction,	tax benefit	recorded	in	2009	upon	the	release	of	valuation	allowances	at	certain	U.S.	and	Brazilian	subsidiaries,	and	$165	million	of	non-taxable	income	recorded	in	2009	at Brazil	as	a	result	of	the	REFIS	program.	These	items	were	offset	by	income	tax	benefits	related	to	a	reversal	of	withholding	tax	liabilities	at	certain	Chilean	subsidiaries and	2010	asset	impairments	primarily	recorded	at	certain	U.S.	subsidiaries.	Included	in	the	net	tax	expense	related	to	the	CEMIG	sale	transaction	is	tax	expense	on	the equity	earnings	associated	with	the	reversal	of	the	net	long-term	liability	and	tax	benefit	related	to	release	of	a	valuation	allowance	against	certain	deferred	tax	assets.

The	net	decrease	in	the	2009	effective	tax	rate	was	primarily	due	to	tax	benefit	recorded	in	2009	upon	the	release	of	valuation	allowance	at	certain	U.S.	and Brazilian	subsidiaries,	$165	million	of	non-taxable	income	recorded	at	Brazil	as	a	result	of	the	REFIS	program	in	2009	and	an	increase	in	U.S.	taxes	on	distributions from	the	Company's	primary	holding	company	in	the	second	quarter	of	2008.

# Net	equity	in	earnings	of	affiliates

Net	equity	in	earnings	of	affiliates	increased	$91	million,	or	99%,	to	$183	million	in	2010	from	$92	million	in	2009.	This	increase	was	primarily	due	to	a	gain recognized	upon	the	sale	of	our	interest	in	CEMIG	during	the	second	quarter	of	2010,	partially	offset	by	2009	equity	in	earnings	of	Cartagena	which	was	accounted	for as	a	consolidated	entity	in	2010	and	thus	reported	directly	within	revenues	and	expenses.

Net	equity	in	earnings	of	affiliates	increased	$59	million,	or	179%,	to	$92	million	in	2009	from	$33	million	in	2008.	This	increase	was	primarily	due	to	a	cash settlement	received	by	Cartagena,	in	Spain,	in	June	2009	for	liquidated	damages	received	related	to	a	construction	delay	from	December	2005	to	November	2006; increased	earnings	at	Guacolda	in	Chile	mainly	due	to	lower	cost	of	coal;	increased	earnings	of	Chigen	affiliates	from	higher	tariffs	partially	offset	by	lower	volume	and a	valuation	write-off	in	2008	at	an	affiliate	in	Turkey.	These	increases	were	partially	offset	by	decreased	earnings	at	OPGC,	in	India,	mainly	due	to	lower	tariff	and	a dividend	distribution	tax	in	March	2009	and	increased	expenses	for	an	equipment	overhaul	at	Elsta	in	the	Netherlands.

# Income	from	continuing	operations	attributable	to	noncontrolling	interests

Income	from	continuing	operations	attributable	to	noncontrolling	interests	decreased	$93	million,	or	8%,	to	$1.0	billion	in	2010	from	$1.1	billion	in	2009.	This decrease	was	primarily	due	to	decreased	earnings	at	Eletropaulo	as	a	result	of	the	absence	of	legal	settlement	income	present	in	2009,	a	loss	on	legal	settlement	at	Gener and	reduced	revenues	due	to	decreased	coal	prices	along	with	higher	electricity	purchases	at	Itabo.	These	decreases	were	partially	offset	by	the	appreciation	of	the Brazilian	Real.

Income	from	continuing	operations	attributable	to	noncontrolling	interests	increased	$340	million,	or	45%,	to	$1.1	billion	in	2009	from	$0.8	billion	in	2008.	This increase	was	primarily	due	to	increases	in	gross	margin	and	other	income,	lower	interest	expense	and	a	decrease	in	impairments	in	2009	at	our	Brazilian	businesses,	and increases	in	gross	margin	and	foreign	currency	transaction	gains	at	our	businesses	in	Chile.	In	addition,	in	the	fourth	quarter	of	2009,	income	from	continuing	operations attributable	to	noncontrolling	interests	increased	$44	million	at	certain	of	our	wind	generation	businesses	as	a	result	of	a	charge	related	to	the	potential	future	taxes	that could	be	deemed	due	in	the	calculation	of	the	hypothetical	liquidation	value	of	certain	of	our	wind	tax	equity	partnerships.

# Discontinued	operations

As	further	discussed	in	Note	21—Discontinued	Operations	and	Held	for	Sale	Businesses	to	the	Consolidated	Financial	Statements	included	in	Item	8	of	this Form	10-K,	Discontinued	Operations	includes	the	results	of	five	businesses:	Ras	Laffan,	a	generation	business	in	Qatar	(sold	in	October	2010);	Barka,	a	generation business	in	Oman,	(sold	in	August	2010);	Lal	Pir	and	Pak	Gen,	generation	businesses	in	Pakistan,	(sold	in	June	2010);	and	Jiaozuo,	a	generation	business	in	China,	(sold in	December	2008).	Prior	periods	have	been	restated	to	reflect	these	businesses	within	Discontinued	Operations	for	all	periods	presented.

In	2010,	income	from	operations	of	discontinued	businesses,	net	of	tax	and	income	attributable	to	noncontrolling	interests,	was	$39	million	and	reflected	the operations	of	our	55%	stake	in	Ras	Laffan,	a	combined	cycle	gas	facility	and	water	desalination	plant	in	Qatar,	our	35%	stake	in	Barka,	a	combined	cycle	gas

facility	and	water	desalination	plant	in	Oman	and	our	55%	stake	in	Lal	Pir	and	Pak	Gen,	two	oil-fired	facilities	in	Pakistan.	The	sale	of	Lal	Pir	and	Pak	Gen	closed	in June	2010,	resulting	in	additional	impairment	expense	and	a	loss	on	the	sale	in	2010	of	$14	million,	net	of	tax	and	noncontrolling	interests.	The	Barka	plant	was	sold	in August	2010,	resulting	in	a	gain	on	sale	of	$63	million,	net	of	tax	and	noncontrolling	interests.	The	sale	of	Ras	Laffan	closed	in	October	2010,	resulting	in	a	gain	on	sale of	$6	million,	net	of	tax.

In	2009,	income	from	operations	of	discontinued	businesses,	net	of	tax	and	income	attributable	to	noncontrolling	interests,	was	$54	million	and	reflected	the operations	of	Ras	Laffan,	Barka,	Lal	Pir	and	Pak	Gen.	Loss	on	disposal	of	discontinued	businesses,	net	of	tax	and	loss	attributable	to	noncontrolling	interests	was	$105 million	and	represented	the	difference	between	the	net	book	value	of	the	Company's	interests	in	its	Pakistan	businesses	and	their	estimated	fair	value.

In	2008,	income	from	operations	of	discontinued	businesses,	net	of	tax	and	income	attributable	to	noncontrolling	interests,	was	$60	million	and	reflected	the operations	of	Ras	Laffan,	Barka,	Lal	Pir,	Pak	Gen	and	Jiaozuo,	a	coal-fired	generation	facility	in	China	sold	in	December	2008.	The	Company	received	$73	million	for its	70%	interest	in	the	business.	The	net	gain	on	the	disposition	was	$7	million.

# Critical	Accounting	Estimates

The	Consolidated	Financial	Statements	of	AES	are	prepared	in	conformity	with	GAAP,	which	requires	the	use	of	estimates,	judgments	and	assumptions	that affect	the	reported	amounts	of	assets	and	liabilities	at	the	date	of	the	financial	statements	and	the	reported	amounts	of	revenue	and	expenses	during	the	periods presented.	AES'	significant	accounting	policies	are	described	in	Note	1—General	and	Summary	of	Significant	Accounting	Policies	to	the	Consolidated	Financial Statements	included	in	Item	8	of	this	Form	10-K.

# An	accounting	estimate	is	considered	critical	if:

•the	estimate	requires	management	to	make	assumptions	about	matters	that	were	highly	uncertain	at	the	time	the	estimate	was	made;

•different	estimates	reasonably	could	have	been	used;	or

•the	impact	of	the	estimates	and	assumptions	on	financial	condition	or	operating	performance	is	material.

Management	believes	that	the	accounting	estimates	employed	are	appropriate	and	the	resulting	balances	are	reasonable;	however,	actual	results	could	materially differ	from	the	original	estimates,	requiring	adjustments	to	these	balances	in	future	periods.	Management	has	discussed	these	critical	accounting	policies	with	the	Audit Committee,	as	appropriate.	Listed	below	are	the	Company's	most	significant	critical	accounting	estimates	and	assumptions	used	in	the	preparation	of	the	Consolidated Financial	Statements.

# Income	Tax	Reserves

We	are	subject	to	income	taxes	in	both	the	United	States	and	numerous	foreign	jurisdictions.	Our	worldwide	income	tax	provision	requires	significant	judgment and	is	based	on	calculations	and	assumptions	that	are	subject	to	examination	by	the	Internal	Revenue	Service	and	other	taxing	authorities.	The	Company	and	certain	of its	subsidiaries	are	under	examination	by	relevant	taxing	authorities	for	various	tax	years.	The	Company	regularly	assesses	the	potential	outcome	of	these	examinations in	each	of	the	tax	jurisdictions	when	determining	the	adequacy	of	the	provision	for	income	taxes.	Accounting	guidance	for	uncertainty	in	income	taxes	prescribes	a	more- likely-than-not	recognition	threshold.	Tax	reserves	have	been	established,	which	the	Company	believes	to	be	adequate	in	relation	to	the	potential	for	additional assessments.	Once	established,	reserves	are	adjusted	only	when	there	is	more	information	available	or	when	an	event	occurs	necessitating	a	change	to	the	reserves.	While the	Company	believes	that	the	amounts	of	the	tax	estimates	are	reasonable,	it	is	possible	that	the	ultimate	outcome	of	current	or	future	examinations	may	exceed	current reserves	in	amounts	that	could	be	material.

On	December	17,	2010,	President	Obama	signed	into	law	the	Tax	Relief	Unemployment	Insurance	Reauthorization	and	Job	Creation	Act	of	2010	("the	Act").	The Act	includes	several	provisions	which	provide	for	tax	relief	for	businesses	by	extending	certain	tax	benefits	and	credits,	including	the	Subpart	F	exception	for	active financing	income	and	the	Controlled	Foreign	Corporation	look-through	provisions	of	Subpart	F.	This	legislation	resulted	in	a	benefit	for	the	Company's	2010	provision for	income	taxes;	however,	there	can	be	no	assurances	that	the	benefits	of	this	legislation	will	extend	beyond	2011,	when	it	is	currently	scheduled	to	expire.

Our	accounting	policies	on	goodwill	and	long-lived	assets	are	described	in	detail	in	Note	1—General	and	Summary	of	Significant	Accounting	Policies,	Goodwill and	Other	Intangibles	and	Long-lived	Assets,	respectively,	included	in	Item	8	of	this	Form	10-K.	Goodwill	is	tested	annually	for	impairment	at	the	reporting	unit	level on	October	1.	In	addition,	goodwill	is	tested	for	impairment	whenever	events	or	circumstances	indicate	that	it	is	more	likely	than	not	that	the	fair	value	of	a	reporting	unit has	been	reduced	below	its	carrying	amount.	A	long-lived	asset	(asset	group)	will	be	tested	for	recoverability	whenever	events	or	changes	in	circumstances	indicate	that its	carrying	amount	may	not	be	recoverable,	i.e.,	the	future	undiscounted	cash	flows	associated	with	the	asset	are	less	than	its	carrying	amount.	In	the	event	that	the carrying	amount	of	the	long-lived	asset	(asset	group)	is	not	recoverable,	an	impairment	evaluation	is	performed,	in	which	the	fair	value	of	the	asset	is	estimated	and compared	to	the	carrying	amount.	Examples	of	indicators	that	would	result	in	an	impairment	test	for	goodwill	and	a	recoverability	test	for	long-lived	assets	include,	but are	not	limited	to,	a	significant	adverse	change	in	the	business	climate,	legislation	changes	or	a	change	in	the	extent	or	manner	in	which	a	long-lived	asset	is	being	used or	in	its	physical	condition.	Throughout	the	impairment	evaluation	process,	management	makes	considerable	judgments;	however,	the	fair	value	determination	is typically	the	most	judgmental	part	of	an	impairment	evaluation.

The	Company	determines	the	fair	value	of	a	reporting	unit	or	a	long-lived	asset	(asset	group)	by	applying	the	approaches	prescribed	under	the	fair	value measurement	accounting	framework.	Generally,	the	market	approach	and	income	approach	are	most	relevant	in	the	fair	value	measurement	of	our	reporting	units	and long-lived	assets;	however,	due	to	the	lack	of	available	relevant	observable	market	information	in	many	circumstances,	the	Company	often	relies	on	the	income approach.	The	Company	may	engage	an	independent	valuation	firm	to	assist	management	with	the	valuation.	The	decision	to	engage	an	independent	valuation	firm considers	all	relevant	facts	and	circumstances,	including	a	cost/benefit	analysis	and	the	Company's	internal	valuation	knowledge	of	the	long-lived	asset	(asset	group)	or business.	The	Company	develops	the	underlying	assumptions	consistent	with	its	internal	budgets	and	forecasts	for	such	valuations.	Additionally,	the	Company	uses	an internal	discounted	cash	flow	valuation	model	(the	"DCF	model"),	based	on	the	principles	of	present	value	techniques,	to	estimate	the	fair	value	of	its	reporting	units	or long-lived	assets	under	the	income	approach.	The	DCF	model	estimates	fair	value	by	discounting	our	internal	budgets	and	cash	flow	forecasts,	adjusted	to	reflect	market participant	assumptions,	to	the	extent	necessary,	at	an	appropriate	discount	rate.

Management	applies	considerable	judgment	in	selecting	several	input	assumptions	during	the	development	of	our	internal	budgets	and	cash	flow	forecasts. Examples	of	the	input	assumptions	that	our	budgets	and	forecasts	are	sensitive	to	include	macroeconomic	factors	such	as	growth	rates,	industry	demand,	inflation, exchange	rates,	power	prices	and	commodity	prices.	Whenever	appropriate,	management	obtains	these	input	assumptions	from	observable	market	data	sources	and extrapolates	the	market	information	if	an	input	assumption	is	not	observable	for	the	entire	forecast	period.	Many	of	these	input	assumptions	are	dependent	on	other economic	assumptions,	which	are	often	derived	from	statistical	economic	models	with	inherent	limitations	such	as	estimation	differences.	Further,	several	input assumptions	are	based	on	historical	trends	which	often	do	not	recur.	The	input	assumptions	most	significant	to	our	budgets	and	cash	flows	are	based	on	expectations	of macroeconomic	factors	which	have	been	volatile	recently.	It	is	not	uncommon	that	different	market	data	sources	have	different	views	of	the	macroeconomic	factors expectations	and	related	assumptions.	As	a	result,	macroeconomic	factors	and	related	assumptions	are	often	available	in	a	narrow	range;	however,	in	some	situations these	ranges	become	wide	and	the	use	of	a	different	set	of	input	assumptions	could	produce	significantly	different	budgets	and	cash	flow	forecasts.

A	considerable	amount	of	judgment	is	also	applied	in	the	estimation	of	the	discount	rate	used	in	the	DCF	model.	To	the	extent	practical,	inputs	to	the	discount	rate are	obtained	from	market	data	sources	(e.g.,	Bloomberg,	Capital	IQ,	etc.).	The	Company	selects	and	uses	a	set	of	publicly	traded	companies	from	the	relevant	industry to	estimate	the	discount	rate	inputs.	Management	applies	judgment	in	the	selection	of	such	companies	based	on	its	view	of	the	most	likely	market	participants.	It	is reasonably	possible	that	the	selection	of	a	different	set	of	likely	market	participants	could	produce	different	input	assumptions	and	result	in	the	use	of	a	different	discount rate.

Fair	value	of	a	reporting	unit	or	a	long-lived	asset	(asset	group)	is	sensitive	to	both	input	assumptions	to	our	budgets	and	cash	flow	forecasts	and	the	discount	rate. Further,	estimates	of	long-term	growth	and	terminal	value	are	often	critical	to	the	fair	value	determination.	As	part	of	the	impairment	evaluation	process,	management analyzes	the	sensitivity	of	fair	value	to	various	underlying	assumptions.	The	level	of	scrutiny	increases	as	the	gap	between	fair	value	and	carrying	amount	decreases. Changes	in	any	of	these	assumptions	could	result	in	management	reaching	a	different	conclusion	regarding	the	potential	impairment,	which	could	be	material.	Our impairment	evaluations	inherently	involve	uncertainties	from	uncontrollable	events	that	could	positively	or	negatively	impact	the	anticipated	future	economic	and operating	conditions.

Further	discussion	of	the	impairment	charges	recognized	by	the	Company	can	be	found	within	Management's	Discussion	and	Analysis,	Consolidated	Results	of Operations—Goodwill	Impairment	and	Asset	Impairment	Expense	and	Note	19—Impairment	Expense	and	Note	8—Goodwill	and	Other	Intangible	Assets	to	the Consolidated	Financial	Statements	included	in	Item	8	of	this	Form	10-K.

# Fair	Value

# Fair	Value	of	Financial	Instruments

A	significant	number	of	the	Company's	financial	instruments	are	carried	at	fair	value	with	changes	in	fair	value	recognized	in	earnings	or	other	comprehensive income	each	period.	The	Company	makes	estimates	regarding	the	valuation	of	assets	and	liabilities	measured	at	fair	value	in	preparing	the	Consolidated	Financial Statements.	These	assets	and	liabilities	include	short	and	long-term	investments	in	debt	and	equity	securities,	included	in	the	balance	sheet	line	items	"Short-term investments"	and	"Other	assets	(Noncurrent)",	derivative	assets,	included	in	"Other	current	assets"	and	"Other	assets	(Noncurrent)"	and	derivative	liabilities,	included	in "Accrued	and	other	liabilities	(current)"	and	"Other	long-term	liabilities".	The	Company	uses	valuation	techniques	and	methodologies	that	maximize	the	use	of observable	inputs	and	minimize	the	use	of	unobservable	inputs.	Where	available,	fair	value	is	based	on	observable	market	prices	or	parameters	or	derived	from	such prices	or	parameters.	Where	observable	prices	are	not	available,	valuation	models	are	applied	to	estimate	the	fair	value	using	the	available	observable	inputs.	The valuation	techniques	involve	some	level	of	management	estimation	and	judgment,	the	degree	of	which	is	dependent	on	the	price	transparency	for	the	instruments	or market	and	the	instruments'	complexity.	Investments	are	generally	fair	valued	based	on	quoted	market	prices	or	other	observable	market	data	such	as	interest	rate indices.	The	Company's	investments	are	primarily	certificates	of	deposit,	government	debt	securities	and	money	market	funds.	Derivatives	are	valued	using	observable data	as	inputs	into	internal	valuation	models.	The	Company's	derivatives	primarily	consist	of	interest	rate	swaps,	foreign	currency	instruments,	and	commodity	and embedded	derivatives.	Additional	discussion	regarding	the	nature	of	these	financial	instruments	and	valuation	techniques	can	be	found	in	Note	4—Fair	Value	in	Item	8 of	this	Form	10-K.

# Accounting	for	Derivative	Instruments	and	Hedging	Activities

We	enter	into	various	derivative	transactions	in	order	to	hedge	our	exposure	to	certain	market	risks.	We	primarily	use	derivative	instruments	to	manage	our interest	rate,	commodity	and	foreign	currency	exposures.	We	do	not	enter	into	derivative	transactions	for	trading	purposes.

In	accordance	with	the	accounting	standards	for	derivatives	and	hedging,	we	recognize	all	derivatives	as	either	assets	or	liabilities	in	the	balance	sheet	and measure	those	instruments	at	fair	value	except	where

derivatives	qualify	and	are	designated	as	"normal	purchase/normal	sale"	transactions.	Changes	in	fair	value	of	derivatives	are	recognized	in	earnings	unless	specific hedge	criteria	are	met.	Income	and	expense	related	to	derivative	instruments	are	recognized	in	the	same	category	as	generated	by	the	underlying	asset	or	liability.

The	accounting	standards	for	derivatives	and	hedging	enable	companies	to	designate	qualifying	derivatives	as	hedging	instruments	based	on	the	exposure	being hedged.	These	hedge	designations	include	fair	value	hedges	and	cash	flow	hedges.	Changes	in	the	fair	value	of	a	derivative	that	is	highly	effective	and	is	designated	and qualifies	as	a	fair	value	hedge,	are	recognized	in	earnings	as	offsets	to	the	changes	in	fair	value	of	the	exposure	being	hedged.	The	Company	has	no	fair	value	hedges	at this	time.	Changes	in	the	fair	value	of	a	derivative	that	is	highly	effective	and	is	designated	as	and	qualifies	as	a	cash	flow	hedge,	are	deferred	in	accumulated	other comprehensive	income	and	are	recognized	into	earnings	as	the	hedged	transactions	occur.	Any	ineffectiveness	is	recognized	in	earnings	immediately.	For	all	hedge contracts,	the	Company	provides	formal	documentation	of	the	hedge	and	effectiveness	testing	in	accordance	with	the	accounting	standards	for	derivatives	and	hedging.

The	fair	value	measurement	accounting	standard	provides	additional	guidance	on	the	definition	of	fair	value	and	defines	fair	value	as	the	price	that	would	be received	to	sell	an	asset	or	paid	to	transfer	a	liability	in	an	orderly	transaction	between	market	participants	at	the	measurement	date,	or	exit	price.	The	fair	value measurement	standard	requires	the	Company	to	consider	and	reflect	the	assumptions	of	market	participants	in	the	fair	value	calculation.	These	factors	include nonperformance	risk	(the	risk	that	the	obligation	will	not	be	fulfilled)	and	credit	risk,	both	of	the	reporting	entity	(for	liabilities)	and	of	the	counterparty	(for	assets).	Due to	the	nature	of	the	Company's	interest	rate	swaps,	which	are	typically	associated	with	non-recourse	debt,	credit	risk	for	AES	is	evaluated	at	the	subsidiary	level	rather than	at	the	Parent	Company	level.	Nonperformance	risk	on	the	Company's	derivative	instruments	is	an	adjustment	to	the	initial	asset/liability	fair	value	position	that	is derived	from	internally	developed	valuation	models	that	utilize	observable	market	inputs.

As	a	result	of	uncertainty,	complexity	and	judgment,	accounting	estimates	related	to	derivative	accounting	could	result	in	material	changes	to	our	financial statements	under	different	conditions	or	utilizing	different	assumptions.	As	a	part	of	accounting	for	these	derivatives,	we	make	estimates	concerning	nonperformance, volatilities,	market	liquidity,	future	commodity	prices,	interest	rates,	credit	ratings	(both	ours	and	our	counterparty's)	and	exchange	rates.

The	fair	value	of	our	derivative	portfolio	is	generally	determined	using	internal	valuation	models,	most	of	which	are	based	on	observable	market	inputs	including interest	rate	curves	and	forward	and	spot	prices	for	currencies	and	commodities.	The	Company	derives	most	of	its	financial	instrument	market	assumptions	from	market efficient	data	sources	(e.g.,	Bloomberg	and	Platt's).	In	some	cases,	where	market	data	is	not	readily	available,	management	uses	comparable	market	sources	and empirical	evidence	to	derive	market	assumptions	to	determine	a	financial	instrument's	fair	value.	In	certain	instances,	the	published	curve	may	not	extend	through	the remaining	term	of	the	contract	and	management	must	make	assumptions	to	extrapolate	the	curve.	Additionally,	in	the	absence	of	quoted	prices,	we	may	rely	on "indicative	pricing"	quotes	from	financial	institutions	to	input	into	our	valuation	model	for	certain	of	our	foreign	currency	swaps.	These	indicative	pricing	quotes	do	not constitute	either	a	bid	or	ask	price	and	therefore	are	not	considered	observable	market	data.	For	individual	contracts,	the	use	of	different	valuation	models	or assumptions	could	have	a	material	effect	on	the	calculated	fair	value.

# Fair	Value	of	Nonfinancial	Assets	and	Liabilities

The	Company	adopted	the	fair	value	measurement	accounting	guidance	for	nonfinancial	assets	and	liabilities	effective	January	1,	2009.	The	most	significant	of these	estimates	surround	the	fair	value	measurement	of	long-lived	tangible	and	intangible	assets	when	tested	for	impairment	upon	a	triggering	event	or	during	the	annual impairment	evaluation	for	indefinite-lived	intangible	assets,	including	goodwill.	These	estimates	include	making	assumptions	regarding	useful	life,	the	impact	of economic	obsolescence	and	expected	future	cash	flows.	Additional	factors	are	discussed	above	in	the	Impairments	section.

# Fair	Value	Hierarchy

The	Company	uses	valuation	techniques	and	methodologies	that	maximize	the	use	of	observable	inputs	and	minimize	the	use	of	unobservable	inputs.	Where available,	fair	value	is	based	on	observable	market	prices	or	parameters	or	derived	from	such	prices	or	parameters.	Where	observable	prices	are	not	available,	valuation models	are	applied	to	estimate	the	fair	value	using	the	available	observable	inputs.	The	valuation	techniques	involve	some	level	of	management	estimation	and judgment,	the	degree	of	which	is	dependent	on	the	price	transparency	for	the	instruments	or	market	and	the	instruments'	complexity.

To	increase	consistency	and	enhance	disclosure	of	the	fair	value	of	financial	instruments,	the	fair	value	measurement	standard	creates	a	fair	value	hierarchy	to prioritize	the	inputs	used	to	measure	fair	value	into	three	categories.	A	financial	instrument's	level	within	the	fair	value	hierarchy	is	based	on	the	lowest	level	of	input significant	to	the	fair	value	measurement,	where	Level	1	is	the	highest	and	Level	3	is	the	lowest.	For	more	information	regarding	the	fair	value	hierarchy,	see	Note	1 —General	and	Summary	of	Significant	Accounting	Policies	in	Item	8.	Financial	Statements	and	Supplementary	Data	of	this	Form	10-K.

# Regulatory	Assets	and	Liabilities

The	Company	accounts	for	certain	of	its	regulated	operations	in	accordance	with	the	regulatory	accounting	standards.	As	a	result,	AES	recognizes	assets	and liabilities	that	result	from	the	regulated	ratemaking	process	that	would	not	be	recognized	under	GAAP	for	non-regulated	entities.	Regulatory	assets	generally	represent incurred	costs	that	have	been	deferred	because	such	costs	are	probable	of	future	recovery	through	customer	rates.	Regulatory	liabilities	generally	represent	obligations	to make	refunds	to	customers	for	previous	collections	for	costs	that	are	not	likely	to	be	incurred	or	included	in	future	rate	initiatives.	Management	continually	assesses whether	the	regulatory	assets	are	probable	of	future	recovery	by	considering	factors	such	as	applicable	regulatory	changes,	recent	rate	orders	applicable	to	other regulated	entities	and	the	status	of	any	pending	or	potential	deregulation	legislation.	If	future	recovery	of	costs	ceases	to	be	probable,	any	asset	write-offs	would	be required	to	be	recognized	in	operating	income.

# New	Accounting	Pronouncements	Adopted

Effective	January	1,	2010,	we	adopted	new	accounting	provisions	related	to	the	following	topics	as	a	result	of	new	accounting	guidance	issued	by	the	Financial Accounting	Standards	Board	("FASB").	The	financial	statement	impact	of	these	new	accounting	pronouncements	is	included	in	Note	1—General	and	Summary	of Significant	Accounting	Policies	included	in	Item	8	of	this	Form	10-K.

•	 Consolidations,	Improvements	to	Financial	Reporting	by	Enterprises	Involved	with	Variable	Interest	Entities	("VIEs").	The	new	accounting	guidance	on the	consolidation	of	VIEs	requires	an	entity	to	qualitatively,	rather	than	quantitatively,	assess	the	determination	of	the	primary	beneficiary	of	a	VIE.	This determination	is	based	on	whether	the	entity	has	the	power	to	direct	the	activities	that	most	significantly	impact	the	economic	performance	of	the	VIE	and the	obligation	to	absorb	losses	or	the	right	to	receive	benefits	of	the	VIE	that	could	potentially	be	significant	to	the	VIE.	Other	key	changes	include:	a requirement	for	the	ongoing	reconsideration	of	the	primary	beneficiary,	the	criteria	for	determining	whether	service	provider	or	decision	maker	contracts are	variable	interests,	the	consideration	of	kick-out	and	removal	rights	in	determining	whether	an	entity	is	a	VIE,	the	types	of	events	that	trigger	the reassessment	of	whether	an	entity	is	a	VIE	and	the	expansion	of	the	disclosures	previously	required.	The	adoption	of	the	new	accounting	guidance	on	the consolidation	of	VIEs	resulted	in	the	deconsolidation	of	certain	immaterial	VIEs	previously	consolidated.	Additionally,	assets,	liabilities	and	operating results	of	two	of	the	Company's	VIEs,	previously	accounted	for	under	the	equity	method	of	accounting,	were	required	to	be	consolidated.	Cartagena,	a	71% owned	generation	business	in	Spain,	and	Cili,	a	51%	owned	generation	business	in	China,	were	consolidated	under	the	new	guidance.

•Accounting	for	Transfers	of	Financial	Assets.	The	new	accounting	guidance	on	transfers	of	financial	assets,	among	other	things:	removes	the	concept	of	a qualifying	special	purpose	entity;	introduces	the

concept	of	participating	interests	and	specifies	that	in	order	to	qualify	for	sale	accounting	a	partial	transfer	of	a	financial	asset	or	a	group	of	financial	assets should	meet	the	definition	of	a	participating	interest;	clarifies	that	an	entity	should	consider	all	arrangements	made	contemporaneously	with	or	in contemplation	of	a	transfer	and	requires	enhanced	disclosures	to	provide	financial	statement	users	with	greater	transparency	about	transfers	of	financial assets	and	a	transferor's	continuing	involvement	with	transfers	of	financial	assets	accounted	for	as	sales.	Upon	adoption	on	January	1,	2010,	the	Company recognized	$40	million	as	accounts	receivable	and	as	an	associated	secured	borrowing	on	its	Consolidated	Balance	Sheet;	both	of	which	have	since increased	to	$50	million	as	of	December	31,	2010,	as	additional	interests	in	receivables	have	been	sold.	While	securitizing	these	accounts	receivable through	IPL	Funding,	a	special	purpose	entity,	IPL,	the	Company's	integrated	utility	in	Indianapolis,	had	previously	recognized	the	transaction	as	a	sale, but	had	not	recognized	the	accounts	receivable	and	secured	borrowing	on	its	balance	sheet.

# Accounting	Pronouncements	Issued	But	Not	Yet	Effective

The	following	accounting	standards	have	been	issued,	but	as	of	December	31,	2010	are	not	yet	effective	for	and	have	not	been	adopted	by	AES.

Accounting	Standards	Update	("ASU")	No.	2010-28,	Intangibles—Goodwill	and	Other	(Topic	350),	When	to	Perform	Step	2	of	the	Goodwill	Impairment	Test	for Reporting	Units	with	Zero	or	Negative	Carrying	Amounts

In	December	2010,	the	FASB	issued	ASU	No.	2010-28,	which	amends	the	accounting	guidance	related	to	goodwill.	The	amendments	in	ASU	No.	2010-28 modify	Step	1	of	the	goodwill	impairment	test	for	reporting	units	with	zero	or	negative	carrying	amounts.	For	those	reporting	units,	an	entity	is	required	to	perform	Step 2	of	the	goodwill	impairment	test	if	it	is	more	likely	than	not	that	a	goodwill	impairment	exists,	eliminating	an	entity's	ability	to	assert	that	a	reporting	unit	is	not required	to	perform	Step	2	because	the	carrying	amount	of	the	reporting	unit	is	zero	or	negative	despite	the	existence	of	qualitative	factors	that	indicate	the	goodwill	is more	likely	than	not	impaired.	In	determining	whether	it	is	more	likely	than	not	that	a	goodwill	impairment	exists,	an	entity	should	consider	whether	there	are	any adverse	qualitative	factors	indicating	that	an	impairment	may	exist.	ASU	No.	2010-28	is	effective	for	fiscal	years,	and	interim	periods	within	those	years,	beginning after	December	15,	2010,	or	January	1,	2011	for	AES.	Early	adoption	is	prohibited.	The	adoption	is	not	expected	to	have	a	material	impact	on	the	Company's	financial position,	results	of	operations	or	cash	flows.

# Capital	Resources	and	Liquidity

Overview.	In	November	2009,	the	Company	announced	a	binding	stock	purchase	agreement	with	CIC,	to	sell	125.5	million	shares	of	AES	stock	to	CIC, representing	a	15%	ownership	stake	in	the	Company.	The	transaction	closed	in	March	2010	and	generated	$1.58	billion	of	new	equity	to	fund	future	growth opportunities.	During	2010,	the	Company	redeemed	$690	million	aggregate	principal	of	its	outstanding	8.75%	Second	Priority	Senior	Secured	Notes	due	2013.	The Notes	were	redeemed	in	May	and	October	2010	at	a	redemption	price	equal	to	101.458%	of	the	principal	amount	redeemed.

As	of	December	31,	2010,	the	Company	had	unrestricted	cash	and	cash	equivalents	of	$2.6	billion,	of	which	approximately	$1.1	billion	is	held	at	the	Parent Company	and	qualified	holding	companies,	and	short	term	investments	of	$1.7	billion.	In	addition,	we	had	restricted	cash	and	debt	service	reserves	of	$1.3	billion.	The Company	also	had	non-recourse	and	recourse	aggregate	principal	amounts	of	debt	outstanding	of	$15.1	billion	and	$4.6	billion,	respectively.	Of	the	approximately	$2.6 billion	of	our	short-term	non-recourse	debt,	$1.2	billion	is	presented	as	current	because	it	is	due	in	the	next	twelve	months	and	$1.4	billion	relates	to	defaulted	debt.	We expect	such	current	maturities	will	be	repaid	from	net	cash	provided	by	operating	activities	of	the	subsidiary	to	which	the	debt	relates	or	through	opportunistic refinancing	activity	or	some	combination	thereof.	Approximately	$463	million	of	our	recourse	debt	matures	within	the	next	twelve	months,	which	we	expect	to	repay using	cash	on	hand	at	the	Parent	Company	or	through	net	cash	provided	by	operating	activities.	See	further	discussion	of	Parent	Company	Liquidity	below.

The	Company	has	two	types	of	debt	reported	on	its	consolidated	balance	sheet:	non-recourse	and	recourse	debt.	Non-recourse	debt	is	used	to	fund	investments and	capital	expenditures	for	construction	and	acquisition	of	our	electric	power	plants,	wind	projects	and	distribution	facilities	at	our	subsidiaries.	Non-recourse	debt	is generally	secured	by	the	capital	stock,	physical	assets,	contracts	and	cash	flows	of	the	related	subsidiary.	The	default	risk	is	limited	to	the	respective	business	and	is without	recourse	to	the	Parent	Company	and	other	subsidiaries.	Recourse	debt	is	direct	borrowings	by	the	Parent	Company	and	is	used	to	fund	development, construction	or	acquisitions,	including	funding	for	equity	investments	or	to	provide	loans	to	the	Parent	Company's	subsidiaries	or	affiliates.	This	Parent	Company	debt	is with	recourse	to	the	Parent	Company	and	is	structurally	subordinated	to	the	debt	of	the	Parent	Company's	subsidiaries	or	affiliates,	except	to	the	extent	such	subsidiaries or	affiliates	guarantee	the	Parent	Company's	debt.

We	rely	mainly	on	long-term	debt	obligations	to	fund	our	construction	activities.	We	have,	to	the	extent	available	at	acceptable	terms,	utilized	non-recourse	debt to	fund	a	significant	portion	of	the	capital	expenditures	and	investments	required	to	construct	and	acquire	our	electric	power	plants,	distribution	companies	and	related assets.	Our	non-recourse	financing	is	designed	to	limit	cross	default	risk	to	the	Parent	Company	or	other	subsidiaries	and	affiliates.	Our	non-recourse	long-term	debt	is	a combination	of	fixed	and	variable	interest	rate	instruments.	Generally,	a	portion	or	all	of	the	variable	rate	debt	is	fixed	through	the	use	of	interest	rate	swaps.	In	addition, the	debt	is	typically	denominated	in	the	currency	that	matches	the	currency	of	the	revenue	expected	to	be	generated	from	the	benefiting	project,	thereby	reducing currency	risk.	In	certain	cases,	the	currency	is	matched	through	the	use	of	derivative	instruments.	The	majority	of	our	non-recourse	debt	is	funded	by	international commercial	banks,	with	debt	capacity	supplemented	by	multilaterals	and	local	regional	banks.	For	more	information	on	our	long-term	debt,	see	Note	10—Debt	of	the Consolidated	Financial	Statements	included	in	Item	8.	of	this	Form	10-K.

Given	our	long-term	debt	obligations,	the	Company	is	subject	to	interest	rate	risk	on	debt	balances	that	accrue	interest	at	variable	rates.	When	possible,	the Company	will	borrow	funds	at	fixed	interest	rates	or	hedge	its	variable	rate	debt	to	fix	its	interest	costs	on	such	obligations.	In	addition,	the	Company	has	historically tried	to	maintain	at	least	70%	of	its	consolidated	long-term	obligations	at	fixed	interest	rates,	including	fixing	the	interest	rate	through	the	use	of	interest	rate	swaps. These	efforts	apply	to	the	notional	amount	of	the	swaps	compared	to	the	amount	of	related	underlying	debt.	While	the	Company	believes	that	this	represents	an economic	hedge,	the	Company	is	required	to	mark-to-market	all	of	these	interest	rate	swaps	and	other	derivatives.	Presently,	the	Parent	Company's	only	direct	exposure to	variable	interest	rate	debt	relates	to	indebtedness	under	its	senior	secured	credit	facility.	On	a	consolidated	basis,	of	the	Company's	$19.7	billion	of	total	debt outstanding	as	of	December	31,	2010,	approximately	$5.0	billion	bore	interest	at	variable	rates	that	were	not	subject	to	a	derivative	instrument	which	fixed	the	interest rate.

In	addition	to	utilizing	non-recourse	debt	at	a	subsidiary	level	when	available,	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	of	a	particular	project.	These	investments	have	generally	taken	the	form	of	equity investments	or	intercompany	loans,	which	are	subordinated	to	the	project's	non-recourse	loans.	We	generally	obtain	the	funds	for	these	investments	from	our	cash	flows from	operations,	proceeds	from	the	sales	of	assets	and/or	the	proceeds	from	our	issuances	of	debt,	common	stock	and	other	securities.	Similarly,	in	certain	of	our businesses,	the	Parent	Company	may	provide	financial	guarantees	or	other	credit	support	for	the	benefit	of	counterparties	who	have	entered	into	contracts	for	the purchase	or	sale	of	electricity,	equipment	or	other	services	with	our	subsidiaries	or	lenders.	In	such	circumstances,	if	a	business	defaults	on	its	payment	or	supply obligation,	the	Parent	Company	will	be	responsible	for	the	business'	obligations	up	to	the	amount	provided	for	in	the	relevant	guarantee	or	other	credit	support.	At December	31,	2010,	the	Parent	Company	had	provided	outstanding	financial	and	performance-related	guarantees	or	other	credit	support	commitments	to	or	for	the benefit	of	our	businesses,	which	were	limited	by	the	terms	of	the	agreements,	of	approximately	$415	million	in	aggregate	(excluding	investment	commitments	and	those collateralized	by	letters	of	credit	and	other	obligations	discussed	below).

As	a	result	of	the	Parent	Company's	below	investment	grade	rating,	counterparties	may	be	unwilling	to	accept	our	general	unsecured	commitments	to	provide credit	support.	Accordingly,	with	respect	to	both	new	and	existing	commitments,	the	Parent	Company	may	be	required	to	provide	some	other	form	of	assurance,	such	as a	letter	of	credit,	to	backstop	or	replace	our	credit	support.	The	Parent	Company	may	not	be	able	to	provide	adequate	assurances	to	such	counterparties.	To	the	extent	we are	required	and	able	to	provide	letters	of	credit	or	other	collateral	to	such	counterparties,	this	will	reduce	the	amount	of	credit	available	to	us	to	meet	our	other	liquidity needs.	At	December	31,	2010,	we	had	$85	million	in	letters	of	credit	outstanding,	which	operate	to	guarantee	performance	relating	to	certain	project	development activities	and	business	operations.	These	letters	of	credit	were	provided	under	the	senior	secured	credit	facility.	During	the	year	ended	December	31,	2010,	the	Company paid	letter	of	credit	fees	ranging	from	3.19%	to	3.75%	per	annum	on	the	outstanding	amounts.

We	expect	to	continue	to	seek,	where	possible,	non-recourse	debt	financing	in	connection	with	the	assets	or	businesses	that	we	or	our	affiliates	may	develop, construct	or	acquire.	However,	depending	on	local	and	global	market	conditions	and	the	unique	characteristics	of	individual	businesses,	non-recourse	debt	may	not	be available	on	economically	attractive	terms	or	at	all.	See	Global	Economic	Conditions	discussion	above.	If	we	decide	not	to	provide	any	additional	funding	or	credit support	to	a	subsidiary	project	that	is	under	construction	or	has	near-term	debt	payment	obligations	and	that	subsidiary	is	unable	to	obtain	additional	non-recourse	debt, such	subsidiary	may	become	insolvent,	and	we	may	lose	our	investment	in	that	subsidiary.	Additionally,	if	any	of	our	subsidiaries	lose	a	significant	customer,	the subsidiary	may	need	to	withdraw	from	a	project	or	restructure	the	non-recourse	debt	financing.	If	we	or	the	subsidiary	choose	not	to	proceed	with	a	project	or	are	unable to	successfully	complete	a	restructuring	of	the	non-recourse	debt,	we	may	lose	our	investment	in	that	subsidiary.

Many	of	our	subsidiaries	depend	on	timely	and	continued	access	to	capital	markets	to	manage	their	liquidity	needs.	The	inability	to	raise	capital	on	favorable terms,	to	refinance	existing	indebtedness	or	to	fund	operations	and	other	commitments	during	times	of	political	or	economic	uncertainty	may	have	material	adverse effects	on	the	financial	condition	and	results	of	operations	of	those	subsidiaries.	In	addition,	changes	in	the	timing	of	tariff	increases	or	delays	in	the	regulatory determinations	under	the	relevant	concessions	could	affect	the	cash	flows	and	results	of	operations	of	our	businesses.

As	of	December	31,	2010,	the	Company	had	approximately	$347	million	of	trade	accounts	receivable	related	to	certain	of	its	generation	and	utility	businesses	in Latin	America	classified	as	other	long-term	assets.	These	consist	primarily	of	trade	accounts	receivable	that,	pursuant	to	amended	agreements	or	government	resolutions, have	collection	periods	that	extend	beyond	December	31,	2011,	or	one	year	past	the	balance	sheet	date.	The	Company	is	actively	collecting	these	receivables	and	does not	expect	any	significant	collection	issues.	Additionally,	the	current	portion	of	these	trade	accounts	receivable	was	$101	million	at	December	31,	2010.

# Capital	Expenditures

The	Company	spent	$2.3	billion,	$2.5	billion	and	$2.9	billion	on	capital	expenditures	in	2010,	2009	and	2008,	respectively.	A	significant	majority	of	these	costs were	funded	with	non-recourse	debt	consistent	with	our	financial	strategy.	At	December	31,	2010,	the	Company	had	a	total	of	$432	million	of	availability	under	long- term	non-recourse	construction	credit	facilities.	As	more	fully	described	in	Key	Trends	and	Uncertainties	above,	we	have	taken	steps	to	decrease	the	amount	of	new discretionary	capital	spending.	We	expect	to	continue	funding	projects	that	are	currently	in	the	construction	phase	using	existing	capital	provided	by	these	non-recourse credit	facilities	as	supplemented	by	internally	generated	cash	flows,	Parent	Company	liquidity,	contribution	from	existing	or	new	partners	and	other	funding	sources.	As a	result,	property,	plant	and	equipment	and	long-term	non-recourse	debt	are	expected	to	increase	over	the	next	few	years	even	though	the	rate	of	discretionary	spending has	decreased.	While	we	believe	we	have	the	resources	to	continue	funding	the	projects	in	construction,	there	can	be	no	assurances	that	we	will	continue	to	fund	all	these existing	construction	efforts.

As	of	December	31,	2010,	the	Company	had	$66	million	of	commitments	to	invest	in	subsidiaries	under	construction	and	to	purchase	related	equipment, excluding	$26	million	of	such	obligations	already	included	in	the

letters	of	credit	discussed	above.	The	Company	expects	to	fund	these	net	investment	commitments	in	2011.	The	exact	payment	schedules	will	be	dictated	by	the construction	milestones.	We	expect	to	fund	these	commitments	from	a	combination	of	current	liquidity	and	internally	generated	Parent	Company	cash	flow.

# Environmental	Capital	Expenditures

The	Company	continues	to	assess	the	possible	need	for	capital	expenditures	associated	with	international,	federal,	regional	and	state	regulation	of	GHG	emissions from	electric	power	generation	facilities.	Currently	in	the	United	States	there	is	no	Federal	legislation	establishing	mandatory	GHG	emissions	reduction	programs (including	CO )	affecting	the	electric	power	generating	facilities	of	the	Company's	subsidiaries.	There	are	numerous	state	programs	regulating	GHG	emissions	from electric	power	generation	facilities	and	there	is	a	possibility	that	federal	GHG	legislation	will	be	enacted	within	the	next	several	years.	Further,	the	EPA	has	adopted regulations	pertaining	to	GHG	emissions	and	has	announced	its	intention	to	propose	new	regulations	for	electric	generating	units	under	Section	111	of	the	CAA.	The EPA	regulations	and	any	subsequent	Federal	legislation,	if	enacted,	may	place	significant	costs	on	GHG	emissions	from	fossil	fuel-fired	electric	power	generation facilities,	particularly	coal-fired	facilities,	and	in	order	to	comply,	CO 	emitting	facilities	may	be	required	to	purchase	additional	GHG	emissions	allowances	or	offsets under	cap-and-trade	programs,	pay	a	carbon	tax	or	install	new	emission	reduction	equipment	to	capture	or	reduce	the	amount	of	GHG	emitted	from	the	facilities,	in	the event	that	reliable	technology	to	do	so	is	developed.	The	capital	expenditures	required	to	comply	with	any	future	GHG	legislation	or	any	GHG	regulations	could	be significant	and	unless	such	costs	can	be	passed	on	to	customers	or	counterparties,	such	regulations	could	impair	the	profitability	of	some	of	the	electric	power	generation facilities	operated	by	our	subsidiaries	or	render	certain	of	them	uneconomical	to	operate,	either	of	which	could	have	a	material	adverse	effect	on	our	consolidated	results of	operations	and	financial	condition.

With	respect	to	our	operations	outside	the	United	States,	certain	of	the	businesses	operated	by	the	Company's	subsidiaries	are	subject	to	compliance	with	EU	ETS and	the	Kyoto	Protocol	in	certain	countries	and	other	country-specific	programs	to	regulate	GHG	emissions.	To	date,	compliance	with	the	Kyoto	Protocol	and	EU	ETS has	not	had	a	material	adverse	effect	on	the	Company's	consolidated	results	of	operations,	financial	condition	and	cash	flows	because	of,	among	other	factors,	the	cost	of GHG	emission	allowances	and/or	the	ability	of	our	businesses	to	pass	the	cost	of	purchasing	such	allowances	on	to	customers	or	counterparties.	However,	in	the	event that	such	counterparties	or	regulatory	authorities	challenge	our	ability	to	pass	these	costs	on,	there	can	be	no	assurance	that	the	Company	and/or	the	relevant	subsidiary would	prevail	in	any	such	dispute.	Furthermore,	even	if	the	Company	and/or	the	relevant	subsidiary	does	prevail,	it	would	be	subject	to	the	cost	and	administrative burden	associated	with	such	dispute.

As	discussed	in	Item	1.—Business—Regulatory	Matters—Environmental	and	Land	Use	Regulations,	in	the	United	States	there	presently	is	no	federal	legislation establishing	mandatory	GHG	emission	reduction	programs.	In	2010,	the	Company's	subsidiaries	operated	businesses	which	had	total	approximate	CO 	emissions	of 77.2	million	metric	tonnes	(ownership	adjusted).	Approximately	40	million	metric	tonnes	of	the	77.2	million	metric	tonnes	were	emitted	in	the	United	States	(both figures	ownership	adjusted).	Approximately	11.3	million	metric	tonnes	were	emitted	in	United	States	states	participating	in	the	RGGI.	We	believe	that	legislative	or regulatory	actions,	if	enacted,	may	require	a	material	increase	in	capital	expenditures	at	our	subsidiaries.

In	the	future	the	actual	impact	on	our	subsidiaries'	capital	expenditures	from	any	potential	federal	program	to	regulate	and	reduce	GHG	emissions,	if	enacted,	and the	state	and	regional	programs	developed	or	in	the	process	of	development,	or	any	EPA	regulation	of	GHG	emissions,	will	depend	on	a	number	of	factors,	including among	others,	the	GHG	reductions	required	under	any	such	legislation	or	regulations,	the	cost	of	emissions	reduction	equipment,	the	price	and	availability	of	offsets,	the extent	to	which	our	subsidiaries	would	be	entitled	to	receive	GHG	emission	allowances	without	having	to	purchase	them,	the	quantity	of	allowances	which	our subsidiaries	would	have	to	purchase,	the	price	of	allowances,	and	our	subsidiaries'	ability	to	recover	or	pass-through	costs	incurred	to	comply	with	any	legislative	or regulatory	requirements	that	are	ultimately	imposed	and	the	use	of	market-based	compliance	options	such	as	cap-and-trade	programs.

We	recognized	tax	expense	of	$307	million	for	the	year	ended	December	31,	2010,	while	our	cash	payments	for	income	taxes,	net	of	refunds,	totaled	$698 million.	The	difference	resulted	primarily	from	impairment	charges	recognized	at	certain	subsidiaries	in	the	United	States,	for	which	we	recognized	a	benefit	in	our domestic	tax	provision.	As	a	result,	global	cash	tax	payments	exceeded	the	consolidated	tax	provision.

# Consolidated	Cash	Flows

At	December	31,	2010,	cash	and	cash	equivalents	increased	$772	million	from	December	31,	2009	to	$2.6	billion.	The	increase	in	cash	and	cash	equivalents	was due	to	$3.5	billion	of	cash	provided	by	operating	activities,	$2.0	billion	of	cash	used	for	investing	activities,	$706	million	of	cash	used	for	financing	activities	and	the favorable	effect	of	foreign	currency	exchange	rates	on	cash	of	$8	million.

At	December	31,	2009,	cash	and	cash	equivalents	increased	$917	million	from	December	31,	2008	to	$1.8	billion.	The	increase	in	cash	and	cash	equivalents	was due	to	$2.2	billion	of	cash	provided	by	operating	activities,	$1.9	billion	of	cash	used	for	investing	activities,	$610	million	of	cash	provided	by	financing	activities	and	the favorable	effect	of	foreign	currency	exchange	rates	on	cash	of	$22	million.

|  | 2010 | 2009 | 2008 | 2010	vs.	2009 | 2009	vs.	2008 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | (in\tmillions) |  |  |
| Net\tcash\tprovided\tby\toperating\tactivities | $3,510 | $2,202 | $2,160 | $1,308 | $42 |
| Net\tcash\tused\tin\tinvesting\tactivities | $2,040 | $1,917 | $3,581 | $123 | $(1,664) |
| Net\tcash\t(used\tin)\tprovided\tby\tfinancing\tactivities | $(706) | $610 | $362 | $(1,316) | $248 |

# Operating	Activities

Net	cash	provided	by	operating	activities	increased	$1.3	billion,	or	59%,	to	$3.5	billion	during	2010	compared	to	2009.	This	net	increase	was	primarily	due	to	the following:

# Investing	Activities

Net	cash	used	for	investing	activities	increased	$123	million,	or	6%,	to	$2.0	billion	during	2010	compared	to	2009.	This	increase	was	largely	attributable	to	the following:

•an	increase	in	the	purchase	of	short-term	investments	of	$1.6	billion	during	2010	compared	to	2009	primarily	due	to	the	investment	of	cash	proceeds	from debt	issuances	at	our	Brazilian	subsidiaries	and	the	purchase	of	time	deposits	at	Gener	in	2010.	Purchases	were	offset	by	an	increase	in	sales	of	short-term investments	of	$1.3	billion	mainly	due	to	the	use	of	proceeds	from	investments	for	the	repayment	of	debt	instruments	and	dividend	distributions	at	our Brazilian	subsidiaries	and	the	sales	of	time	deposits	at	Gener;

•an	increase	of	$406	million	in	funding	requirements	for	restricted	cash	balances	during	2010	compared	to	2009.	During	2010,	$104	million	of	funds	were transferred	to	restricted	cash	balances	while	during	2009,	$302	million	was	transferred	out	of	restricted	cash;

•an	increase	of	$254	million	for	acquisitions,	net	of	cash	acquired,	primarily	due	to	$138	million	related	to	the	acquisition	of	Ballylumford	in	Northern Ireland,	$65	million	related	to	the	purchase	of	three	wind	development	pipelines	in	the	U.K.	and	Poland,	$35	million	related	to	the	acquisition	of	JHRH, and	$11	million	related	to	the	buyout	of	noncontrolling	interests	at	Changuinola;

•an	increase	of	$241	million	in	debt	service	reserves	during	2010	compared	to	2009.	During	2010,	$56	million	of	funds	were	transferred	to	debt	service reserves	while	during	2009,	$185	million	was	utilized	for	debt	maturities;	partially	offset	by

•an	increase	of	$593	million	in	proceeds	from	the	sale	of	businesses	primarily	due	to	proceeds	of	$226	million	related	to	the	sale	in	October	2010	of	Ras Laffan	in	Qatar,	$170	million	related	to	the	sale	in	August	2010	of	Barka	in	Oman,	the	final	settlement	proceeds	of	$99	million	received	in	January	2010 from	the	termination	of	a	management	agreement	with	Kazakhmys	in	Kazakhstan	related	to	Ekibastuz	and	Maikuben	which	were	sold	in	May	2008,	and	the net	proceeds	from	the	sale	of	Lal	Pir	and	Pak	Gen	in	Pakistan	in	June	2010	of	$100	million;

•a	decrease	of	$210	million	in	capital	expenditures	to	$2.3	billion	primarily	due	to	a	decrease	in	expenditures	of	$298	million	at	Gener	and	$250	million	at our	Europe	Wind	generation	projects.	These	decreases	were	partially	offset	by	a	net	increase	in	capital	expenditures	of	$261	million	at	our	Brazilian subsidiaries,	$66	million	at	Maritza	in	Bulgaria,	and	$16	million	at	our	U.S.	Wind	generation	projects;	and

•an	increase	of	$132	million	in	proceeds	related	to	the	repayment	of	the	loan	receivable	from	a	wind	development	project	in	Brazil.	There	were	no	proceeds from	loan	repayments	during	2009.

# Financing	Activities

Net	cash	used	for	financing	activities	increased	$1,316	million,	or	216%,	to	$706	million	during	2010	compared	to	net	cash	provided	by	financing	activities	of $610	million	during	2009.	This	increase	was	primarily	attributable	to	the	following:

•a	$1.7	billion	increase	in	repayments	of	recourse	and	non-recourse	debt,	predominately	due	to	increases	of	$760	million	of	recourse	debt	repayments	at	the Parent	Company,	$706	million	at	our	Brazilian	businesses,	$279	million	at	our	businesses	in	the	Dominican	Republic,	$55	million	at	Masinloc	in	the Philippines,	$44	million	at	New	York,	$40	million	at	our	European	wind	businesses,	$31	million	at	Chigen	and	$30	million	at	Cartagena,	partially	offset by	decreases	of	$132	million	at	IPALCO	and	$115	at	Armenia	Mountain;

•a	$560	million	decrease	in	proceeds	from	issuances	of	recourse	and	non-recourse	debt	primarily	due	to	decreases	of	$503	million	of	recourse	debt	at	the Parent	Company,	$286	million	at	Gener,	$209	million	at	Armenia	Mountain,	$208	million	at	our	European	wind	businesses,	$123	million	at	Sonel	and $122	million	at	IPALCO,	partially	offset	by	increases	of	$604	million	at	our	Brazilian	businesses	and	$294	million	at	our	businesses	in	the	Dominican Republic;

•a	$399	million	increase	in	distributions	to	noncontrolling	interests,	primarily	due	to	$245	million	at	our	Brazilian	businesses,	$84	million	related	to distributions	in	connection	with	the	sale	of	discontinued	operations	and	$69	million	at	Armenia	Mountain;

•a	$190	million	decrease	in	contributions	from	noncontrolling	interests	primarily	due	to	a	reduction	of	$117	million	at	Armenia	Mountain	and	$71	million at	Gener;	and

•a	$99	million	acquisition	of	treasury	stock.

•a	$1.6	billion	issuance	of	common	stock	net	of	transaction	costs	to	CIC;	and

•a	$67	million	increase	in	net	borrowings	under	revolving	credit	facilities	primarily	due	to	decreased	repayments	attributable	to	discontinued	operations	sold in	2010.

# Contractual	Obligations

A	summary	of	our	contractual	obligations,	commitments	and	other	liabilities	as	of	December	31,	2010	is	presented	in	the	table	below	(in	millions):

|  |  | Less	than |  |  | 5	years |  | Footnote |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Contractual\tObligations | Total | 1\tyear | 1-3\tyears | 4-5\tyears | and\tmore | Other | Reference^(10) |
| Debt\tObligations^(1) | $19,653 | $3,026 | $1,591 | $3,963 | $11,073 | $— | 10 |
| Interest\tPayments\ton\tLong-Term\tDebt^(2) | 9,533 | 1,358 | 2,531 | 2,055 | 3,589 | \t — | n/a |
| Capital\tLease\tObligations^(3) | 206 | 17 | 26 | 21 | 142 | \t — | 11 |
| Operating\tLease\tObligations^(4) | 919 | 56 | 111 | 104 | 648 | \t — | 11 |
| Sale/Leaseback\tObligations^(5) | 664 | 43 | 90 | 94 | 437 | \t — | 11 |
| Electricity\tObligations^(6) | 52,160 | 3,055 | 6,118 | 5,211 | \t 37,776 | \t — | 11 |
| Fuel\tObligations^(7) | 8,871 | 1,587 | 1,887 | 1,006 | 4,391 | \t — | 11 |
| Other\tPurchase\tObligations^(8) | 21,040 | 1,628 | 2,603 | 2,752 | \t 14,057 | \t — | 11 |
| Other\tLong-term\tLiabilities\tReflected\ton\tAES's\tConsolidated\tBalance\tSheet |  |  |  |  |  |  |  |
| under\tGAAP^(9) | 625 | 4 | 93 | 94 | 298 | \t 136 | n/a |
| Total | $113,671 | $10,774 | $15,050 | $15,300 | $72,411 | $136 |  |

Includes	recourse	and	non-recourse	debt	presented	on	the	Consolidated	Balance	Sheet.	Non-recourse	debt	borrowings	are	not	a	direct	obligation	of	AES,	the Parent	Company.	Recourse	debt	represents	the	direct	borrowings	of	AES,	the	Parent	Company.	See	Note	10—Debt	to	the	Consolidated	Financial	Statements included	in	Item	8	of	this	Form	10-K	which	provides	additional	disclosure	regarding	these	obligations.	These	amounts	exclude	capital	lease	obligations	which	are included	in	the	capital	lease	category,	see	(3)	below.

Interest	payments	are	estimated	based	on	final	maturity	dates	of	debt	securities	outstanding	at	December	31,	2010	and	do	not	reflect	anticipated	future	refinancing, early	redemptions	or	new	debt	issuances.	Variable	rate	interest	obligations	are	estimated	based	on	rates	as	of	December	31,	2010.

Several	AES	subsidiaries	have	leases	for	operating	and	office	equipment	and	vehicles	that	are	classified	as	capital	leases	within	Property,	Plant	and	Equipment.

Minimum	contractual	obligations	include	$127	million	of	imputed	interest.

The	Company	was	obligated	under	long-term	noncancelable	operating	leases,	primarily	for	office	rental	and	site	leases.	These	amounts	exclude	amounts	related to	the	sale/leaseback	discussed	below	in	item	(5).

Sale/Leaseback	Obligations—represent	a	sales/leaseback	with	operating	lease	treatment	at	one	of	our	New	York	subsidiaries.

Operating	subsidiaries	of	the	Company	have	entered	into	contracts	for	the	purchase	of	electricity	from	third	parties.

Operating	subsidiaries	of	the	Company	have	entered	into	fuel	purchase	contracts	subject	to	termination	only	in	certain	limited	circumstances.

Amounts	relate	to	other	contractual	obligations	where	the	Company	has	an	enforceable	and	legally	binding	agreement	to	purchase	goods	or	services	that	specifies all	significant	terms,	including:	quantity,	pricing,	and	approximate	timing.	These	amounts	include	planned	capital	expenditures	that	are	contractually	obligated. These	amounts	do	not	include	current	liabilities	on	the	Consolidated	Balance	Sheet	except	for	the	current	portion	of	uncertain	tax	obligations.	Noncurrent uncertain	tax	obligations	are	reflected	in	the	"Other"	column	of	the	table	above	as	the	Company	is	not	able	to	reasonably	estimate	the	timing	of	the	future payments.	In	addition,	the	amounts	do	not	include:	(1)	regulatory	liabilities	(See	Note	9—Regulatory	Assets	and	Liabilities),	(2)	contingencies	(See	Note	12— Contingencies),	(3)	pension	and	other	post	retirement	employee	benefit	liabilities	(see	Note	13—Benefit	Plans)	or	(4)	any	taxes	(See	Note	20—Income	Taxes) except	for	uncertain	tax	obligations,	as	the	Company	is	not	able	to	reasonably	estimate	the	timing	of	future	payments.	See	the	indicated	notes	to	the	Consolidated Financial	Statements	included	in	Item	8	of	this	Form	10-K	for	additional	information	on	the	items	excluded.	Derivatives	(See	Note	6—Derivative	Instruments	and Hedging	Activities)	and	incentive	compensation	are	excluded	as	the	Company	is	not	able	to	reasonably	estimate	the	timing	or	amount	of	the	future	payments. For	further	information	see	the	note	referenced	below	in	Item	8.—Financial	Statements	and	Supplementary	Data.

# Parent	Company	Liquidity

The	following	discussion	of	"Parent	Company	Liquidity"	has	been	included	because	we	believe	it	is	a	useful	measure	of	the	liquidity	available	to	The	AES Corporation,	or	the	Parent	Company,	given	the	non-recourse	nature	of	most	of	our	indebtedness.	Parent	Company	liquidity	as	outlined	below	is	a	non-GAAP	measure and	should	not	be	construed	as	an	alternative	to	cash	and	cash	equivalents	which	are	determined	in	accordance	with	GAAP,	as	a	measure	of	liquidity.	Cash	and	cash equivalents	are	disclosed	in	the	Consolidated	Statements	of	Cash	Flows	and	the	Parent	Only	Unconsolidated	Statements	of	Cash	Flows	in	Schedule	I	of	this	Form	10-K. Parent	Company	liquidity	may	differ	from	similarly	titled	measures	used	by	other	companies.	The	principal	sources	of	liquidity	at	the	Parent	Company	level	are:

•dividends	and	other	distributions	from	our	subsidiaries,	including	refinancing	proceeds;

•proceeds	from	debt	and	equity	financings	at	the	Parent	Company	level,	including	availability	under	our	credit	facilities;	and

Cash	requirements	at	the	Parent	Company	level	are	primarily	to	fund:

•interest;

•construction	commitments;

•other	equity	commitments;

•Parent	Company	overhead	and	development	costs.

The	Company	defines	Parent	Company	Liquidity	as	cash	available	to	the	Parent	Company	plus	available	borrowings	under	existing	credit	facilities.	The	cash	held at	qualified	holding	companies	represents	cash	sent	to	subsidiaries	of	the	Company	domiciled	outside	of	the	U.S.	Such	subsidiaries	have	no	contractual	restrictions	on their	ability	to	send	cash	to	the	Parent	Company.	Parent	Company	Liquidity	is	reconciled	to	its	most	directly

comparable	U.S.	GAAP	financial	measure,	"cash	and	cash	equivalents"	at	December	31,	2010	and	2009	as	follows:

| Parent	Company	Liquidity | 2010 | 2009 |
| :--- | :--- | :--- |
|  | (in\tmillions) |  |
| Cash\tand\tcash\tequivalents | $2,554 | $1,782 |
| Less:\tCash\tand\tcash\tequivalents\tat\tsubsidiaries | (1,432) | (1,105) |
| Parent\tand\tqualified\tholding\tcompanies\tcash\tand\tcash\tequivalents | 1,122 | 677 |
| Commitments\tunder\tParent\tcredit\tfacilities | 800 | 785 |
| Less:\tBorrowings\tand\tletters\tof\tcredit\tunder\tthe\tcredit\tfacilities | (85) | (204) |
| Borrowings\tavailable\tunder\tParent\tcredit\tfacilities | 715 | 581 |
| Total\tParent\tCompany\tLiquidity | $1,837 | $1,258 |

# Recourse	Debt	Transactions:

During	2010,	the	Company	redeemed	$690	million	aggregate	principal	of	its	8.75%	Second	Priority	Senior	Secured	Notes	due	2013	("the	2013	Notes").	The 2013	Notes	were	redeemed	at	a	redemption	price	equal	to	101.458%	of	the	principal	amount	redeemed.	The	Company	recognized	a	pre-tax	loss	on	the	redemption	of	the 2013	Notes	of	$15	million	for	the	year	ended	December	31,	2010,	which	is	included	in	"Other	expense"	in	the	accompanying	Consolidated	Statement	of	Operations.

On	July	29,	2010,	the	Company	entered	into	an	Amendment	No.	2	(the	"Amendment	No.	2")	to	the	Fourth	Amended	and	Restated	Credit	and	Reimbursement Agreement,	dated	as	of	July	29,	2008,	among	the	Company,	various	subsidiary	guarantors	and	various	lending	institutions	(the	"Existing	Credit	Agreement")	that amends	and	restates	the	Existing	Credit	Agreement	(as	so	amended	and	restated	by	the	Amendment	No.	2,	the	"Fifth	Amended	and	Restated	Credit	Agreement").	The Fifth	Amended	and	Restated	Credit	Agreement	adjusted	the	terms	and	conditions	of	the	Existing	Credit	Agreement,	including	the	following	changes:

•the	aggregate	commitment	for	the	revolving	credit	loan	facility	was	increased	to	$800	million;

•the	final	maturity	date	of	the	revolving	credit	loan	facility	was	extended	to	January	29,	2015;

•there	were	changes	to	the	facility	fee	applicable	to	the	revolving	credit	loan	facility;

•the	interest	rate	margin	applicable	to	the	revolving	credit	loan	facility	is	now	based	on	the	credit	rating	assigned	to	the	loans	under	the	credit	agreement, with	pricing	currently	at	LIBOR	+	3.00%;

•the	Company	may	incur	a	combination	of	additional	term	loan	and	revolver	commitments	so	long	as	total	term	loan	and	revolver	commitments	(including those	currently	outstanding)	do	not	exceed	$1.4	billion;	and

•the	negative	pledge	(i.e.,	a	cap	on	first	lien	debt)	of	$3.0	billion.

# Recourse	Debt:

Our	recourse	debt	at	year-end	was	approximately	$4.6	billion	and	$5.5	billion	in	2010	and	2009,	respectively.	The	following	table	sets	forth	our	Parent	Company contingent	contractual	obligations	as	of	December	31,	2010:

| Contingent	contractual	obligations | Amount | Number	of<br>Agreements | for	Each<br>Agreement | for	Each<br>Agreement |
| :--- | :--- | :--- | :--- | :--- |
|  | (in\tmillions) |  | (in\tmillions) | (in\tmillions) |
| Guarantees | $415 | 24 | &lt;$ | 1\t-\t$62 |
| Letters\tof\tcredit\tunder\tthe\tsenior\tsecured\tcredit\tfacility | 85 | 30 | &lt;$ | 1\t-\t$26 |
| Total | $500 | 54 |  |  |

As	of	December	31,	2010,	the	Company	had	$66	million	of	commitments	to	invest	in	subsidiaries	under	construction	and	to	purchase	related	equipment, excluding	$26	million	of	such	obligations	already	included	in	the	letters	of	credit	discussed	above.	The	Company	expects	to	fund	these	net	investment	commitments	in 2011.	The	exact	payment	schedules	will	be	dictated	by	the	construction	milestones.	We	expect	to	fund	these	commitments	from	a	combination	of	current	liquidity	and internally	generated	Parent	Company	cash	flow.

We	have	a	diverse	portfolio	of	performance	related	contingent	contractual	obligations.	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, subsidiary	default,	political	risk,	tax	indemnities,	spot	market	power	prices,	sponsor	support	and	liquidated	damages	under	power	sales	agreements	for	projects	in development,	in	operation	and	under	construction.	While	we	do	not	expect	that	we	will	be	required	to	fund	any	material	amounts	under	these	contingent	contractual obligations	during	2011	or	beyond,	many	of	the	events	which	would	give	rise	to	such	obligations	are	beyond	our	control.	We	can	provide	no	assurance	that	we	will	be able	to	fund	our	obligations	under	these	contingent	contractual	obligations	if	we	are	required	to	make	substantial	payments	thereunder.

While	we	believe	that	our	sources	of	liquidity	will	be	adequate	to	meet	our	needs	for	the	foreseeable	future,	this	belief	is	based	on	a	number	of	material assumptions,	including,	without	limitation,	assumptions	about	our	ability	to	access	the	capital	markets	(see	Key	Trends	and	Uncertainties	and	Global	Economic Conditions),	the	operating	and	financial	performance	of	our	subsidiaries,	currency	exchange	rates,	power	market	pool	prices,	and	the	ability	of	our	subsidiaries	to	pay dividends.	In	addition,	our	subsidiaries'	ability	to	declare	and	pay	cash	dividends	to	us	(at	the	Parent	Company	level)	is	subject	to	certain	limitations	contained	in	loans, governmental	provisions	and	other	agreements.	We	can	provide	no	assurance	that	these	sources	will	be	available	when	needed	or	that	the	actual	cash	requirements	will not	be	greater	than	anticipated.	We	have	met	our	interim	needs	for	shorter-term	and	working	capital	financing	at	the	Parent	Company	level	with	our	senior	secured credit	facility.	See	Item	1A.—Risk	Factors,	"The	AES	Corporation	is	a	holding	company	and	its	ability	to	make	payments	on	its	outstanding	indebtedness,	including	its public	debt	securities,	is	dependent	upon	the	receipt	of	funds	from	its	subsidiaries	by	way	of	dividends,	fees,	interest,	loans	or	otherwise."	of	this	Form	10-K.

Various	debt	instruments	at	the	Parent	Company	level,	including	our	senior	secured	credit	facility,	contain	certain	restrictive	covenants.	The	covenants	provide for,	among	other	items:

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

•limitations	on	dividends,	stock	repurchases	and	other	equity	transactions;

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

•	 maintenance	of	certain	financial	ratios;	and

•financial	and	other	reporting	requirements.

As	of	December	31,	2010,	we	were	in	compliance	with	these	covenants	at	the	Parent	Company	level.

# Non-Recourse	Debt:

While	the	lenders	under	our	non-recourse	debt	financings	generally	do	not	have	direct	recourse	to	the	Parent	Company,	defaults	thereunder	can	still	have important	consequences	for	our	results	of	operations	and	liquidity,	including,	without	limitation:

•reducing	our	cash	flows	as	the	subsidiary	will	typically	be	prohibited	from	distributing	cash	to	the	Parent	Company	during	the	time	period	of	any	default;

•triggering	our	obligation	to	make	payments	under	any	financial	guarantee,	letter	of	credit	or	other	credit	support	we	have	provided	to	or	on	behalf	of	such subsidiary;

•causing	us	to	record	a	loss	in	the	event	the	lender	forecloses	on	the	assets;	and

•triggering	defaults	in	our	outstanding	debt	at	the	Parent	Company.

For	example,	our	senior	secured	credit	facilities	and	outstanding	debt	securities	at	the	Parent	Company	include	events	of	default	for	certain	bankruptcy	related events	involving	material	subsidiaries.	In	addition,	our	revolving	credit	agreement	at	the	Parent	Company	includes	events	of	default	related	to	payment	defaults	and accelerations	of	outstanding	debt	of	material	subsidiaries.

Some	of	our	subsidiaries	are	currently	in	default	with	respect	to	all	or	a	portion	of	their	outstanding	indebtedness.	The	total	non-recourse	debt	classified	as	current in	the	accompanying	Consolidated	Balance	Sheets	amounts	to	$2.6	billion.	The	portion	of	current	debt	related	to	such	defaults	was	$1.4	billion	at	December	31,	2010,	all of	which	was	non-recourse	debt	related	to	four	subsidiaries—Maritza,	Sonel,	Kelanitissa	and	Aixi.

None	of	the	subsidiaries	that	are	currently	in	default	are	subsidiaries	that	met	the	applicable	definition	of	materiality	under	AES'	corporate	debt	agreements	as	of December	31,	2010	in	order	for	such	defaults	to	trigger	an	event	of	default	or	permit	acceleration	under	such	indebtedness.	However,	as	a	result	of	additional	dispositions of	assets,	other	significant	reductions	in	asset	carrying	values	or	other	matters	in	the	future	that	may	impact	our	financial	position	and	results	of	operations	or	the financial	position	of	the	individual	subsidiary,	it	is	possible	that	one	or	more	of	these	subsidiaries	could	fall	within	the	definition	of	a	"material	subsidiary"	and	thereby upon	an	acceleration	trigger	an	event	of	default	and	possible	acceleration	of	the	indebtedness	under	the	AES		Parent	Company's	outstanding	debt	securities.

# Off-Balance	Sheet	Arrangements

In	May	1999,	our	subsidiary	in	New	York	acquired	six	electric	generating	plants	from	New	York	State	Electric	and	Gas.	Concurrently,	the	subsidiary	sold	two	of the	plants	to	unrelated	third	parties	for	$666	million	and	simultaneously	entered	into	a	leasing	arrangement	with	the	unrelated	parties.	In	May	2007,	the	subsidiary purchased	37.5%	interest	in	a	trust	estate	that	holds	the	leased	plants.	Future	minimum	lease	commitments	under	the	lease	agreement	have	been	reduced	by	the subsidiary's	interest	in	the	plants.	We	have	accounted	for	this	sale/leaseback	transaction	as	an	operating	lease.	We	amortize	the	off-balance	sheet	lease	obligation reduced	by	the	subsidiary	interest	over	the	life	of	the	lease,	which	resulted	in	the	recognition	of	expense	of	$34	million	for	each	of	the	years	ended	December	31,	2010, 2009	and	2008,	respectively.	AES	is	not	subject	to	any	additional	liabilities	or	contingencies	if	the	arrangement	terminates	and	we	believe	that	the	dissolution	of	the	off- balance	sheet	arrangement	would	have	minimal	effects	on	our	operating	cash	flows.	The	terms	of	Eastern	Energy's	credit	facility	include	restrictive	covenants	such	as the	maintenance	of	certain	coverage	ratios.	Historically,	the	plants	have	satisfied	the	restrictive	covenants	of	the	credit	facility;	however	as	a	result	of	the	continued pressure	on	energy	prices	and	negative	forecasted	operating	cash	flow	and	losses	previously	discussed	under	Key	Trends	and	Uncertainties,	management	does	not believe	that	cash	flow	from	operations,	together	with	amounts	available	under	existing	credit	facilities,	will	be	sufficient	to	cover	expected	capital	requirements	over	the terms	of	the	leases.	Management	is	exploring	revenue	enhancements	as	well	as	reviewing	cost	and	debt	structure	for	meaningful	reductions	that	could	be	implemented	in the	future;	however,	in	the	event	of	a	default	Eastern	Energy	could	be	subject	to	full	payment	of	the	outstanding	principal,	accrued	interest	and	termination	costs	under its	lease	arrangements	and	existing	$200	million	credit	facility.	In	addition,	the	subsidiary	lessor	could	be	subject	to	full	payment	of	the	outstanding	principal,	accrued interest	and	make-whole	premiums	under	its	bond	indenture.	Also,	a	default	by	Eastern	Energy	or	its	related	subsidiaries	could	result	in	the	loss	of	AES's	ownership interest	in	Eastern	Energy	and	related	subsidiaries.	See	Note	11—Commitments	to	the	Consolidated	Financial	Statements	included	in	Item	8	of	this	Form	10-K	for further	discussion	of	this	transaction.

# ITEM	7A. QUANTITATIVE	AND	QUALITATIVE	DISCLOSURES	ABOUT	MARKET	RISK

# Overview	Regarding	Market	Risks

We	are	a	global	company	in	the	power	generation	and	distribution	businesses.	We	own	and/or	operate	power	plants	to	generate	and	sell	power	to	wholesale customers.	We	also	own	and/or	operate	utilities	to	distribute,	transmit	and	sell	electricity	to	end-user	customers.	Our	primary	market	risk	exposure	is	to	the	price	of commodities	particularly	electricity,	oil,	natural	gas,	coal	and	environmental	credits.	We	operate	in	multiple	countries	and	as	such	are	subject	to	volatility	in	exchange rates	at	the	subsidiary	level	and	between	our	functional	currency,	the	U.S.	Dollar,	and	currencies	of	the	countries	in	which	we	operate.	We	are	also	exposed	to	interest rate	fluctuations	due	to	our	issuance	of	debt	and	related	financial	instruments.

These	disclosures	set	forth	in	this	Item	7A	are	based	upon	a	number	of	assumptions,	and	actual	impacts	to	the	Company	may	not	follow	the	assumptions	made	by the	Company.	The	safe	harbor	provided	in	Section	27A	of	the	Securities	Act	of	1933	and	Section	21E	of	the	Securities	Exchange	Act	of	1934	shall	apply	to	the disclosures	contained	in	this	Item	7A.	For	further	information	regarding	market	risk,	see	Item	1A.—Risk	Factors,	"Our	financial	position	and	results	of	operations	may fluctuate	significantly	due	to	fluctuations	in	currency	exchange	rates	experienced	at	our	foreign	operations",	"Our	businesses	may	incur	substantial	costs	and	liabilities and	be	exposed	to	price	volatility	as	a	result	of	risks	associated	with	the	wholesale	electricity	markets,	which	could	have	a	material	adverse	effect	on	our	financial performance"	and	"We	may	not	be	adequately	hedged	against	our	exposure	to	changes	in	commodity	prices	or	interest	rates"	in	this	Form	10-K.

# Commodity	Price	Risk

We	are	exposed	to	the	impact	of	market	fluctuations	in	the	price	of	electricity,	fuels	and	environmental	credits.	Although	we	primarily	consist	of	businesses	with long-term	contracts	or	retail	sales	concessions,	a	portion	of	our	current	and	expected	future	revenues	are	derived	from	businesses	without	significant	long-term	revenue or	supply	contracts.	These	businesses	subject	our	operational	results	to	the	volatility	of	prices	for	electricity,	fuels	and	environmental	credits	in	competitive	markets.	We employ	risk	management	strategies	to	hedge	our	financial	performance	against	the	effects	of	fluctuations	in	energy	commodity	prices.	The	implementation	of	these strategies	can	involve	the	use	of	physical	and	financial	commodity	contracts,	futures,	swaps	and	options.

When	hedging	the	output	of	our	generation	assets,	we	have	PPAs	or	other	hedging	instruments	that	lock	in	the	spread	per	MWh	between	variable	costs,	such	as fuel,	to	generate	a	unit	of	electricity	and	the	price	at	which	the	electricity	can	be	sold.	The	portion	of	our	sales	and	purchases	that	are	not	subject	to	such	agreements	will be	exposed	to	commodity	price	risk.

AES	businesses	will	see	variance	in	variable	margin	performance	as	global	commodity	prices	shift.	For	2011,	including	operations	from	the	Company's	merchant generation	assets	in	New	York,	we	project	pre-tax	earnings	exposure	would	be	approximately	$10	million	for	a	$10/barrel	move	in	oil,	$110	million	for	a	$1/MMBTU move	in	natural	gas,	and	$50	million	for	a	$10/ton	shift	in	coal	prices.	Excluding	New	York,	we	project	approximately	$35	million	for	a	$1/MMBTU	move	in	natural gas	and	$35	million	for	a	$10/ton	shift	in	coal	prices.	The	decrease	in	oil	exposure	from	$15	million	on	December	31,	2009	is	primarily	due	to	higher	hedge	levels	at some	businesses	and	lower	hedging	of	fuel	costs	at	our	Hungarian	facility	where	fuel	cost	is	indexed	to	oil	partially	offset	by	higher	exposure	at	Gener	due	to	the commissioning	of	new	power	facilities.	The	increase	in	natural	gas	exposure	from	$50	million	on	December	31,	2009	is	primarily	due	to	lower	hedging	levels	at	Eastern Energy,	due	to	dark	spread	compression,	and	our	Kilroot	facility,	which	is	no	longer	operating	under	a	long-term	PPA.	The	increase	in	coal	exposure	from	$20	million on	December	31,	2009	arises	primarily	from	the	lower	hedge	levels	at	Eastern	Energy,	Kilroot	long-term	PPA	termination,	Argentina	pricing	rules	that	limit	the	ability to	reflect	coal	price	movement	under	some	conditions,	and	inclusion	of	China	due	to	a	delay	in	energy	tariff	resets	intended	to	reflect	changes	in	coal	prices.	These numbers	have	been	produced	by	forecasting	the	impact	of	a	change	in	commodity	price	to	spot	power	prices	and	power	and	fuel	contracts	held	by	each	business.	Our estimates	exclude	correlation.	For	example,	a	decline	in	oil	or	natural	gas	prices	can	be	accompanied	by	a	decline

in	coal	price	if	commodity	prices	are	correlated.	In	aggregate,	the	Company's	downside	exposure	occurs	with	lower	oil,	lower	natural	gas,	and	higher	coal	prices. Exposures	at	individual	businesses	will	change	as	new	contracts	or	financial	hedges	are	executed.

Commodity	prices	affect	our	businesses	differently	depending	on	the	local	market	characteristics	and	risk	management	strategies.	Generation	costs	can	be	directly affected	by	movements	in	the	price	of	natural	gas,	oil	and	coal.	Spot	power	prices	and	contract	indexation	provisions	are	affected	by	these	same	commodity	price movements.	We	have	some	natural	offsets	across	our	businesses	such	that	low	commodity	prices	may	benefit	certain	businesses	and	be	a	cost	to	others.	Variance	is	not perfectly	linear	or	symmetric.	The	sensitivities	are	affected	by	a	number	of	non-market,	or	indirect	market,	factors.	Examples	of	these	factors	include	hydrology,	energy market	supply/demand	balances,	regional	fuel	supply	issues,	and	regulatory	interventions	such	as	price	caps.	Operational	flexibility	changes	the	shape	of	our sensitivities.	For	instance,	power	plants	may	reduce	dispatch	in	low	market	environments	limiting	downside	exposure.	Volume	variation	also	affects	our	commodity exposure.	The	volume	sold	under	contracts	or	retail	concessions	can	vary	based	on	weather	and	economic	conditions	resulting	in	a	higher	or	lower	volume	of	sales	in spot	markets.	Thermal	unit	availability	and	hydrology	can	affect	the	generation	output	available	for	sale	and	can	affect	the	marginal	unit	setting	power	prices.

Our	larger	contributors	to	commodity	risk	include	Eastern	Energy	and	wholesale	power	sales	from	IPL	in	North	America;	Gener,	Argentina,	the	Dominican Republic	and	Panama	in	Latin	America;	Kilroot	in	Europe;	and	Masinloc	in	Asia.

In	North	America,	commodity	risk	is	due	to	"dark	spread"	to	the	extent	a	portion	of	sales	are	un-hedged.	Given	that	natural	gas-fired	generators	set	power	prices for	many	periods,	higher	natural	gas	prices	expand	margins	and	higher	coal	prices	cause	a	decline	in	margins.	The	positive	impact	on	margins	will	be	moderated	if natural	gas-fired	generators	set	the	market	price	only	during	certain	peak	periods.	IPL	sells	power	at	wholesale	once	retail	demand	is	served,	so	retail	sales	demand	may affect	commodity	exposure.

In	Chile,	we	own	assets	and	have	associated	contracts	in	both	the	central	and	northern	regions	of	the	country.	Contracts	tend	to	be	long-term	and	indexed	to	fuel limiting	commodity	risk.	Oil-fired	generators	set	power	prices	for	some	periods	impacting	spot	power	margins.	Gener	has	been	adding	coal-fired	generation	to	its portfolio,	increasing	its	exposure	to	dark	spreads	on	un-hedged	volumes.	Gener	also	owns	natural	gas/diesel,	hydropower	and	biomass	generation	facilities.

In	other	Latin	American	markets,	the	businesses	have	commodity	exposure	on	un-hedged	volumes.	In	Panama	and	Colombia,	we	own	hydropower	assets,	so contracts	are	not	indexed	to	fuel.	In	the	Dominican	Republic,	we	own	natural	gas-fired	and	coal-fired	assets,	and	both	contract	and	spot	prices	may	move	with commodity	prices.	In	Argentina,	prices	are	set	according	to	government	rules	that	result	in	commodity	exposure	based	on	the	spread	between	cost	of	coal-fired generation	and	oil-fired	generation	and	other	factors.

In	Europe,	our	Kilroot	facility's	long	term	PPA	was	terminated	during	the	fourth	quarter	of	2010.	The	commodity	risk	at	our	Kilroot	business	is	due	to	"dark spread"	to	the	extent	sales	are	un-hedged.	Natural	gas-fired	generators	set	power	prices	for	many	periods,	so	higher	natural	gas	prices	expand	margins	and	higher	coal prices	cause	a	decline.	The	positive	impact	on	margins	will	be	moderated	if	natural	gas-fired	generators	set	the	market	price	only	during	certain	peak	periods.

Our	Masinloc	business	in	Asia	is	a	coal-fired	generation	facility,	which	hedges	its	output	through	medium	term	contracts	that	are	indexed	to	fuel	prices.	Low	oil prices	may	be	a	driver	of	margin	compression	since	oil	affects	spot	power	sale	prices.

# Foreign	Exchange	Rate	Risk

In	the	normal	course	of	business,	we	are	exposed	to	foreign	currency	risk	and	other	foreign	operations	risks	that	arise	from	investments	in	foreign	subsidiaries	and affiliates.	A	key	component	of	these	risks	stems	from	the	fact	that	some	of	our	foreign	subsidiaries	and	affiliates	utilize	currencies	other	than	our	consolidated	reporting currency,	the	U.S.	Dollar.	Additionally,	certain	of	our	foreign	subsidiaries	and	affiliates	have	entered	into	monetary	obligations	in	the	U.S.	Dollar	or	currencies	other than	their	own	functional	currencies.	Primarily,	we	are	exposed	to	changes	in	the	exchange	rate	between	the	U.S.	Dollar	and	the	following	currencies:	Argentine	Peso, Brazilian	Real,	British	Pound,	Cameroonian	Franc,	Chilean	Peso,	Colombian	Peso,	Euro,	Kazakhstani	Tenge,	Mexican	Peso,	and	Philippine	Peso.	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.	We	also	use foreign	currency	forwards,	swaps	and	options,	where	possible,	to	manage	our	risk	related	to	certain	foreign	currency	fluctuations.

During	2010,	we	entered	into	hedges	to	partially	mitigate	the	exposure	of	earnings	translated	into	the	U.S.	Dollar	to	foreign	exchange	volatility.	As	of December	31,	2010,	assuming	a	10%	U.S.	Dollar	appreciation,	2011	pre-tax	earnings	attributable	to	foreign	subsidiaries	exposed	to	movements	in	the	exchange	rates	of the	Brazilian	Real,	Chilean	Peso,	Philippine	Peso	and	Euro	(the	earnings	attributable	to	subsidiaries	exposed	to	Cameroonian	Franc	movements	are	included	under	Euro due	to	the	fixed	exchange	rate	of	the	Cameroonian	Franc	to	the	Euro)	relative	to	the	U.S.	Dollar	are	projected	to	be	approximately	$40	million,	$15	million,	$10	million, and	$20	million,	respectively,	and	represent	the	majority	of	the	Company's	pre-tax	earnings	exposure	to	currency	moves.	The	increases	relative	to	December	31,	2009 figures,	which	were	$35	million,	$10	million,	$5	million	and	$10	million	for	the	Brazilian	Real,	Chilean	Peso,	Philippine	Peso	and	Euro,	respectively,	are	primarily driven	by	forecasted	increases	in	the	foreign	currency	denominated	pre-tax	earnings	notably	attributable	to	businesses	in	Brazil,	Chile,	the	Philippines	and	Europe.	These numbers	have	been	produced	by	applying	a	one-time	10%	U.S.	Dollar	appreciation	to	forecasted	exposed	pre-tax	earnings	for	2011	coming	from	subsidiaries	where	the local	currency	is	either	not	the	U.S.	Dollar	or	is	not	exhibiting	the	characteristics	of	a	peg	or	managed	float	relative	to	the	U.S.	Dollar,	net	of	the	impact	of	outstanding hedges	and	holding	all	other	variables	constant.	The	numbers	presented	above	are	net	of	any	transactional	gains/losses.	These	sensitivities	may	change	in	the	future	as new	hedges	are	executed	or	existing	hedges	unwound.	Additionally,	updates	to	the	forecasted	pre-tax	earnings	exposed	to	foreign	exchange	risk	may	result	in	further modification.

# Interest	Rate	Risks

We	are	exposed	to	risk	resulting	from	changes	in	interest	rates	as	a	result	of	our	issuance	of	variable	and	fixed-rate	debt,	as	well	as	interest	rate	swap,	cap	and floor	and	option	agreements.

Decisions	on	the	fixed-floating	debt	ratio	are	made	to	be	consistent	with	the	risk	factors	faced	by	individual	businesses	or	plants.	Depending	on	whether	a	plant's capacity	payments	or	revenue	stream	is	fixed	or	varies	with	inflation,	we	partially	hedge	against	interest	rate	fluctuations	by	arranging	fixed-rate	or	variable-rate financing.	In	certain	cases,	particularly	for	non-recourse	financing,	we	execute	interest	rate	swap,	cap	and	floor	agreements	to	effectively	fix	or	limit	the	interest	rate exposure	on	the	underlying	financing.

As	of	December	31,	2010,	the	portfolio's	2011	pre-tax	earnings	exposure	(adjusted	to	reflect	noncontrolling	interests)	to	a	100	basis	point	increase	in	Brazilian Real,	British	Pound,	Colombian	Peso,	Euro,	Philippine	Peso,	Ukraine	Hryvnia	and	U.S.	Dollar	interest	rates	would	be	approximately	$25	million.	This	number	is	based on	the	impact	of	a	one-time,	100	basis	point	increase	in	interest	rates	on	interest	expense	for	Brazilian	Real,	British	Pound,	Colombian	Peso,	Euro,	Philippine	Peso, Ukraine	Hryvnia	and	U.S.	Dollar-denominated	debt,	which	is	primarily	non-recourse	financing.	The	numbers	do	not	take	into	account	the	historical	correlation	between these	interest	rates.	This	compares	to	$20	million	as	of	December	31,	2009.	The	increase	is	driven	by	an	increase	in	the	notional	amount	of	floating	rate	debt	in	the portfolio.

# ITEM	8. FINANCIAL	STATEMENTS	AND	SUPPLEMENTARY	DATA

# REPORT	OF	INDEPENDENT	REGISTERED	PUBLIC	ACCOUNTING	FIRM

The	Board	of	Directors	and	Stockholders	of	The	AES	Corporation:

We	have	audited	the	accompanying	consolidated	balance	sheets	of	The	AES	Corporation	and	subsidiaries	as	of	December	31,	2010	and	December	31,	2009,	and the	related	consolidated	statements	of	operations,	stockholders'	equity	and	cash	flows	for	each	of	the	three	years	in	the	period	ended	December	31,	2010.	Our	audits	also included	the	financial	statement	schedules	listed	in	the	index	at	Item	15(a).	These	financial	statements	and	schedules	are	the	responsibility	of	the	Company's management.	Our	responsibility	is	to	express	an	opinion	on	these	financial	statements	and	schedules	based	on	our	audits.

We	conducted	our	audits	in	accordance	with	the	standards	of	the	Public	Company	Accounting	Oversight	Board	(United	States).	Those	standards	require	that	we plan	and	perform	the	audit	to	obtain	reasonable	assurance	about	whether	the	financial	statements	are	free	of	material	misstatement.	An	audit	includes	examining,	on	a test	basis,	evidence	supporting	the	amounts	and	disclosures	in	the	financial	statements.	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.

In	our	opinion,	the	financial	statements	referred	to	above	present	fairly,	in	all	material	respects,	the	consolidated	financial	position	of	The	AES	Corporation	and subsidiaries	at	December	31,	2010	and	2009,	and	the	consolidated	results	of	their	operations	and	their	cash	flows	for	each	of	the	three	years	in	the	period	ended December	31,	2010,	in	conformity	with	U.S.	generally	accepted	accounting	principles.	Also,	in	our	opinion,	the	related	financial	statement	schedules,	when	considered in	relation	to	the	basic	financial	statements	taken	as	a	whole,	present	fairly,	in	all	material	respects,	the	information	set	forth	therein.

As	discussed	in	Note	1	to	the	consolidated	financial	statements,	in	2010	The	AES	Corporation	and	subsidiaries	changed	their	method	of	accounting	for	the consolidation	of	variable	interest	entities	with	the	adoption	of	amendments	to	Financial	Accounting	Standards	Board	("FASB")	Accounting	Standards	Codification ("ASC")	810,	Consolidation,	and	their	method	of	accounting	for	transfers	and	servicing	of	financial	assets	with	the	adoption	of	the	amendments	to	FASB	ASC	860, Transfers	and	Servicing,	both	effective	January	1,	2010.

We	also	have	audited,	in	accordance	with	the	standards	of	the	Public	Company	Accounting	Oversight	Board	(United	States),	The	AES	Corporation's	internal control	over	financial	reporting	as	of	December	31,	2010,	based	on	criteria	established	in	Internal	Control-Integrated	Framework	issued	by	the	Committee	of	Sponsoring Organizations	of	the	Treadway	Commission	and	our	report	dated	February	25,	2011	expressed	an	unqualified	opinion	thereon.

McLean,	Virginia

# CONSOLIDATED	BALANCE	SHEETS

| CURRENT	ASSETS |  |  |
| :--- | :--- | :--- |
| Cash\tand\tcash\tequivalents | $2,554 | $1,782 |
| Restricted\tcash | 574 | 407 |
| Short-term\tinvestments | 1,730 | 1,648 |
| Accounts\treceivable,\tnet\tof\tallowance\tfor\tdoubtful\taccounts\tof\t$308\tand\t$290,\trespectively | 2,362 | 2,118 |
| Inventory | 600 | 560 |
| Receivable\tfrom\taffiliates | 27 | 24 |
| Deferred\tincome\ttaxes—current | 306 | 210 |
| Prepaid\texpenses | 234 | 161 |
| Other\tcurrent\tassets | 1,059 | 1,557 |
| Current\tassets\tof\tdiscontinued\tand\theld\tfor\tsale\tbusinesses | — | 320 |
| Total\tcurrent\tassets | 9,446 | 8,787 |
| NONCURRENT\tASSETS |  |  |
| Property,\tPlant\tand\tEquipment: |  |  |
| Land | 1,128 | 1,111 |
| Electric\tgeneration,\tdistribution\tassets\tand\tother | 28,207 | 26,815 |
| Accumulated\tdepreciation | (9,173) | (8,774) |
| Construction\tin\tprogress | 4,459 | 4,644 |
| Property,\tplant\tand\tequipment,\tnet | 24,621 | 23,796 |
| Other\tAssets: |  |  |
| Deferred\tfinancing\tcosts,\tnet\tof\taccumulated\tamortization\tof\t$295\tand\t$293,\trespectively | 376 | 377 |
| Investments\tin\tand\tadvances\tto\taffiliates | 1,320 | 1,157 |
| Debt\tservice\treserves\tand\tother\tdeposits | 691 | 595 |
| Goodwill | 1,271 | 1,299 |
| Other\tintangible\tassets,\tnet\tof\taccumulated\tamortization\tof\t$160\tand\t$223,\trespectively | 516 | 510 |
| Deferred\tincome\ttaxes—noncurrent | 646 | 587 |
| Other | 1,624 | 1,551 |
| Noncurrent\tassets\tof\tdiscontinued\tand\theld\tfor\tsale\tbusinesses | — | 876 |
| Total\tother\tassets | 6,444 | 6,952 |
| TOTAL\tASSETS | $40,511 | $39,535 |
| LIABILITIES\tAND\tEQUITY |  |  |
| CURRENT\tLIABILITIES |  |  |
| Accounts\tpayable | $2,060 | $1,862 |
| Accrued\tinterest | 265 | 269 |
| Accrued\tand\tother\tliabilities | 2,700 | 2,331 |
| Non-recourse\tdebt—current,\tincluding\t$1,152\trelated\tto\tvariable\tinterest\tentities\tat\tDecember\t31,\t2010 | 2,577 | 1,718 |
| Recourse\tdebt—current | 463 | 214 |
| Current\tliabilities\tof\tdiscontinued\tand\theld\tfor\tsale\tbusinesses | — | 227 |
| Total\tcurrent\tliabilities | 8,065 | 6,621 |
| LONG-TERM\tLIABILITIES |  |  |
| Non-recourse\tdebt—noncurrent,\tincluding\t$2,201\trelated\tto\tvariable\tinterest\tentities\tat\tDecember\t31,\t2010 | 12,544 | 12,304 |
| Recourse\tdebt—noncurrent | 4,149 | 5,301 |
| Deferred\tincome\ttaxes—noncurrent | 895 | 1,090 |
| Pension\tand\tother\tpost-retirement\tliabilities | 1,522 | 1,322 |
| Other\tlong-term\tliabilities | 2,863 | 3,146 |
| Long-term\tliabilities\tof\tdiscontinued\tand\theld\tfor\tsale\tbusinesses | — | 811 |
| Total\tlong-term\tliabilities |  |  |
|  | 21,973 | 23,974 |
| Contingencies\tand\tCommitments\t(see\tNotes\t12\tand\t11) |  |  |
| Cumulative\tpreferred\tstock\tof\tsubsidiary | 60 | 60 |
| EQUITY |  |  |
| THE\tAES\tCORPORATION\tSTOCKHOLDERS'\tEQUITY |  |  |
| issued\tand\t667,679,913\toutstanding\tat\tDecember\t31,\t2009) | 8 | 7 |
| Additional\tpaid-in\tcapital | 8,444 | 6,868 |
| Retained\tearnings | 620 | 650 |
| Accumulated\tother\tcomprehensive\tloss | (2,383) | (2,724) |
| Treasury\tstock,\tat\tcost\t(17,287,073\tand\t9,534,580\tshares\tat\tDecember\t31,\t2010\tand\t2009,\trespectively) | (216) | (126) |
| Total\tThe\tAES\tCorporation\tstockholders'\tequity | 6,473 | 4,675 |
| NONCONTROLLING\tINTERESTS | 3,940 | 4,205 |
| Total\tequity | 10,413 | 8,880 |
| TOTAL\tLIABILITIES\tAND\tEQUITY | $40,511 | $39,535 |

See	Accompanying	Notes	to	these	Consolidated	Financial	Statements

# CONSOLIDATED	STATEMENTS	OF	OPERATIONS

|  | 2010 | 2009 | 2008 |
| :--- | :--- | :--- | :--- |
|  | (in\tmillions,\texcept\tper\tshare\tamounts) | (in\tmillions,\texcept\tper\tshare\tamounts) |  |
| Revenue: |  |  |  |
| Regulated | $9,145 | $7,816 | $7,768 |
| Non-Regulated | 7,502 | 6,138 | 7,429 |
| Total\trevenue | 16,647 | 13,954 | 15,197 |
| Cost\tof\tSales: |  |  |  |
| Regulated | (6,718) | (5,705) | (5,564) |
| Non-Regulated | (5,965) | (4,816) | (6,065) |
| Total\tcost\tof\tsales | (12,683) | (10,521) | (11,629) |
| Gross\tmargin | 3,964 | 3,433 | 3,568 |
| General\tand\tadministrative\texpenses | (392) | (339) | (368) |
| Interest\texpense | (1,526) | (1,485) | (1,770) |
| Interest\tincome | 411 | 348 | 519 |
| Other\texpense | (239) | (111) | (161) |
| Other\tincome | 108 | 465 | 375 |
| Gain\ton\tsale\tof\tinvestments | — | 131 | 909 |
| Loss\ton\tsale\tof\tsubsidiary\tstock | — | — | (31) |
| Goodwill\timpairment | (21) | (122) | — |
| Asset\timpairment\texpense | (1,221) | (25) | (175) |
| Foreign\tcurrency\ttransaction\tgains\t(losses)\ton\tnet\tmonetary\tposition | (33) | 33 | (184) |
| Other\tnon-operating\texpense | (7) | (12) | (15) |
| INCOME\tFROM\tCONTINUING\tOPERATIONS\tBEFORE\tTAXES\tAND\tEQUITY\tIN\tEARNINGS\tOF\tAFFILIATES | 1,044 | 2,316 | 2,667 |
| Income\ttax\texpense | (307) | (599) | (771) |
| Net\tequity\tin\tearnings\tof\taffiliates | 183 | 92 | 33 |
| INCOME\tFROM\tCONTINUING\tOPERATIONS | 920 | 1,809 | 1,929 |
| Income\tfrom\toperations\tof\tdiscontinued\tbusinesses,\tnet\tof\tincome\ttax\texpense\tof\t$2,\t$3\tand\t$7,\trespectively | 75 | 96 | 97 |
| Gain\t(loss)\tfrom\tdisposal\tof\tdiscontinued\tbusinesses,\tnet\tof\tincome\ttax\texpense\tof\t$132,\t$—\tand\t$—,\trespectively | 64 | (150) | 6 |
| NET\tINCOME | 1,059 | 1,755 | 2,032 |
| Noncontrolling\tinterests: |  |  |  |
| Less:\tIncome\tfrom\tcontinuing\toperations\tattributable\tto\tnoncontrolling\tinterests | (1,006) | (1,099) | (759) |
| Less:\t(Income)\tloss\tfrom\tdiscontinued\toperations\tattributable\tto\tnoncontrolling\tinterests | (44) | 2 | (39) |
| Total\tnet\tincome\tattributable\tto\tnoncontrolling\tinterests | (1,050) | (1,097) | (798) |
| NET\tINCOME\tATTRIBUTABLE\tTO\tTHE\tAES\tCORPORATION | $9 | $658 | $1,234 |
| BASIC\tEARNINGS\t(LOSS)\tPER\tSHARE: |  |  |  |
| Income\t(loss)\tfrom\tcontinuing\toperations\tattributable\tto\tThe\tAES\tCorporation\tcommon\tstockholders,\tnet\tof\ttax | $(0.11) | $1.06 | $1.75 |
| Discontinued\toperations\tattributable\tto\tThe\tAES\tCorporation\tcommon\tstockholders,\tnet\tof\ttax | 0.12 | (0.07) | 0.09 |
| NET\tINCOME\tATTRIBUTABLE\tTO\tTHE\tAES\tCORPORATION\tCOMMON\tSTOCKHOLDERS | $0.01 | $0.99 | $1.84 |
| DILUTED\tEARNINGS\t(LOSS)\tPER\tSHARE: |  |  |  |
| Income\t(loss)\tfrom\tcontinuing\toperations\tattributable\tto\tThe\tAES\tCorporation\tcommon\tstockholders,\tnet\tof\ttax | $(0.11) | $1.06 | $1.73 |
| Discontinued\toperations\tattributable\tto\tThe\tAES\tCorporation\tcommon\tstockholders,\tnet\tof\ttax | 0.12 | (0.08) | 0.09 |
| NET\tINCOME\tATTRIBUTABLE\tTO\tTHE\tAES\tCORPORATION\tCOMMON\tSTOCKHOLDERS | $0.01 | $0.98 | $1.82 |
| AMOUNTS\tATTRIBUTABLE\tTO\tTHE\tAES\tCORPORATION\tCOMMON\tSTOCKHOLDERS: |  |  |  |
| Income\t(loss)\tfrom\tcontinuing\toperations,\tnet\tof\ttax | $(86) | $710 | $1,170 |
| Discontinued\toperations,\tnet\tof\ttax | 95 | (52) | 64 |
| Net\tincome | $9 | $658 | $1,234 |

# CONSOLIDATED	STATEMENTS	OF	CASH	FLOWS

|  | 2010 | 2009 | 2008 |
| :--- | :--- | :--- | :--- |
|  |  | (in\tmillions) |  |
| OPERATING\tACTIVITIES: |  |  |  |
| Net\tincome | $ 1,059 | $ 1,755 | $ 2,032 |
| Adjustments\tto\tnet\tincome: |  |  |  |
| Depreciation\tand\tamortization | 1,178 | 1,049 | 1,001 |
| (Gain)\tloss\tfrom\tsale\tof\tinvestments\tand\timpairment\texpense | 1,313 | 57 | (712) |
| (Gain)\tloss\ton\tdisposal\tand\timpairment\twrite-down—discontinued\toperations | (209) | 150 | (7) |
| Provision\tfor\tdeferred\ttaxes | (418) | 15 | 160 |
| Contingencies | 37 | (122) | 52 |
| (Gain)\tloss\ton\tthe\textinguishment\tof\tdebt | 34 | (6) | 56 |
| Undistributed\tgain\tfrom\tsale\tof\tequity\tmethod\tinvestment | (106) | — | — |
| Noncontrolling\tinterest\tof\tdiscontinued\toperations | — | — | (4) |
| Other | (31) | (99) | 127 |
| Changes\tin\toperating\tassets\tand\tliabilities: |  |  |  |
| (Increase)\tdecrease\tin\taccounts\treceivable | (98) | 62 | (451) |
| (Increase)\tdecrease\tin\tinventory | 10 | (34) | (83) |
| (Increase)\tdecrease\tin\tprepaid\texpenses\tand\tother\tcurrent\tassets | 430 | 138 | (62) |
| (Increase)\tdecrease\tin\tother\tassets | (248) | (177) | (467) |
| Increase\t(decrease)\tin\taccounts\tpayable\tand\taccrued\tliabilities | 136 | (308) | 260 |
| Increase\t(decrease)\tin\tincome\ttaxes\tand\tother\tincome\ttax\tpayables,\tnet | 166 | 88 | 226 |
| Increase\t(decrease)\tin\tother\tliabilities | 257 | (366) | 32 |
| Net\tcash\tprovided\tby\toperating\tactivities | 3,510 | 2,202 | 2,160 |
| INVESTING\tACTIVITIES: |  |  |  |
| Capital\texpenditures | (2,310) | (2,520) | (2,850) |
| Acquisitions—net\tof\tcash\tacquired | (254) | — | (1,135) |
| Proceeds\tfrom\tthe\tsale\tof\tbusinesses | 595 | 2 | 1,328 |
| Proceeds\tfrom\tthe\tsale\tof\tassets | 23 | 17 | 105 |
| Sale\tof\tshort-term\tinvestments | 5,786 | 4,526 | 5,150 |
| Purchase\tof\tshort-term\tinvestments | (5,795) | (4,248) | (5,469) |
| (Increase)\tdecrease\tin\trestricted\tcash | (104) | 302 | (295) |
| (Increase)\tdecrease\tin\tdebt\tservice\treserves\tand\tother\tassets | (56) | 185 | (100) |
| Affiliate\tadvances\tand\tequity\tinvestments | (97) | (155) | (240) |
| Proceeds\tfrom\tloan\trepayments | 132 | — | — |
| Loan\tadvances | — | — | (173) |
| Other\tinvesting | 40 | (26) | 98 |
| Net\tcash\tused\tin\tinvesting\tactivities | (2,040) | (1,917) | (3,581) |
| FINANCING\tACTIVITIES: |  |  |  |
| Issuance\tof\tcommon\tstock | 1,567 | — | — |
| Borrowings\t(repayments)\tunder\tthe\trevolving\tcredit\tfacilities,\tnet | 78 | 11 | 298 |
| Issuance\tof\trecourse\tdebt | — | 503 | 625 |
| Issuance\tof\tnon-recourse\tdebt | 1,940 | 1,997 | 2,158 |
| Repayments\tof\trecourse\tdebt | (914) | (154) | (1,037) |
| Repayments\tof\tnon-recourse\tdebt | (1,945) | (1,008) | (1,260) |
| Payments\tfor\tdeferred\tfinancing\tcosts | (61) | (91) | (82) |
| Distributions\tto\tnoncontrolling\tinterests | (1,245) | (846) | (597) |
| Contributions\tfrom\tnoncontrolling\tinterests | — | 190 | 410 |
| Financed\tcapital\texpenditures | (23) | (18) | (47) |
| Purchase\tof\ttreasury\tstock | (99) | — | (143) |
| Other\tfinancing | (4) | 26 | 37 |
| Net\tcash\t(used\tin)\tprovided\tby\tfinancing\tactivities | (706) | 610 | 362 |
| Effect\tof\texchange\trate\tchanges\ton\tcash | 8 | 22 | (96) |
| Total\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | 772 | 917 | (1,155) |
| Cash\tand\tcash\tequivalents,\tbeginning | 1,782 | 865 | 2,020 |
| Cash\tand\tcash\tequivalents,\tending | $ 2,554 | $ 1,782 | $865 |
| SUPPLEMENTAL\tDISCLOSURES: |  |  |  |
| Cash\tpayments\tfor\tinterest,\tnet\tof\tamounts\tcapitalized | $ 1,462 | $ 1,395 | $ 1,615 |
| Cash\tpayments\tfor\tincome\ttaxes,\tnet\tof\trefunds | $698 | $484 | $465 |
| SCHEDULE\tOF\tNONCASH\tINVESTING\tAND\tFINANCING\tACTIVITIES: |  |  |  |
| Assets\tacquired\tin\tacquisition\tof\tsubsidiary | $— | $— | $ 1,097 |
| Liabilities\tassumed\tin\tacquisition\tof\tsubsidiary | $— | $— | $49 |
| Assets\tacquired\tin\tnoncash\tasset\texchange | $42 | $111 | $18 |
| Assets\tdisposed\tof\tin\tnoncash\tasset\texchange | $— | $— | $4 |

# CONSOLIDATED	STATEMENTS	OF	CHANGES	IN	STOCKHOLDERS'	EQUITY

|  | Common	Stock | Common	Stock | Treasury	Stock | Treasury	Stock |  | Retained | Accumulated |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Shares | Amount | Shares | Amount | Additional\nPaid-In\nCapital | Earnings\n(Accumulated\nDeficit) | Other\nComprehensive\nLoss | Noncontrolling\nInterests | Consolidated\nComprehensive\nIncome |
|  |  |  |  |  |  | (in\tmillions) |  |  |  |
| Balance\tat\tJanuary\t1,\t2008 | 670.3 | $7 | — | $— | $6,776 | $(1,241) | $(2,378) | $3,181 |  |
| Net\tincome | — | — | — | — | — | 1,234 | — | 798 | $2,032 |
| Foreign\tcurrency\ttranslation\tadjustment,\tnet\tof\tincome\ttax | — | — | — | — | — | — | (560) | (492) | (1,052) |
| Change\tin\tunfunded\tpensions\tobligation,\tnet\tof\tincome\ttax | — | — | — | — | — | — | (49) | (100) | (149) |
| Change\tin\tderivative\tfair\tvalue,\tincluding\ta\treclassification\tto\tearnings, |  |  |  |  |  |  |  |  |  |
| net\tof\tincome\ttax | — | — | — | — | — | — | (31) | (37) | (68) |
| Other\tcomprehensive\tincome |  |  |  |  |  |  |  |  | (1,269) |
| Total\tcomprehensive\tincome |  |  |  |  |  |  |  |  | $763 |
| Capital\tcontributions\tfrom\tnoncontrolling\tinterests | — | — | — | — | — | — | — | 619 |  |
| Dividends\tdeclared\tto\tnoncontrolling\tinterests | — | — | — | — | — | — | — | (574) |  |
| Disposition\tof\tbusinesses | — | — | — | — | — | — | — | (37) |  |
| Effect\tof\tpension\tmeasurement\tdate\tchange | — | — | — | — | — | (1) | — | — |  |
| Acquisition\tof\ttreasury\tstock | — | — | 10.7 | (144) | — | — | — | — |  |
| Issuance\tof\tcommon\tstock\tunder\tbenefit\tplans\tand\texercise\tof\tstock |  |  |  |  |  |  |  |  |  |
| options\tand\twarrants,\tnet\tof\tincome\ttax | 3.2 | — | — | — | 30 | — | — | — |  |
| Stock\tcompensation | — | — | — | — | 26 | — | — | — |  |
| Balance\tat\tDecember\t31,\t2008 | 673.5 | $7 | 10.7 | $(144) | $6,832 | $(8) | $(3,018) | $3,358 |  |
| Net\tincome | — | — | — | — | — | 658 | — | 1,097 | $1,755 |
| Change\tin\tfair\tvalue\tof\tavailable-for-sale\tsecurities,\tnet\tof\tincome\ttax | — | — | — | — | — | — | 6 | — | 6 |
| Foreign\tcurrency\ttranslation\tadjustment,\tnet\tof\tincome\ttax | — | — | — | — | — | — | 271 | 471 | 742 |
| Change\tin\tunfunded\tpensions\tobligation,\tnet\tof\tincome\ttax | — | — | — | — | — | — | (23) | (116) | (139) |
| Change\tin\tderivative\tfair\tvalue,\tincluding\ta\treclassification\tto\tearnings, |  |  |  |  |  |  |  |  |  |
| net\tof\tincome\ttax | — | — | — | — | — | — | 40 | 33 | 73 |
| Other\tcomprehensive\tincome |  |  |  |  |  |  |  |  | 682 |
| Total\tcomprehensive\tincome |  |  |  |  |  |  |  |  | $2,437 |
| Capital\tcontributions\tfrom\tnoncontrolling\tinterests | — | — | — | — | — | — | — | 195 |  |
| Dividends\tdeclared\tto\tnoncontrolling\tinterests | — | — | — | — | — | — | — | (825) |  |
| Disposition\tof\tbusinesses | — | — | — | — | — | — | — | (8) |  |
| Issuance\tof\ttreasury\tstock | — | — | (1.2) | 18 | (20) | — | — | — |  |
| Issuance\tof\tcommon\tstock\tunder\tbenefit\tplans\tand\texercise\tof\tstock |  |  |  |  |  |  |  |  |  |
| options\tand\twarrants,\tnet\tof\tincome\ttax |  |  |  |  |  |  |  |  |  |
|  | 3.7 | — | — | — | 18 | — | — | — |  |
| Stock\tcompensation | — | — | — | — | 38 | — | — | — |  |
| Balance\tat\tDecember\t31,\t2009 | 677.2 | $7 | 9.5 | $(126) | $6,868 | $650 | $(2,724) | $4,205 |  |
| Net\tincome | — | — | — | — | — | 9 | — | 1,050 | $1,059 |
| Change\tin\tfair\tvalue\tof\tavailable-for-sale\tsecurities,\tnet\tof\tincome\ttax | — | — | — | — | — | — | (5) | — | (5) |
| Foreign\tcurrency\ttranslation\tadjustment,\tnet\tof\tincome\ttax | — | — | — | — | — | — | 383 | 85 | 468 |
| Change\tin\tunfunded\tpensions\tobligation,\tnet\tof\tincome\ttax | — | — | — | — | — | — | (22) | (66) | (88) |
| Change\tin\tderivative\tfair\tvalue,\tincluding\ta\treclassification\tto\tearnings, |  |  |  |  |  |  |  |  |  |
| net\tof\tincome\ttax | — | — | — | — | — | — | (120) | (31) | (151) |
| Other\tcomprehensive\tincome |  |  |  |  |  |  |  |  | 224 |
| Total\tcomprehensive\tincome |  |  |  |  |  |  |  |  | $1,283 |
| Cumulative\teffect\tof\tconsolidation\tof\tentities\tunder\tvariable\tinterest |  |  |  |  |  |  |  |  |  |
| entity\taccounting\tguidance | — | — | — | — | — | (47) | (38) | 15 |  |
| Cumulative\teffect\tof\tdeconsolidation\tof\tentities\tunder\tvariable\tinterest |  |  |  |  |  |  |  |  |  |
| entity\taccounting\tguidance | — | — | — | — | — | 1 | — | — |  |
| Capital\tcontributions\tfrom\tnoncontrolling\tinterests | — | — | — | — | — | — | — | 35 |  |
| Dividends\tdeclared\tto\tnoncontrolling\tinterests | — | — | — | — | — | — | — | (1,220) |  |
| Disposition\tof\tbusinesses | — | — | — | — | — | — | 143 | (138) |  |
| Acquisition\tof\ttreasury\tstock | — | — | 8.4 | (99) | — | — | — | — |  |
| Issuance\tof\tcommon\tstock | 125.5 | 1 | — | — | 1,566 | — | — | — |  |
| Issuance\tof\tcommon\tstock\tunder\tbenefit\tplans\tand\texercise\tof\tstock |  |  |  |  |  |  |  |  |  |
| options\tand\twarrants,\tnet\tof\tincome\ttax | 2.2 | — | (0.6) | 9 | 9 | — | — | — |  |
| Stock\tcompensation | — | — | — | — | 26 | — | — | — |  |
| Changes\tin\tthe\tcarrying\tamount\tof\tredeemable\tstock\tof\tsubsidiaries | — | — | — | — | — | 7 | — | — |  |
| Acquisition\tof\tsubsidiary\tshares\tfrom\tnoncontrolling\tinterests | — | — | — | — | (25) | — | — | 5 |  |
| Balance\tat\tDecember\t31,\t2010 | 804.9 | $8 | 17.3 | $(216) | $8,444 | $620 | $(2,383) | $3,940 |  |

# NOTES	TO	CONSOLIDATED	FINANCIAL	STATEMENTS

# 1.	GENERAL	AND	SUMMARY	OF	SIGNIFICANT	ACCOUNTING	POLICIES

The	AES	Corporation	is	a	holding	company	(the	"Parent	Company")	that	through	its	subsidiaries	and	affiliates,	(collectively,	"AES"	or	"the	Company")	operates a	geographically	diversified	portfolio	of	electricity	generation	and	distribution	businesses.	Generally,	given	this	holding	company	structure,	the	liabilities	of	the individual	operating	entities	are	not	recourse	to	the	parent	and	are	isolated	to	the	operating	entities.	Most	of	our	operating	entities	are	structured	as	corporations,	therefore limiting	the	liability	of	the	shareholders.	The	structure	is	generally	the	same	regardless	of	whether	a	subsidiary	is	consolidated	under	a	voting	or	variable	interest	model.

PRINCIPLES	OF	CONSOLIDATION—The	Consolidated	Financial	Statements	of	the	Company	include	the	accounts	of	The	AES	Corporation,	its	subsidiaries and	controlled	affiliates,	and	variable	interest	entities	("VIEs")	of	which	the	Company	is	the	primary	beneficiary.	All	intercompany	transactions	and	balances	have	been eliminated	in	consolidation.

A	VIE	is	an	entity	(a)	that	has	a	total	equity	investment	at	risk	that	is	not	sufficient	to	finance	its	activities	without	additional	subordinated	financial	support	or (b)	where	the	group	of	equity	holders	does	not	have	(i)	the	ability	to	make	significant	decisions	about	the	entity's	activities,	(ii)	the	obligation	to	absorb	the	entity's expected	losses	or	(iii)	the	right	to	receive	the	entity's	expected	residual	returns	or	(c)	where	the	voting	rights	of	some	equity	holders	are	not	proportional	to	their obligations	to	absorb	expected	losses,	receive	expected	residual	returns,	or	both,	and	substantially	all	of	the	entity's	activities	either	involve	or	are	conducted	on	behalf	of an	investor	that	has	disproportionately	few	voting	rights.

Effective	January	1,	2010,	the	Company	prospectively	adopted	the	new	accounting	guidance	on	the	consolidation	of	VIEs.	The	new	guidance	requires	an	entity	to determine	qualitatively,	rather	than	quantitatively,	the	primary	beneficiary	of	a	VIE.	This	determination	is	based	on	whether	the	entity	has	the	power	to	direct	the activities	that	most	significantly	impact	the	economic	performance	of	the	VIE	and	the	obligation	to	absorb	losses	or	the	right	to	receive	benefits	of	the	VIE	that	could potentially	be	significant	to	the	VIE.	Other	key	changes	include:	a	requirement	for	the	ongoing	reconsideration	of	the	primary	beneficiary,	the	criteria	used	for determining	whether	service	provider	or	decision	maker	contracts	are	variable	interests,	the	consideration	of	kick-out	and	removal	rights	in	determining	whether	an entity	is	a	VIE,	the	types	of	events	that	trigger	the	reassessment	of	whether	an	entity	is	a	VIE	and	expansion	of	the	disclosures	previously	required.

The	determination	of	which	party	has	the	power	to	direct	the	activities	that	most	significantly	impact	the	economic	performance	of	the	VIE	could	require significant	judgment	and	assumptions.	That	determination	considers	the	purpose	and	design	of	the	business,	the	risks	that	the	business	was	designed	to	create	and	pass along	to	other	entities,	the	activities	of	the	business	that	can	be	directed	and	which	party	can	direct	them,	and	the	expected	relative	impact	of	those	activities	on	the economic	performance	of	the	business	through	its	life.	The	businesses	for	which	significant	judgment	and	assumptions	were	required	were	primarily	certain	generation businesses	who	have	power	purchase	agreements	("PPAs")	to	sell	energy	exclusively	or	primarily	to	a	single	counterparty	for	the	term	of	those	agreements.	For	these generation	businesses,	the	counterparty	has	the	power	to	dispatch	energy	and,	in	some	instances,	to	make	decisions	regarding	the	sale	of	excess	energy.	As	such,	the counterparty	has	the	power	to	direct	certain	activities	that	significantly	impact	the	economic	performance	of	the	business	primarily	through	the	cash	flows	and	gross margin,	if	any,	earned	by	the	business	from	the	sale	of	energy	to	the	counterparty	and	sometimes	through	the	counterparty's	absorption	of	fuel	price	risk.	However,	the counterparty	usually	does	not	have	the	power	to	direct	any	of	the	other	activities	that	could	significantly	impact	the	economic	performance.	These	other	activities include:	daily	operation	and	management,	maintenance,	repairs	and	capital	expenditures,	plant	expansion,	decisions	regarding	the	overall	financing	of	ongoing operations	and	budgets	and,	in	some	instances,	decisions	regarding	the	sale	of	excess	energy.	As	such,	AES	has	the	power	to

# NOTES	TO	CONSOLIDATED	FINANCIAL	STATEMENTS—(Continued)

direct	some	activities	of	the	business	that	significantly	impact	its	economic	performance,	primarily	through	the	cash	flows	and	gross	margin	earned	from	capacity payments	received	from	being	available	to	produce	energy	and	from	the	sale	of	energy	to	other	entities	(particularly	during	any	period	beyond	the	end	of	the	power purchase	agreement).	For	these	businesses,	the	determination	as	to	which	set	of	activities	most	significantly	impact	the	economic	performance	of	the	business	requires significant	judgment	and	the	use	of	assumptions.	The	Company	concluded	that	the	activities	directed	by	the	counterparty	were	less	significant	than	those	directed	by AES.

The	adoption	of	the	new	accounting	guidance	on	the	consolidation	of	VIEs	resulted	in	the	deconsolidation	of	certain	immaterial	VIEs	previously	consolidated. Additionally,	assets,	liabilities	and	operating	results	of	two	of	the	Company's	VIEs,	previously	accounted	for	under	the	equity	method	of	accounting,	were	required	to	be consolidated.	Cartagena,	a	71%	owned	generation	business	in	Spain,	and	Cili,	a	51%	owned	generation	business	in	China,	were	consolidated	under	the	new	guidance. This	resulted	in	a	cumulative	effect	adjustment	of	$47	million	to	retained	earnings	as	of	January	1,	2010.	The	cumulative	effect	adjustment	is	primarily	comprised	of losses	that	were	not	recognized	while	the	equity	method	of	accounting	was	suspended	for	Cartagena.	The	equity	method	of	accounting	was	suspended	in	December	2008 when	the	Company's	basis	in	its	investment	in	Cartagena	was	reduced	to	zero.	As	of	December	31,	2010,	total	assets	and	total	liabilities	related	to	these	VIEs	were	$850 million	and	$919	million,	respectively.	In	addition,	revenue	for	the	year	ended	December	31,	2010	included	$416	million	of	revenue	from	these	VIEs.	Prior	period operating	results	of	these	VIEs	are	reflected	in	"Net	equity	in	earnings	of	affiliates"	except	for	those	prior	periods	during	which	the	equity	method	of	accounting	was suspended.

USE	OF	ESTIMATES—The	preparation	of	these	consolidated	financial	statements	in	conformity	with	accounting	principles	generally	accepted	in	the	United States	of	America	("U.S.	GAAP")	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	consolidated	financial	statements,	as	well	as	the	reported	amounts	of	revenue	and	expenses	during	the	reporting	period. Actual	results	could	differ	from	those	estimates.	Items	subject	to	such	estimates	and	assumptions	include:	the	carrying	value	and	estimated	useful	lives	of	long-lived assets;	impairment	of	goodwill,	long-lived	assets	and	equity	method	investments;	valuation	allowances	for	receivables	and	deferred	tax	assets;	the	recoverability	of deferred	regulatory	assets;	the	valuation	of	certain	financial	instruments;	the	determination	of	noncontrolling	interest	using	the	hypothetical	liquidation	at	book	value ("HLBV")	method	for	certain	wind	generation	partnerships;	pension	liabilities;	environmental	liabilities;	and	potential	litigation	claims	and	settlements.

DISCONTINUED	OPERATIONS	AND	RECLASSIFICATIONS—A	discontinued	operation	is	a	component	of	the	Company	that	either	has	been	disposed	of or	is	classified	as	held	for	sale.	A	component	of	the	Company	comprises	operations	and	cash	flows	that	can	be	clearly	distinguished,	operationally	and	for	financial reporting	purposes,	from	the	rest	of	the	Company.	In	accordance	with	the	accounting	standards	on	the	impairment	or	disposal	of	long-lived	assets,	the	prior	period Consolidated	Financial	Statements	in	this	Form	10-K	have	been	restated	to	reflect	the	businesses	determined	to	be	discontinued	operations,	as	further	discussed	in	Note 21—Discontinued	Operations	and	Held	for	Sale	Businesses.	The	Company	has	reclassified	certain	of	its	trade	related	payables	from	accrued	and	other	liabilities	to accounts	payable	within	the	Consolidated	Financial	Statements	to	conform	to	current	year	presentation.

FAIR	VALUE—Fair	value,	as	defined	in	the	fair	value	measurement	accounting	guidance,	is	the	price	that	would	be	received	to	sell	an	asset	or	paid	to	transfer	a liability	in	an	orderly	transaction	between	market	participants	at	the	measurement	date,	or	exit	price.	The	Company	applies	the	fair	value	measurement	accounting guidance	for	financial	assets	and	liabilities	to	determine	the	fair	value	of	short	and	long	term	investments	in	marketable	debt	and	equity	securities,	included	in	the consolidated	balance	sheet	line	items	"Short-term	investments"	and	"Other	assets	(noncurrent),"	derivative	assets,	included	in	"Other	current	assets"	and	"Other

assets	(noncurrent)"	and	derivative	liabilities,	included	in	"Accrued	and	other	liabilities	(current)"	and	"Other	long-term	liabilities."	The	Company	applies	the	fair	value measurement	guidance	for	nonfinancial	assets	upon	the	acquisition	of	a	business	in	accordance	with	the	accounting	guidance	for	business	combinations	or	in	conjunction with	the	measurement	of	an	impairment	loss	on	an	asset	group	or	reporting	unit	under	the	accounting	guidance	for	the	impairment	of	long-lived	assets	or	goodwill.

The	fair	value	measurement	accounting	guidance	requires	that	the	Company	make	assumptions	that	market	participants	would	use	in	pricing	an	asset	or	liability based	on	the	best	information	available.	These	factors	include	nonperformance	risk	(the	risk	that	the	obligation	will	not	be	fulfilled)	and	credit	risk	of	the	reporting	entity (for	liabilities)	and	of	the	counterparty	(for	assets).	The	fair	value	measurement	guidance	prohibits	the	inclusion	of	transaction	costs	and	any	adjustments	for	blockage factors	in	determining	the	instruments'	fair	value.	The	principal	or	most	advantageous	market	should	be	considered	from	the	perspective	of	the	reporting	entity.

Fair	value,	where	available,	is	based	on	observable	quoted	market	prices.	Where	observable	prices	or	inputs	are	not	available,	several	valuation	models	and techniques	are	applied.	These	models	and	techniques	attempt	to	maximize	the	use	of	observable	inputs	and	minimize	the	use	of	unobservable	inputs.	The	process involves	varying	levels	of	management	judgment,	the	degree	of	which	is	dependent	on	the	price	transparency	of	the	instruments	or	market	and	the	instruments' complexity.

To	increase	consistency	and	enhance	disclosure	of	the	fair	value	of	financial	instruments,	the	fair	value	measurement	accounting	guidance	creates	a	fair	value hierarchy	to	prioritize	the	inputs	used	to	measure	fair	value	into	three	categories.	An	asset	or	liability's	level	within	the	fair	value	hierarchy	is	based	on	the	lowest	level	of input	significant	to	the	fair	value	measurement,	where	Level	1	is	the	highest	and	Level	3	is	the	lowest.	The	three	levels	are	defined	as	follows:

Level	1—unadjusted	quoted	prices	in	active	markets	accessible	by	the	reporting	entity	for	identical	assets	or	liabilities.	Active	markets	are	those	in	which transactions	for	the	asset	or	liability	occur	with	sufficient	frequency	and	volume	to	provide	pricing	information	on	an	ongoing	basis.

Level	2—pricing	inputs	other	than	quoted	market	prices	included	in	Level	1	which	are	based	on	observable	market	data,	that	are	directly	or	indirectly	observable for	substantially	the	full	term	of	the	asset	or	liability.	These	include	quoted	market	prices	for	similar	assets	or	liabilities,	quoted	market	prices	for	identical	or	similar assets	in	markets	that	are	not	active,	adjusted	quoted	market	prices,	inputs	from	observable	data	such	as	interest	rate	and	yield	curves,	volatilities	or	default	rates observable	at	commonly	quoted	intervals	or	inputs	derived	from	observable	market	data	by	correlation	or	other	means.	The	fair	value	of	most	over-the-counter derivatives	derived	from	internal	valuation	models	using	market	inputs	and	most	investments	in	marketable	debt	securities	qualify	as	Level	2.

Level	3—pricing	inputs	that	are	unobservable,	or	less	observable,	from	objective	sources.	Unobservable	inputs	are	only	used	to	the	extent	observable	inputs	are not	available.	These	inputs	maintain	the	concept	of	an	exit	price	from	the	perspective	of	a	market	participant	and	should	reflect	assumptions	of	other	market	participants. An	entity	should	consider	all	market	participant	assumptions	that	are	available	without	unreasonable	cost	and	effort.	These	are	given	the	lowest	priority	and	are	generally used	in	internally	developed	methodologies	to	generate	management's	best	estimate	of	the	fair	value	when	no	observable	market	data	is	available.	The	fair	value	of	the Company's	reporting	units	determined	using	a	discounted	cash	flows	valuation	model	for	goodwill	impairment	assessment	and	the	fair	value	of	the	Company's	long- lived	asset	groups	determined	using	a	discounted	cash	flows	valuation	model	for	the	long-lived	asset	impairment	assessments	qualify	as	Level	3.

Any	transfers	between	the	fair	value	hierarchy	levels	are	recognized	at	the	end	of	the	reporting	period.

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	or	remaining	maturity	at	the	date	of	acquisition	of	three	months	or	less,	to	be	cash	and	cash	equivalents.	The	carrying	amount	of	such balances	approximate	fair	value.

RESTRICTED	CASH—Restricted	cash	includes	cash	and	cash	equivalents	which	are	restricted	as	to	withdrawal	or	usage.	The	nature	of	restrictions	includes restrictions	imposed	by	financing	agreements	such	as	security	deposits	kept	as	collateral,	debt	service	reserves,	maintenance	reserves	and	others,	as	well	as	restrictions imposed	by	long-term	PPAs.

INVESTMENTS	IN	MARKETABLE	SECURITIES—Short-term	investments	in	marketable	debt	and	equity	securities	consist	of	securities	with	original	or remaining	maturities	in	excess	of	three	months	but	less	than	one	year.	The	Company's	marketable	investments	are	primarily	certificates	of	deposit,	government	debt securities	and	money	market	funds.

Marketable	debt	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 amortized	cost.	Other	marketable	securities	that	the	Company	does	not	intend	to	hold	to	maturity	are	classified	as	available-for-sale	or	trading	and	are	carried	at	fair value.	Available-for-sale	investments	are	marked-to-market	at	the	end	of	each	reporting	period,	with	unrealized	holding	gains	or	losses,	which	represent	changes	in	the market	value	of	the	investment,	reflected	in	accumulated	other	comprehensive	income	("AOCI"),	a	separate	component	of	stockholders'	equity.	In	measuring	the	other- than-temporary	impairment	of	debt	securities,	the	Company	identifies	two	components:	1)	the	amount	representing	the	credit	loss,	which	is	recognized	as	"other	non- operating	expense"	in	the	Consolidated	Statements	of	Operations;	and	2)	the	amount	related	to	other	factors,	which	is	recognized	in	AOCI	unless	there	is	a	plan	to	sell the	security,	in	which	case	it	would	be	recognized	in	earnings.	The	amount	recognized	in	AOCI	for	held-to-maturity	debt	securities	is	then	amortized	over	the	remaining life	of	the	security.

Investments	classified	as	trading	are	marked-to-market	on	a	periodic	basis	through	the	Consolidated	Statements	of	Operations.	Interest	and	dividends	on investments	are	reported	in	interest	income	and	other	income,	respectively.	Gains	and	losses	on	sales	of	investments	are	determined	using	the	specific	identification method.

See	Note	4—Fair	Value	and	the	Company's	fair	value	policy	for	additional	discussion	regarding	the	determination	of	the	fair	value	of	the	Company's	investments in	marketable	debt	and	equity	securities.

ACCOUNTS	AND	NOTES	RECEIVABLE	AND	ALLOWANCE	FOR	DOUBTFUL	ACCOUNTS—Accounts	and	Notes	receivable	are	carried	at	amortized cost.	The	Company	periodically	assesses	the	collectability	of	accounts	receivable	considering	factors	such	as	specific	evaluation	of	collectability,	historical	collection experience,	the	age	of	accounts	receivable	and	other	currently	available	evidence	of	the	collectability,	and	records	an	allowance	for	doubtful	accounts	for	the	estimated uncollectable	amount	as	appropriate.	Certain	of	our	businesses	charge	interest	on	accounts	receivable	either	under	contractual	terms	or	where	charging	interest	is	a customary	business	practice.	In	such	cases,	interest	income	is	recognized	on	an	accrual	basis.	In	situations	where	the	collection	of	interest	is	uncertain,	interest	income	is recognized	as	cash	is	received.	Individual	accounts	and	notes	receivable	are	written	off	when	they	are	no	longer	deemed	collectible.	Included	in	"Noncurrent	Other Assets"	are	long-term	financing	receivables	of	$151	million,	primarily	with	certain	Latin	American	governmental

bodies.	These	receivables	have	contractual	maturities	of	greater	than	one	year	and	are	being	collected	in	installments.	Of	the	total	$151	million,	amounts	of	$81	million and	$55	million,	respectively,	relate	to	our	businesses	in	Argentina	and	the	Dominican	Republic.	The	remaining	amount	relates	to	our	distribution	businesses	in	Brazil.

INVENTORY—Inventory	primarily	consists	of	coal,	fuel	oil	and	other	raw	materials	used	to	generate	power,	and	spare	parts	and	supplies	used	to	maintain power	generation	and	distribution	facilities.	Inventory	is	carried	at	lower	of	cost	or	market.	Cost	is	the	sum	of	the	purchase	price	and	incidental	expenditures	and	charges incurred	to	bring	the	inventory	to	its	existing	condition	or	location.	Cost	is	determined	under	the	first-in,	first-out	("FIFO"),	average	cost	or	specific	identification method.	Generally,	cost	is	reduced	to	market	value	if	the	market	value	of	inventory	has	declined	and	it	is	probable	that	the	utility	of	inventory,	in	its	disposal	in	the ordinary	course	of	business,	will	not	be	recovered	through	revenue	earned	from	the	generation	of	power.

LONG-LIVED	ASSETS—Long-lived	assets	include	property,	plant	and	equipment,	assets	under	capital	leases	and	intangible	assets	subject	to	amortization	(i.e., finite-lived	intangible	assets).

# Property,	plant	and	equipment

Property,	plant	and	equipment	are	stated	at	cost,	net	of	accumulated	depreciation.	The	cost	of	renewals	and	improvements	that	extend	the	useful	life	of	property, plant	and	equipment	are	capitalized.

Construction	progress	payments,	engineering	costs,	insurance	costs,	salaries,	interest	and	other	costs	directly	relating	to	construction	in	progress	are	capitalized during	the	construction	period,	provided	the	completion	of	the	project	is	deemed	probable,	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,	site	identification,	financing,	construction	permitting	and	contract	compliance.	Construction	in	progress	balances	are	transferred	to	electric generation	and	distribution	assets	when	an	asset	group	is	ready	for	its	intended	use.	Government	subsidies	are	recorded	as	a	reduction	to	property,	plant	and	equipment and	reflected	in	cash	flows	from	investing	activities.

Depreciation,	after	consideration	of	salvage	value	and	asset	retirement	obligations,	is	computed	primarily	using	the	straight-line	method	over	the	estimated	useful lives	of	the	assets,	which	are	determined	on	a	composite	or	component	basis.	Maintenance	and	repairs	are	charged	to	expense	as	incurred.	Capital	spare	parts,	including rotable	spare	parts,	are	included	in	electric	generation	and	distribution	assets.	If	the	spare	part	is	considered	a	component,	it	is	depreciated	over	its	useful	life	after	the part	is	placed	in	service.	If	the	spare	part	is	deemed	part	of	a	composite	asset,	the	part	is	depreciated	over	the	composite	useful	life	even	when	being	held	as	a	spare	part.

# Intangible	Assets	Subject	to	Amortization

Finite-lived	intangible	assets	are	amortized	over	their	useful	lives	which	range	from	1-	89	years.	The	Company	accounts	for	purchased	emission	allowances	as intangible	assets	and	records	an	expense	when	utilized	or	sold.	Granted	allowances	are	valued	at	zero.

# Impairment	of	Long-lived	Assets

The	Company	evaluates	the	impairment	of	long-lived	assets	(asset	group)	using	internal	projections	of	undiscounted	cash	flows	when	circumstances	indicate	that the	carrying	amount	of	such	assets	may	not	be	recoverable	or	the	assets	meet	the	held	for	sale	criteria	under	the	relevant	accounting	standards.	Events	or

changes	in	circumstances	that	may	necessitate	a	recoverability	evaluation	may	include	but	are	not	limited	to:	changes	to	or	the	passage	of	new	legislation,	changes	in	the relative	pricing	of	wholesale	electricity,	anticipated	demand	and/or	cost	of	fuel.	The	carrying	amount	of	a	long-lived	asset	(asset	group)	may	not	be	recoverable	if	it exceeds	the	sum	of	undiscounted	cash	flows	expected	to	result	from	the	use	and	eventual	disposal	of	the	asset	(asset	group).	In	such	cases,	fair	value	of	the	long-lived asset	(asset	group)	is	determined	in	accordance	with	the	fair	value	measurement	accounting	guidance.	The	excess	of	carrying	amount	over	fair	value,	if	any,	is recognized	as	an	impairment	expense.	For	regulated	assets,	an	impairment	expense	could	be	reduced	by	the	establishment	of	a	regulatory	asset,	if	recovery	through approved	rates	was	probable.	For	non-regulated	assets,	impairment	is	recognized	as	an	expense	against	earnings.

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.	Make-whole	payments	in	connection	with	early	debt	retirements	are	classified as	cash	flows	used	in	investing	activities.

EQUITY	METHOD	INVESTMENTS—Investments	in	entities	over	which	the	Company	has	the	ability	to	exercise	significant	influence,	but	not	control,	are accounted	for	using	the	equity	method	of	accounting	and	reported	in	"Investments	in	and	advances	to	affiliates"	on	the	Consolidated	Balance	Sheets.	In	accordance	with the	accounting	guidance	for	equity	method	investments,	the	Company	periodically	assesses	the	recoverability	of	its	equity	method	investments.	If	an	identified	event	or change	in	circumstances	requires	an	impairment	evaluation,	management	assesses	the	fair	value	based	on	valuation	methodologies,	including	discounted	cash	flows, estimates	of	sale	proceeds	and	external	appraisals,	as	appropriate.	The	difference	between	the	carrying	amount	of	the	equity	method	investment	and	its	estimated	fair value	is	recognized	as	impairment	when	the	loss	in	value	is	deemed	other-than-temporary	and	included	in	"Other	non-operating	expense"	on	the	Consolidated	Statements of	Operations.

In	accordance	with	the	accounting	standards	for	equity	method	investments,	the	Company	discontinues	the	application	of	the	equity	method	when	an	investment is	reduced	to	zero	and	the	Company	is	not	otherwise	committed	to	provide	further	financial	support	to	the	investee.	The	Company	resumes	the	application	of	the	equity method	if	the	investee	subsequently	reports	net	income	to	the	extent	that	the	Company's	share	of	such	net	income	equals	the	share	of	net	losses	not	recognized	during	the period	in	which	the	equity	method	of	accounting	was	suspended.

GOODWILL	AND	INDEFINITE-LIVED	INTANGIBLE	ASSETS—In	accordance	with	the	accounting	guidance	on	goodwill	and	other	intangible	assets,	the Company	recognizes	goodwill	as	an	asset	representing	the	future	economic	benefits	arising	from	other	assets	acquired	in	a	business	combination	that	are	not	individually identified	and	separately	recognized.	The	Company	evaluates	goodwill	and	indefinite-lived	intangible	assets	for	impairment	on	an	annual	basis	and	whenever	events	or changes	in	circumstances	necessitate	an	evaluation	for	impairment.	The	Company's	annual	impairment	testing	date	is	October	1 . st

# Goodwill:

The	Company	evaluates	goodwill	impairment	at	the	reporting	unit	level,	which	is	an	operating	segment,	as	defined	in	the	segment	reporting	accounting	guidance, or	one	level	below	an	operating	segment,	a	component.	In	determining	its	reporting	units,	the	Company	starts	with	its	segment	reporting	structure.	Operating	segments are	identified	and	then	analyzed	to	identify	components	(usually	businesses)	which	make	up	these	operating	segments.	Two	or	more	components	are	combined	into	a single	reporting	unit	if	they	share	the	economic	similarity	criteria	prescribed	by	the	accounting	guidance.	Assets	and	liabilities	are	allocated	to	a	reporting	unit	if 178

the	assets	will	be	employed	by	or	a	liability	relates	to	the	operations	of	a	reporting	unit	or	would	be	considered	by	a	market	participant	in	determining	its	fair	value. Goodwill	resulting	from	an	acquisition	is	assigned	to	the	reporting	units	that	are	expected	to	benefit	from	the	synergies	of	the	acquisition.	Generally,	each	AES	business constitutes	a	reporting	unit.

Goodwill	impairment	evaluation	is	performed	in	two	steps.	In	Step	1,	the	carrying	amount	of	a	reporting	unit	is	compared	to	its	fair	value	and	if	the	fair	value exceeds	the	carrying	amount,	Step	2	is	unnecessary.	If	the	carrying	amount	exceeds	the	reporting	unit's	fair	value,	this	could	indicate	potential	impairment	and	Step	2	of the	goodwill	evaluation	process	is	required	to	determine	if	goodwill	is	impaired	and	to	measure	the	amount	of	impairment	loss	to	recognize,	if	any.	In	determining	the implied	fair	value	of	goodwill	for	impairment	measurement,	the	accounting	guidance	requires	measuring	all	assets	and	liabilities,	including	unrecognized	assets	and liabilities,	at	fair	value,	as	would	be	done	in	a	business	combination.	When	a	Step	2	analysis	is	required	to	be	completed,	the	fair	value	of	individual	assets	and	liabilities is	determined	using	valuations	(which	in	some	cases	may	be	based	in	part	on	third	party	valuation	reports),	or	other	observable	sources	of	fair	value,	as	appropriate.	An impairment	loss	is	recognized	to	the	extent	the	carrying	amount	of	goodwill	exceeds	its	implied	fair	value,	not	to	exceed	the	carrying	value	of	goodwill.

Most	of	the	Company's	reporting	units	are	not	publicly	traded.	Therefore,	the	Company	estimates	the	fair	value	of	its	reporting	units	under	the	fair	value measurement	accounting	guidance	which	requires	making	assumptions	that	a	market	participant	would	make	in	a	hypothetical	sale	transaction	at	the	testing	date.	The	fair value	of	a	reporting	unit	is	estimated	using	internal	budgets	and	forecasts,	adjusted	for	any	market	participants'	assumptions	and	discounted	at	the	rate	of	return	required by	a	market	participant.	The	Company	considers	both	market	and	income-based	approaches	to	determine	a	range	of	fair	value,	but	typically	concludes	that	the	value derived	using	an	income-based	approach	is	more	representative	of	fair	value	due	to	the	lack	of	direct	market	comparables.	The	Company	does	use	market	data	to corroborate	and	determine	the	reasonableness	of	the	fair	value	derived	from	the	income-based	discounted	cash	flow	analysis.

# Indefinite-lived	Intangible	Assets:

The	Company's	indefinite-lived	intangible	assets	include	items	such	as	land	use	rights,	easements,	and	concessions.	These	are	tested	for	impairment	on	an	annual basis	or	whenever	events	or	changes	in	circumstances	necessitate	an	evaluation	for	impairment	in	accordance	with	applicable	accounting	guidance	for	indefinite-lived intangible	assets.

INCOME	TAXES—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.	The	Company	establishes	a	valuation	allowance	when	it	is	more	likely	than not	that	all	or	a	portion	of	a	deferred	tax	asset	will	not	be	realized.	The	Company's	tax	positions	are	evaluated	under	a	more-likely-than-not	recognition	threshold	and measurement	analysis	before	they	are	recognized	for	financial	statement	reporting.

Uncertain	tax	positions	have	been	classified	as	noncurrent	income	tax	liabilities	unless	expected	to	be	paid	within	one	year.	The	Company's	policy	for	interest	and penalties	related	to	income	tax	exposures	is	to	recognize	interest	and	penalties	as	a	component	of	the	provision	for	income	taxes	in	the	Consolidated	Statements	of Operations.

PENSION	AND	OTHER	POSTRETIREMENT	PLANS—In	accordance	with	the	accounting	guidance	on	defined	benefit	pension	and	other	postretirement plans,	the	Company	recognizes	in	its	Consolidated	Balance	Sheets	an	asset	or	liability	reflecting	the	funded	status	of	pension	and	other	postretirement	plans	with	current year

changes	in	the	funded	status	recognized	in	AOCI.	All	plan	assets	are	recorded	at	fair	value.	AES	follows	the	measurement	date	provisions	of	the	accounting	guidance, which	require	a	year-end	measurement	date	of	plan	assets	and	obligations	for	all	defined	benefit	plans.

NONCONTROLLING	INTERESTS—In	accordance	with	the	accounting	guidance	on	noncontrolling	interests,	such	interests	are	classified	as	a	separate component	of	equity	in	the	Consolidated	Balance	Sheets	and	Statements	of	Changes	in	Equity.	Additionally,	net	income	and	comprehensive	income	attributable	to noncontrolling	interests	are	reflected	separately	from	consolidated	net	income	and	comprehensive	income	in	the	Consolidated	Statements	of	Operations	and	Statements of	Changes	in	Equity.	Any	change	in	ownership	of	a	subsidiary	while	the	controlling	financial	interest	is	retained	is	accounted	for	as	an	equity	transaction	between	the controlling	and	noncontrolling	interests.	Losses	continue	to	be	attributed	to	the	noncontrolling	interests,	even	when	the	noncontrolling	interests'	basis	has	been	reduced to	zero.

Although	in	general,	the	noncontrolling	ownership	interest	in	earnings	is	calculated	based	on	ownership	percentage,	certain	of	the	Company's	wind	businesses	use the	HLBV	method	in	consolidation.	HLBV	uses	a	balance	sheet	approach,	which	measures	the	Company's	equity	in	income	or	loss	by	calculating	the	change	in	the amount	of	net	worth	the	partners	are	legally	able	to	claim	based	on	a	hypothetical	liquidation	of	the	entity	at	the	beginning	of	a	reporting	period	compared	to	the	end	of that	period.	This	method	is	used	in	AES	Wind	Generation	partnerships	which	contain	agreements	designating	different	allocations	of	value	among	investors,	where	the allocations	change	in	form	or	percentage	over	the	life	of	the	partnership.

ACCOUNTS	PAYABLE	AND	OTHER	ACCRUED	LIABILITIES—Accounts	payable	consists	of	amounts	due	to	trade	creditors	related	to	the	Company's core	business	operations.	The	nature	of	these	payables	include	amounts	owed	to	vendors	and	suppliers	for	items	such	as	energy	purchased	for	resale,	fuel,	maintenance, inventory	and	other	raw	materials.	Other	accrued	liabilities	include	items	such	as	income	taxes,	regulatory	liabilities,	legal	contingencies	and	employee	related	costs including	payroll,	benefits	and	related	taxes.

ASSET	RETIREMENT	OBLIGATIONS—In	accordance	with	the	accounting	standards	for	asset	retirement	obligations,	the	Company	records	the	fair	value	of the	liability	for	a	legal	obligation	to	retire	an	asset	in	the	period	in	which	the	obligation	is	incurred.	When	a	new	liability	is	recognized,	the	Company	capitalizes	the	costs of	the	liability	by	increasing	the	carrying	amount	of	the	related	long-lived	asset.	The	liability	is	accreted	to	its	present	value	each	period	and	the	capitalized	cost	is depreciated	over	the	useful	life	of	the	related	asset.	Upon	settlement	of	the	obligation,	the	Company	eliminates	the	liability	and,	based	on	the	actual	cost	to	retire,	may incur	a	gain	or	loss.

GUARANTOR	ACCOUNTING—In	accordance	with	the	accounting	standards	on	guarantees,	at	the	inception	of	a	guarantee,	the	Company	records	the	fair value	of	a	guarantee	as	a	liability,	with	the	offset	dependent	on	the	circumstances	under	which	the	guarantee	was	issued.

TRANSFER	OF	FINANCIAL	ASSETS—Effective	January	1,	2010,	the	Company	prospectively	adopted	the	new	accounting	guidance	on	transfers	of	financial assets,	which	among	other	things:	removes	the	concept	of	a	qualifying	special	purpose	entity;	introduces	the	concept	of	participating	interests	and	specifies	that	in	order to	qualify	for	sale	accounting	a	partial	transfer	of	a	financial	asset	or	a	group	of	financial	assets	should	meet	the	definition	of	a	participating	interest;	clarifies	that	an entity	should	consider	all	arrangements	made	contemporaneously	with	or	in	contemplation	of	a	transfer	and	requires	enhanced	disclosures	to	provide	financial	statement users	with	greater	transparency	about	transfers	of	financial	assets	and	a	transferor's	continuing	involvement	with	transfers	of	financial	assets	accounted	for	as	sales. Upon	adoption	on	January	1,	2010,	the	Company	recognized	$40	million	as	accounts	receivable	and	as	an	associated	secured	borrowing	on	its

Consolidated	Balance	Sheet;	both	of	which	have	since	increased	to	$50	million	as	of	December	31,	2010,	as	additional	interests	in	receivables	have	been	sold.	While securitizing	these	accounts	receivable	through	IPL	Funding,	a	special	purpose	entity,	IPL,	the	Company's	integrated	utility	in	Indianapolis,	had	previously	recognized the	transaction	as	a	sale,	but	had	not	recognized	the	accounts	receivable	and	secured	borrowing	on	its	balance	sheet.	Under	the	facility,	interests	in	these	accounts receivable	are	sold,	on	a	revolving	basis,	to	unrelated	parties	(the	Purchasers)	up	to	the	lesser	of	$50	million	or	an	amount	determinable	under	the	facility	agreement.	The Purchasers	assume	the	risk	of	collection	on	the	interest	sold	without	recourse	to	IPL,	which	retains	the	servicing	responsibilities	for	the	interest	sold.	While	no	direct recourse	to	IPL	exists,	IPL	risks	loss	in	the	event	collections	are	not	sufficient	to	allow	for	full	recovery	of	the	retained	interests.	No	servicing	asset	or	liability	is recorded	since	the	servicing	fee	paid	to	IPL	approximates	a	market	rate.	Under	the	new	accounting	guidance,	the	retained	interest	in	these	securitized	accounts	receivable does	not	meet	the	definition	of	a	participating	interest,	thereby	requiring	the	Company	to	recognize	on	its	Consolidated	Balance	Sheet	the	portion	transferred	and	the proceeds	received	as	accounts	receivable	and	a	secured	borrowing,	respectively.

FOREIGN	CURRENCY	TRANSLATION—A	business'	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	a	currency	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.	Translation	adjustments	are included	in	AOCI.	Gains	and	losses	on	intercompany	foreign	currency	transactions	that	are	long-term	in	nature	and	which	the	Company	does	not	intend	to	settle	in	the foreseeable	future,	are	also	recognized	in	AOCI.	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.

REVENUE	RECOGNITION—Revenue	from	Utilities	is	classified	as	regulated	on	the	Consolidated	Statements	of	Operations.	Revenue	from	the	sale	of	energy is	recognized	in	the	period	during	which	the	sale	occurs.	The	calculation	of	revenue	earned	but	not	yet	billed	is	based	on	the	number	of	days	not	billed	in	the	month,	the estimated	amount	of	energy	delivered	during	those	days	and	the	estimated	average	price	per	customer	class	for	that	month.	Differences	between	actual	and	estimated unbilled	revenue	are	usually	immaterial.	Revenue	from	the	Generation	business	is	classified	as	non-regulated	and	is	recognized	based	upon	output	delivered	and capacity	provided,	at	rates	as	specified	under	contract	terms	or	prevailing	market	rates.	The	Company	has	businesses	where	it	makes	sales	and	purchases	of	power	to	and from	Independent	System	Operators	("ISOs")	and	Regional	Transmission	Organizations	("RTOs").	In	those	instances,	the	Company	accounts	for	these	transactions	on	a net	hourly	basis	because	the	transactions	are	settled	on	a	net	hourly	basis.	Revenue	is	recorded	net	of	any	taxes	assessed	on	and	collected	from	customers,	which	are remitted	to	the	governmental	authorities.

SHARE-BASED	COMPENSATION—The	Company	grants	share-based	compensation	in	the	form	of	stock	options	and	restricted	stock	units.	The	Company accounts	for	stock-based	compensation	plans	under	the	accounting	guidance	on	stock-based	compensation,	which	requires	entities	to	recognize	compensation	costs relating	to	share-based	payments	in	their	financial	statements.	That	cost	is	measured	on	the	grant	date	based	on	the	fair	value	of	the	equity	or	liability	instrument	issued and	is	expensed	on	a	straight-line	basis	over	the	requisite	service	period,	net	of	estimated	forfeitures.	Currently,	the	Company	uses	a	Black-Scholes	option	pricing	model to	estimate	the	fair	value	of	stock	options	granted	to	its	employees.

GENERAL	AND	ADMINISTRATIVE	EXPENSES—General	and	administrative	expenses	include	corporate	and	other	expenses	related	to	corporate	staff functions	and	initiatives,	primarily	executive	management,

finance,	legal,	human	resources	and	information	systems,	which	are	not	directly	allocable	to	our	business	segments.	Additionally,	all	costs	associated	with	business development	efforts	are	classified	as	general	and	administrative	expenses.

REGULATORY	ASSETS	AND	LIABILITIES—The	Company	accounts	for	certain	of	its	regulated	operations	in	accordance	with	the	accounting	standards	on regulated	operations.	As	a	result,	AES	records	assets	and	liabilities	that	result	from	the	regulated	ratemaking	process	that	are	not	recognized	under	GAAP	for	non- regulated	entities.	Regulatory	assets	generally	represent	incurred	costs	that	have	been	deferred	due	to	the	probability	of	future	recovery	in	customer	rates.	Regulatory liabilities	generally	represent	obligations	to	make	refunds	to	customers.	Management	continually	assesses	whether	the	regulatory	assets	are	probable	of	future	recovery by	considering	factors	such	as	applicable	regulatory	changes,	recent	rate	orders	applicable	to	other	regulated	entities	and	the	status	of	any	pending	or	potential deregulation	legislation.	If	future	recovery	of	costs	previously	deferred	ceases	to	be	probable,	the	asset	write-offs	are	recognized	in	continuing	operations.

DERIVATIVES	AND	HEDGING	ACTIVITIES—Derivatives	primarily	consist	of	interest	rate	swaps,	cross	currency	swaps,	foreign	currency	instruments,	and commodity	and	embedded	derivatives.	The	Company	enters	into	various	derivative	transactions	in	order	to	hedge	its	exposure	to	certain	market	risks.	AES	primarily uses	derivative	instruments	to	manage	its	interest	rate,	foreign	currency	and	commodity	exposures.	The	Company	does	not	enter	into	derivative	transactions	for	trading purposes.

Under	the	accounting	standards	for	derivatives	and	hedging,	the	Company	recognizes	all	contracts	that	meet	the	definition	of	a	derivative,	except	those	designated as	normal	purchase	or	normal	sale	at	inception,	as	either	assets	or	liabilities	in	the	Consolidated	Balance	Sheets	and	measures	those	instruments	at	fair	value.	Changes	in the	fair	value	of	derivatives	are	recognized	in	earnings	unless	specific	hedge	criteria	are	met.	Gains	and	losses	related	to	derivative	instruments	that	qualify	as	hedges	are recognized	in	the	same	category	as	generated	by	the	underlying	asset	or	liability.	Gains	or	losses	on	derivatives	that	do	not	qualify	for	hedge	accounting	are	recognized as	interest	expense	for	interest	rate	and	cross	currency	derivatives,	foreign	currency	transaction	gains	or	losses	for	foreign	currency	derivatives,	and	non-regulated revenue	or	non-regulated	cost	of	sales	for	commodity	derivatives.

The	accounting	standards	for	derivatives	and	hedging	enable	companies	to	designate	qualifying	derivatives	as	hedging	instruments	based	on	the	exposure	being hedged.	These	hedge	designations	include	fair	value	hedges	and	cash	flow	hedges.	Changes	in	the	fair	value	of	a	derivative	that	is	highly	effective,	designated	and qualifies	as	a	fair	value	hedge	are	recognized	in	earnings	as	offsets	to	the	changes	in	fair	value	of	the	exposure	being	hedged.	The	Company	has	no	fair	value	hedges	at this	time.	Changes	in	the	fair	value	of	a	derivative	that	is	highly	effective,	designated	and	qualifies	as	a	cash	flow	hedge	are	deferred	in	AOCI	and	are	recognized	into earnings	as	the	hedged	transactions	affect	earnings.	Any	ineffectiveness	is	recognized	in	earnings	immediately.	The	ineffective	portion	is	recognized	as	interest	expense for	interest	rate	and	cross	currency	hedges,	foreign	currency	transaction	gains	or	losses	for	foreign	currency	hedges,	and	non-regulated	revenue	or	non-regulated	cost	of sales	for	commodity	hedges.	For	all	hedge	contracts,	the	Company	maintains	formal	documentation	of	the	hedge	and	effectiveness	testing	in	accordance	with	the accounting	standards	for	derivatives	and	hedging.	If	AES	determines	that	the	derivative	is	not	highly	effective	as	a	hedge,	hedge	accounting	will	be	discontinued prospectively.

For	cash	flow	hedges	of	forecasted	transactions,	AES	estimates	the	future	cash	flows	of	the	forecasted	transactions	and	evaluates	the	probability	of	the	occurrence and	timing	of	such	transactions.	Changes	in	conditions	or	the	occurrence	of	unforeseen	events	could	require	discontinuance	of	hedge	accounting	or	could	affect	the timing	of	the	reclassification	of	gains	or	losses	on	cash	flow	hedges	from	AOCI	into	earnings.

The	Company	has	elected	not	to	offset	net	derivative	positions	in	the	financial	statements.	Accordingly,	the	Company	does	not	offset	such	derivative	positions against	the	fair	value	of	amounts	(or	amounts	that	approximate	fair	value)	recognized	for	the	right	to	reclaim	cash	collateral	(a	receivable)	or	the	obligation	to	return	cash collateral	(a	payable)	under	master	netting	arrangements.

See	Note	4—Fair	Value	and	the	Company's	fair	value	policy	for	additional	discussion	regarding	the	determination	of	the	fair	value	of	the	Company's	derivative assets	and	liabilities.

# 2.	INVENTORY

As	of	December	31,	2010,	77%	of	the	Company's	inventory	was	valued	using	average	cost,	21%	was	determined	using	the	FIFO	method	and	the	remaining inventory	was	valued	using	the	specific	identification	method.	The	following	table	summarizes	our	inventory	balances	as	of	December	31,	2010	and	2009:

|  | 2010 | 2009 |
| :--- | :--- | :--- |
|  | (in\tmillions) |  |
| Coal,\tfuel\toil\tand\tother\traw\tmaterials | $296 | $293 |
| Spare\tparts\tand\tsupplies | \t 304 | \t 267 |
| Total | $600 | $560 |

# 3.	PROPERTY,	PLANT	&	EQUIPMENT

The	following	table	summarizes	the	components	of	the	electric	generation	and	distribution	assets	and	other	property,	plant	and	equipment	with	their	estimated useful	lives:

|  | Estimated | December	31, | December	31, |
| :--- | :--- | :--- | :--- |
|  | Useful\tLife | 2010 | 2009 |
|  |  | (in\tmillions) |  |
| Electric\tgeneration\tand\tdistribution\tfacilities | \t3\t-\t62\tyrs. | $24,400 | $23,484 |
| Other\tbuildings | \t3\t-\t50\tyrs. | 2,215 | 1,926 |
| Furniture,\tfixtures\tand\tequipment | \t3\t-\t31\tyrs. | 729 | 685 |
| Other | \t1\t-\t50\tyrs. | 863 | 720 |
| Total\telectric\tgeneration\tand\tdistribution\tassets\tand\tother |  | \t 28,207 | \t 26,815 |
| Accumulated\tdepreciation |  | (9,173) | (8,774) |
| Net\telectric\tgeneration\tand\tdistribution\tassets\tand\tother^(1) |  | $19,034 | $18,041 |

Net	electric	generation	and	distribution	assets	and	other	related	to	Lal	Pir,	Pak	Gen,	Barka	and	Ras	Laffan	of	$848	million	as	of	December	31,	2009	were excluded	from	the	table	above	and	were	included	in	the	noncurrent	assets	of	discontinued	and	held	for	sale	businesses.

The	amounts	as	of	December	31,	2010	in	the	table	above	are	stated	net	of	impairment	losses	recognized	in	2010	as	further	discussed	in	Note	19—Impairment Expense.

|  |  | December	31, |  |
| :--- | :--- | :--- | :--- |
|  | 2010 | 2009 | 2008 |
|  |  | (in\tmillions) |  |
| Interest\tcapitalized\tduring\tdevelopment\tand\tconstruction | $193 | $187 | $176 |

Recoveries	of	liquidated	damages	from	construction	delays	and	government	subsidies	are	reflected	as	a	reduction	in	the	related	projects'	construction	costs.

Approximately	$12.2	billion	of	property,	plant	and	equipment,	net	of	accumulated	depreciation,	was	mortgaged,	pledged	or	subject	to	liens	as	of	December	31,	2010.

Depreciation	expense,	including	the	amortization	of	assets	recorded	under	capital	leases,	was	$1.1	billion,	$980	million	and	$928	million	for	the	years	ended December	31,	2010,	2009	and	2008,	respectively.

Net	electric	generation	and	distribution	assets	and	other	include	unamortized	internal	use	software	costs	of	$170	million	and	$182	million	as	of	December	31, 2010	and	2009,	respectively.	Amortization	expense	associated	with	software	costs	was	$52	million,	$48	million	and	$41	million	for	the	years	ended	December	31,	2010, 2009	and	2008.

The	following	table	summarizes	regulated	and	non-regulated	generation	and	distribution	property,	plant	and	equipment	and	accumulated	depreciation	as	of December	31,	2010	and	2009:

|  | 2010 | 2009 |
| :--- | :--- | :--- |
|  | (in\tmillions) |  |
| Regulated\tassets | $12,488 | $11,744 |
| Regulated\taccumulated\tdepreciation | (5,123) | (4,830) |
| Regulated\tgeneration,\tdistribution\tassets,\tand\tother,\tnet | 7,365 | 6,914 |
| Non-regulated\tassets | \t 15,719 | \t 15,071 |
| Non-regulated\taccumulated\tdepreciation | (4,050) | (3,944) |
| Non-regulated\tgeneration,\tdistribution\tassets,\tand\tother,\tnet | \t 11,669 | \t 11,127 |
| Net\telectric\tgeneration\tand\tdistribution\tassets,\tand\tother | $19,034 | $18,041 |

The	following	table	summarizes	the	amounts	recognized,	which	were	related	to	asset	retirement	obligations,	for	the	years	ended	December	31,	2010	and	2009:

|  | 2010 | 2009 |
| :--- | :--- | :--- |
|  | (in\tmillions) |  |
| Balance\tat\tJanuary\t1 | $101 | $70 |
| Additional\tliabilities\tincurred | 20 | 17 |
| Liabilities\tsettled | \t — | (1) |
| Accretion\texpense | 7 | 5 |
| Change\tin\testimated\tcash\tflows | 2 | 10 |
| Translation\tadjustments | (1) | \t — |
| Balance\tat\tDecember\t31 | $129 | $101 |

The	Company's	asset	retirement	obligations	covered	by	the	relevant	guidance	primarily	include	active	ash	landfills,	water	treatment	basins	and	the	removal	or dismantlement	of	certain	plant	and	equipment.	The	fair	value	of	legally	restricted	assets	for	purposes	of	settling	asset	retirement	obligations	was	$12	million	and	$0	at December	31,	2010	and	2009,	respectively.

The	fair	value	of	current	financial	assets	and	liabilities,	debt	service	reserves	and	other	deposits	approximate	their	reported	carrying	amounts.	The	fair	value	of non-recourse	debt	is	estimated	differently	based	upon	the	type	of	loan.	For	variable	rate	loans,	carrying	value	approximates	fair	value.	For	fixed	rate	loans,	the	fair	value is	estimated	using	quoted	market	prices	or	discounted	cash	flow	analyses.	See	Note	10—Debt	for	additional	information	on	the	fair	value	and	carrying	value	of	debt.	The fair	value	of	interest	rate	swap,	cap	and	floor	agreements,	foreign	currency	forwards,	swaps	and	options,	and	energy	derivatives	is	the	estimated	net	amount	that	the Company	would	receive	or	pay	to	sell	or	transfer	the	agreements	as	of	the	balance	sheet	date.

The	estimated	fair	values	of	the	Company's	assets	and	liabilities	have	been	determined	using	available	market	information.	By	virtue	of	these	amounts	being estimates	and	based	on	hypothetical	transactions	to	sell	assets	or	transfer	liabilities,	the	use	of	different	market	assumptions	and/or	estimation	methodologies	may	have	a material	effect	on	the	estimated	fair	value	amounts.

The	following	table	summarizes	the	carrying	and	fair	value	of	certain	of	the	Company's	financial	assets	and	liabilities	as	of	December	31,	2010	and	2009:

|  | 2010 |  | 2009 | 2009 |
| :--- | :--- | :--- | :--- | :--- |
|  | Carrying\nAmount | Fair\nValue | Carrying\nAmount | Fair\nValue |
|  |  | (in\tmillions) |  |  |
| Assets |  |  |  |  |
| Marketable\tsecurities | $1,772 | $1,772 | $1,691 | $1,691 |
| Derivatives | 125 | 125 | 141 | 141 |
| Total\tassets | $1,897 | $1,897 | $1,832 | $1,832 |
| Liabilities |  |  |  |  |
| Debt | $19,733 | $20,339 | $19,537 | $20,008 |
| Derivatives | 424 | 424 | 310 | 310 |
| Total\tliabilities | $20,157 | $20,763 | $19,847 | $20,318 |

# Valuation	Techniques:

The	fair	value	measurement	accounting	guidance	describes	three	main	approaches	to	measuring	the	fair	value:	(1)	market	approach;	(2)	income	approach	and (3)	cost	approach.	The	market	approach	uses	prices	and	other	relevant	information	generated	from	market	transactions	involving	identical	or	comparable	assets	or liabilities.	The	income	approach	often	uses	valuation	techniques	to	convert	future	amounts	to	a	single	present	value	amount.	The	measurement	is	based	on	current	market expectations	of	return	on	those	future	amounts.	The	cost	approach	is	based	on	the	amount	that	would	currently	be	required	to	replace	an	asset.	The	Company	measures its	investments	and	derivatives	at	fair	value	on	a	recurring	basis.	Additionally,	in	connection	with	annual	or	event-driven	impairment	evaluations,	certain	nonfinancial assets	and	liabilities	are	measured	at	fair	value	on	a	nonrecurring	basis.	These	include	long-lived	tangible	assets	(i.e.,	property,	plant	and	equipment),	goodwill	and intangible	assets	(e.g.,	sales	concessions,	land	use	rights	and	emissions	allowances	etc).	In	general,	the	Company	determines	the	fair	value	of	investments	using	the market	approach	and	of	derivatives	using	the	income	approach.	In	the	nonrecurring	measurements	of	nonfinancial	assets	and	liabilities,	all	three	approaches	are considered;	however,	fair	value	generated	by	the	income	approach	is	often	selected.

# Investments

The	Company's	investments	measured	at	fair	value	primarily	consist	of	marketable	debt	and	equity	securities.	Equity	securities	are	measured	at	fair	value	using quoted	market	prices.	Debt	securities	primarily	consist	of	unsecured	debentures,	certificates	of	deposit	and	government	debt	securities	held	by	our	Brazilian	subsidiaries. Returns	and	pricing	on	these	instruments	are	generally	indexed	to	the	CDI	(Brazilian	equivalent	to	London	Inter	Bank	Offered	Rate	("LIBOR"),	a	benchmark	interest rate	widely	used	by	banks	in	the	money	market),	or	Selic	(overnight	borrowing	rate)	rates	in	Brazil.	Fair	value	is	determined	from	comparisons	of	market	data	obtained for	similar	assets	and	is	considered	Level	2	in	the	fair	value	hierarchy.	For	more	detail	regarding	the	fair	value	of	investments	see	Note	5—Investments	in	Marketable Securities.

# Derivatives

When	deemed	appropriate,	the	Company	manages	its	risk	from	interest	and	foreign	currency	exchange	rate	and	commodity	price	fluctuations	through	the	use	of financial	and	physical	derivative	instruments.	The	Company's	derivatives	are	primarily	interest	rate	swaps	to	hedge	non-recourse	debt	to	establish	a	fixed	rate	on variable	rate	debt,	foreign	exchange	instruments	to	hedge	against	currency	fluctuations,	commodity	derivatives	to	hedge	against	commodity	price	fluctuations	and embedded	derivatives	associated	with	commodity	contracts.	The	Company's	subsidiaries	are	counterparties	to	various	over-the-counter	derivatives,	which	include interest	rate	swaps	and	options,	foreign	currency	options	and	forwards	and	commodity	swaps.	In	addition,	the	Company's	subsidiaries	are	counterparties	to	certain	PPAs and	fuel	supply	agreements	that	are	derivatives	or	include	embedded	derivatives.

For	the	derivatives	where	there	is	a	standard	industry	valuation	model,	the	Company	uses	that	model	to	estimate	the	fair	value.	For	the	derivatives	(such	the	PPAs and	fuel	supply	agreements	that	are	derivatives	or	include	embedded	derivatives)	where	there	is	not	a	standard	industry	valuation	model,	the	Company	has	created internal	valuation	models	to	estimate	the	fair	value,	using	observable	data	to	the	extent	available.	For	all	derivatives,	the	income	approach	is	used,	which	consists	of forecasting	future	cash	flows	based	on	contractual	notional	amounts	and	applicable	and	available	market	data	as	of	the	valuation	date.	The	following	are	among	the	most common	market	data	inputs	used	in	the	income	approach:	volatilities,	spot	and	forward	benchmark	interest	rates	(such	as	LIBOR	and	Euro	Inter	Bank	Offered	Rate ("EURIBOR")),	foreign	exchange	rates	and	commodity	prices.	Forward	rates	and	prices	are	generally	obtained	from	published	information	provided	by	pricing	services for	an	instrument	with	the	same	duration	as	the	derivative	instrument	being	valued.	In	situations	where	significant	inputs	are	not	observable,	the	Company	uses	relevant techniques	to	best	estimate	the	inputs,	such	as	regression	analysis,	Monte	Carlo	simulation	or	prices	for	similarly	traded	instruments	available	in	the	market.

For	each	derivative,	the	income	approach	is	used	to	estimate	the	cash	flows	over	the	remaining	term	of	the	contract.	Those	cash	flows	are	then	discounted	using the	relevant	spot	benchmark	interest	rate	(such	as	LIBOR	or	EURIBOR)	plus	a	spread	that	reflects	the	credit	or	nonperformance	risk.	This	risk	is	estimated	by	the Company	using	credit	spreads	and	risk	premiums	that	are	observable	in	the	market,	whenever	possible,	or	estimated	borrowing	costs	based	on	bank	quotes,	industry publications	and/or	information	on	financing	closed	on	similar	projects.	To	the	extent	that	management	can	estimate	the	fair	value	of	these	assets	or	liabilities	without the	use	of	significant	unobservable	inputs,	these	derivatives	are	classified	as	Level	2.

In	certain	instances,	the	published	forward	rates	or	prices	may	not	extend	through	the	remaining	term	of	the	contract	and	management	must	make	assumptions	to extrapolate	the	curve,	which	necessitates	the	use	of	unobservable	inputs,	such	as	proxy	commodity	prices	or	historical	settlements	to	forecast	forward	prices.	In	addition, in	certain	instances,	there	may	not	be	third	party	data	readily	available	which	requires	the	use	of	unobservable	inputs.	Similarly,	in	certain	instances,	the	spread	that reflects	the	credit	or	nonperformance	risk	is	unobservable.	The	fair	value	hierarchy	of	an	asset	or	a	liability	is	based	on	the	Level	of	significance	of	input	assumptions. An	input	assumption	is	considered	significant	if	it	affects	the	fair	value	by	at	least	10%.	Assets	and	liabilities	are	transferred	to	Level	3	when	the	use	of	unobservable inputs	becomes	significant.	Similarly,	when	the	use	of	unobservable	input	becomes	insignificant	for	Level	3	assets	and	liabilities,	they	are	transferred	to	Level	2.

Transfers	in	and	out	of	Level	3	are	determined	as	of	the	end	of	the	reporting	period	and	are	from	and	to	Level	2.	The	Company	has	not	had	any	Level	1 derivatives	so	there	have	not	been	any	transfers	between	Levels	1	and	2.

# Nonfinancial	assets	and	liabilities

For	nonrecurring	measurements	derived	using	the	income	approach,	fair	value	is	determined	using	valuation	models	based	on	the	principles	of	discounted	cash flows	("DCF").	The	income	approach	is	most	often	used	in	the	impairment	evaluation	of	long-lived	tangible	assets,	goodwill	and	intangible	assets.	The	Company	has developed	internal	valuation	models	for	such	valuations;	however,	an	independent	valuation	firm	may	be	engaged	in	certain	situations.	In	such	situations,	the independent	valuation	firm	largely	uses	DCF	valuation	models	as	the	primary	measure	of	fair	value	though	other	valuation	approaches	are	also	considered.	A	few examples	of	input	assumptions	to	such	valuations	include	macroeconomic	factors	such	as	growth	rates,	industry	demand,	inflation,	exchange	rates,	power	prices	and commodity	prices.	Whenever	possible,	the	Company	attempts	to	obtain	market	observable	data	to	develop	input	assumptions.	Where	the	use	of	market	observable	data is	limited	or	not	possible	for	certain	input	assumptions,	the	Company	develops	its	own	estimates	of	such	assumptions	using	a	variety	of	techniques	such	as	regression analysis	and	extrapolations.

For	nonrecurring	measurements	derived	using	the	market	approach,	recent	market	transactions	involving	the	sale	of	identical	or	similar	assets	are	considered.	The use	of	this	approach	is	limited	because	it	is	often	difficult	to	find	sale	transactions	of	identical	or	similar	assets.	This	approach	is	used	in	the	impairment	evaluations	of certain	intangible	assets.	Otherwise,	it	is	used	to	corroborate	the	fair	value	determined	under	the	income	approach.

For	nonrecurring	measurements	derived	using	the	cost	approach,	fair	value	is	typically	determined	using	the	replacement	cost	approach.	Under	this	approach,	the depreciated	replacement	cost	of	assets	is	determined	by	first	determining	the	current	replacement	cost	of	assets	and	then	applying	the	remaining	useful	lives	percentages to	such	cost.	Further	adjustments	for	economic	and	functional	obsolescence	are	made	to	the	depreciated	replacement	cost.	This	approach	involves	a	considerable	amount of	judgment	which	is	why	its	use	is	limited	to	the	measurement	of	a	few	long-lived	tangible	assets.	Like	the	market	approach,	this	approach	is	also	used	to	corroborate the	fair	value	determined	under	the	income	approach.	For	the	year	ended	December	31,	2010,	the	Company	did	not	measure	any	nonfinancial	assets	under	the	cost approach.

# Fair	Value	Considerations:

In	determining	fair	value,	the	Company	considers	the	source	of	observable	market	data	inputs,	liquidity	of	the	instrument,	the	credit	risk	of	the	counterparty	and the	risk	of	the	Company's	nonperformance.	The	conditions	and	criteria	used	to	assess	these	factors	are:

# Sources	of	market	assumptions:

The	Company	derives	most	of	its	market	assumptions	from	market	efficient	data	sources	(e.g.,	Bloomberg	and	Platt's).	In	some	cases,	where	market	data	is	not readily	available,	management	uses	comparable	market	sources	and	empirical	evidence	to	derive	market	assumptions	to	determine	the	fair	value.

# Market	liquidity:

The	Company	evaluates	market	liquidity	based	on	whether	the	financial	or	physical	instrument,	or	the	underlying	asset,	is	traded	in	an	active	or	inactive	market. An	active	market	exists	if	the	prices	are	fully	transparent	to	market	participants,	can	be	measured	by	market	bid	and	ask	quotes,	the	market	has	a	relatively	large proportion	of	trading	volume	as	compared	to	the	Company's	current	trading	volume	and	the	market	has	a	significant	number	of	market	participants	that	will	allow	the market	to	rapidly	absorb	the	quantity	of	the	assets	traded	without	significantly	affecting	the	market	price.	Other	factors	the	Company	considers	when	determining

whether	a	market	is	active	or	inactive	include	the	presence	of	government	or	regulatory	control	over	pricing	that	could	make	it	difficult	to	establish	a	market	based	price when	entering	into	a	transaction.

# Nonperformance	risk:

Nonperformance	risk	refers	to	the	risk	that	the	obligation	will	not	be	fulfilled	and	affects	the	value	at	which	a	liability	is	transferred	or	an	asset	is	sold. Nonperformance	risk	includes,	but	may	not	be	limited	to,	the	Company	or	counterparty's	credit	and	settlement	risk.	Nonperformance	risk	adjustments	are	dependent	on credit	spreads,	letters	of	credit,	collateral,	other	arrangements	available	and	the	nature	of	master	netting	arrangements.	The	Company	and	its	subsidiaries	are	parties	to various	interest	rate	swaps	and	options;	foreign	currency	options	and	forwards;	and	derivatives	and	embedded	derivatives	which	subject	the	Company	to nonperformance	risk.	The	financial	and	physical	instruments	held	at	the	subsidiary	Level	are	generally	non-recourse	to	the	Parent	Company.

Nonperformance	risk	on	the	investments	held	by	the	Company	is	incorporated	in	the	investment's	exit	price	that	is	derived	from	quoted	market	data	that	is	used	to mark	the	investment	to	fair	value.

The	Company	adjusts	for	nonperformance	risk	or	credit	risk	on	its	derivative	instruments	by	deducting	a	credit	valuation	adjustment	("CVA").	The	CVA	is	based on	the	margin	or	debt	spread	of	the	Company	or	counterparty	and	the	tenor	of	the	respective	derivative	instrument.	The	counterparty	for	a	derivative	asset	position	is considered	to	be	the	bank	or	government	sponsored	banking	entity	or	counterparty	to	the	PPA	or	commodity	contract.	The	CVA	for	asset	positions	is	based	on	the counterparty's	credit	ratings	and	debt	spreads	or,	in	the	absence	of	readily	obtainable	credit	information,	the	respective	country	debt	spreads	are	used	as	a	proxy.	The CVA	for	liability	positions	is	based	on	the	Parent	Company's	or	the	subsidiary's	current	debt	spread,	the	margin	on	indicative	financing	arrangements,	or	in	the	absence of	readily	obtainable	credit	information,	the	respective	country	debt	spreads	are	used	as	a	proxy.	If	the	instrument	is	recourse	to	the	Parent	Company,	the	Parent Company's	current	debt	spread	is	used	to	adjust	for	nonperformance	risk.	All	derivative	instruments	are	analyzed	individually	and	are	subject	to	unique	risk	exposures.

# Recurring	Measurements:

The	following	table	sets	forth,	by	Level	within	the	fair	value	hierarchy,	the	Company's	financial	assets	and	liabilities	that	were	measured	at	fair	value	on	a recurring	basis	as	of	December	31,	2010	and	2009.	Financial	assets	and	liabilities	have	been	classified	in	their	entirety	based	on	the	lowest	Level	of	input	that	is significant	to	the	fair	value	measurement.	The	Company's	assessment	of	the	significance	of	a	particular	input	to	the	fair	value	measurement	requires	judgment,	and	may affect	the	determination	of	the	fair	value	of	the	assets	and	liabilities	and	their	placement	within	the	fair	value	hierarchy	levels.

The	following	table	presents	a	reconciliation	of	derivative	assets	and	liabilities	measured	at	fair	value	on	a	recurring	basis	using	significant	unobservable	inputs (Level	3)	for	the	years	ended	December	31,	2010	and	2009:

|  | 2010 | 2010 | 2010 | 2010 | 2010 | 2009 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Interest\nRate | Cross\nCurrency | Foreign\nCurrency | Commodity\n&amp;\tOther | Total | Total |
|  |  |  | (in\tmillions) |  |  |  |
| Balance\tat\tbeginning\tof\tperiod^(1) | $(12) | $(12) | $— | $24 | $— | $ (69) |
| Total\tgains\t(losses)\t(realized\tand\tunrealized):^(1) |  |  |  |  |  |  |
| Included\tin\tearnings^(2) | 1 | 4 | 25 | 21 | 51 | (20) |
| Included\tin\tother\tcomprehensive\tincome | (12) | 13 | — | — | 1 | \t 134 |
| Included\tin\tregulatory\tassets | (3) | — | — | 1 | (2) | \t — |
| Purchases,\tissuances\tand\tsettlements^(1) | 7 | 5 | (1) | (28) | (17) | 31 |
| Transfers\tof\tassets\t(liabilities)\tinto\tLevel\t3^(3) | — | — | (2) | — | (2) | 1 |
| Transfers\tof\t(assets)\tliabilities\tout\tof\tLevel\t3^(3) | 18 | — | — | — | 18 | (77) |
| Balance\tat\tend\tof\tperiod^(1) | $(1) | $10 | $22 | $18 | $49 | $— |
| Total\tgains\t(losses)\tfor\tthe\tperiod\tincluded\tin\tearnings\tattributable\tto\tthe |  |  |  |  |  |  |
| change\tin\tunrealized\tgains\t(losses)\trelating\tto\tassets\tand\tliabilities\theld\tat |  |  |  |  |  |  |
| the\tend\tof\tthe\tperiod^(1) | $ — | $7 | $24 | $9 | $40 | $(2) |

# Derivative	assets	and	(liabilities)	are	presented	on	a	net	basis.

The	gains	(losses)	included	in	earnings	for	these	Level	3	derivatives	are	classified	as	follows:	interest	rate	and	cross	currency	derivatives	as	interest	expense, foreign	currency	derivatives	as	foreign	currency	transaction	gains	(losses)	and	commodity	and	other	derivatives	as	either	non-regulated	revenue,	non-regulated cost	of	sales	or	other	expense.	See	Note	6—Derivative	Instruments	and	Hedging	Activities	for	further	information	regarding	the	classification	of	gains	and	losses included	in	earnings	in	the	Consolidated	Statements	of	Operations.

Transfers	in	and	out	of	Level	3	are	determined	as	of	the	end	of	the	reporting	period	and	are	from	and	to	Level	2.	The	(assets)	liabilities	transferred	out	of	Level	3 are	primarily	the	result	of	a	decrease	in	the	significance	of	unobservable	inputs	used	to	calculate	the	credit	valuation	adjustments	of	these	derivative	instruments. Similarly,	the	assets	(liabilities)	transferred	into	Level	3	are	primarily	the	result	of	an	increase	in	the	significance	of	unobservable	inputs	used	to	calculate	the credit	valuation	adjustments	of	these	derivative	instruments.

The	following	table	presents	a	reconciliation	of	available-for-sale	securities	measured	at	fair	value	on	a	recurring	basis	using	significant	unobservable	inputs (Level	3)	for	the	years	ended	December	31,	2010	and	2009:

|  | 2010 |  | 2009 |
| :--- | :--- | :--- | :--- |
|  |  | (in\tmillions) |  |
| Balance\tat\tbeginning\tof\tperiod^(1) | $42 |  | $42 |
| Purchases,\tissuances\tand\tsettlements | — |  | — |
| Balance\tat\tend\tof\tperiod | $42 |  | $42 |
| Total\tgains\t(losses)\tfor\tthe\tperiod\tincluded\tin\tearnings\tattributable\tto\tthe\tchange\tin\tunrealized\tgains/losses\trelating\tto\tassets\nheld\tat\tthe\tend\tof\tthe\tperiod | $— |  | $— |

Available-for-sale	securities	in	Level	3	are	auction	rate	securities	and	variable	rate	demand	notes	which	have	failed	remarketing	or	are	not	actively	trading	and	for which	there	are	no	longer	adequate	observable	inputs	to	measure	the	fair	value.

# Nonrecurring	Measurements:

For	the	purpose	of	impairment	evaluation,	the	Company	measured	fair	values	of	long-lived	assets,	goodwill	and	intangibles	assets,	and	assets	and	liabilities	of discontinued	operations	under	the	fair	value	measurement	accounting	guidance.	The	following	table	summarizes	major	categories	of	assets	and	liabilities	measured	at fair	value	on	a	nonrecurring	basis	during	the	year	and	their	level	within	the	fair	value	hierarchy:

|  |  | Fair	Value | Fair	Value | Fair	Value | Gross |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | Carrying |  |  |  | (Gain) |
|  | Amount^\t(1) | Level\t1 | Level\t2 | Level\t3 | Loss |
|  |  |  | (in\tmillions) |  |  |
| Long-lived\tassets\theld\tand\tused: |  |  |  |  |  |
| Eastern\tEnergy | $827 | $ — | $ — | $ — | $827 |
| Southland\t(Huntington\tBeach) | 288 | \t — | \t — | 88 | 200 |
| Tisza\tII | 160 | \t — | \t — | 75 | 85 |
| Deepwater | 83 | \t — | \t — | 4 | 79 |
| Discontinued\toperations\tand\tbusinesses\theld\tfor\tsale: |  |  |  |  |  |
| Barka | 20 | \t — | 124 | \t — | (104) |
| Ras\tLaffan | 120 | \t — | 226 | \t — | (106) |
| Goodwill: |  |  |  |  |  |
| Deepwater | 18 | \t — | \t — | \t — | 18 |
| Other | 3 | \t — | \t — | \t — | 3 |

Carrying	amount	as	of	the	month	end	prior	to	impairment.

# Long-lived	Assets	Held	and	Used

In	the	fourth	quarter	of	2010,	the	Company	determined	there	were	impairment	indicators	for	the	long-lived	assets	at	Eastern	Energy,	our	coal-fired	generation plants	in	New	York.	These	long-lived	assets	had	a	carrying	amount	of	$827	million	and	were	considered	fully	impaired.	This	resulted	in	the	recognition	of	asset impairment	expense	of	$827	million.

In	the	fourth	quarter	of	2010,	the	Company	determined	there	were	impairment	indicators	for	the	long-lived	assets	at	Deepwater,	our	pet-coke-fired	generation facility	in	Texas.	These	long-lived	assets	had	a	carrying	amount	of	$83	million	and	were	written	down	to	their	fair	value	of	$4	million.	This	resulted	in	the	recognition	of asset	impairment	expense	of	$79	million.

In	the	third	quarter	of	2010,	the	Company	determined	there	were	impairment	indicators	for	the	long-lived	assets	at	Tisza	II,	our	gas-fired	generation	plant	in Hungary,	and	Huntington	Beach,	one	of	our	gas-fired	generation	plants	in	California.	These	long-lived	assets	had	carrying	amounts	of	$160	million	and	$288	million, respectively,	and	were	written	down	to	their	fair	value	of	$75	million	and	$88	million,	respectively.	These	resulted	in	the	recognition	of	asset	impairment	expense	of	$85 million	and	$200	million,	respectively.

Since	the	majority	of	significant	assumptions	used	in	the	valuations	were	not	observable,	management	believes	that	the	measurements	are	Level	3	in	the	fair	value hierarchy.	For	further	discussion	of	these	impairments,	see	Note	19—Impairment	Expense.

# Discontinued	Operations	and	Held	for	Sale	Businesses

The	Company	determined	the	fair	value	of	nonfinancial	assets	and	liabilities	of	our	held	for	sale	businesses	during	the	year	ended	December	31,	2010.	These included	the	Company's	operations	in	Oman	and	Qatar.

Since	the	fair	value	estimates	were	based	on	sale	price,	management	believes	that	the	measurement	is	Level	2	in	the	fair	value	hierarchy.	For	further	discussion, see	Note	21—Discontinued	Operations	and	Held	for	Sale	Businesses.

As	noted	in	Note	8—Goodwill	and	Other	Intangible	Assets,	goodwill	of	$18	million	related	to	our	Deepwater	business	was	written	down	to	its	implied	fair	value of	zero	during	an	interim	impairment	evaluation,	resulting	in	the	recognition	of	goodwill	impairment	of	$18	million	for	the	year	ended	December	31,	2010.

Since	the	majority	of	significant	assumptions	used	in	the	valuation	were	not	observable,	management	believes	that	the	measurement	is	Level	3	in	the	fair	value hierarchy.	For	further	discussion,	see	Note	8—Goodwill	and	Other	Intangible	Assets.

# 5.	INVESTMENTS	IN	MARKETABLE	SECURITIES

The	following	table	sets	forth	the	Company's	investments	in	marketable	debt	and	equity	securities	classified	as	trading	and	available-for-sale	as	of	December	31, 2010	and	2009	by	type	of	investment	and	by	level	within	the	fair	value	hierarchy.	The	security	types	are	determined	based	on	the	nature	and	risk	of	the	security	and	are consistent	with	how	the	Company	manages,	monitors	and	measures	its	securities.

|  | 2010 | 2010 | 2010 | 2010 | 2009 | 2009 | 2009 | 2009 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Level\t1 | Level\t2 | Level\t3 | Total | Level\t1 | Level\t2 | Level\t3 | Total |
|  |  |  |  | (in\tmillions) | (in\tmillions) |  |  |  |
| AVAILABLE-FOR-SALE:^(1) |  |  |  |  |  |  |  |  |
| Debt\tsecurities: |  |  |  |  |  |  |  |  |
| Unsecured\tdebentures^(2) | $ — | $727 | $ — | $727 | $ — | $667 | $ — | $667 |
| Certificates\tof\tdeposit^(2) | \t — | 877 | \t — | 877 | \t — | 652 | \t — | 652 |
| Government\tdebt\tsecurities | \t — | 47 | \t — | 47 | \t — | 152 | \t — | 152 |
| Other | \t — | — | 42 | 42 | \t — | — | 42 | 42 |
| Subtotal | \t — | \t 1,651 | 42 | \t 1,693 | \t — | \t 1,471 | 42 | 1,513 |
| Equity\tsecurities: |  |  |  |  |  |  |  |  |
| Mutual\tfunds | 1 | 61 | \t — | 62 | 117 | — | \t — | 117 |
| Common\tstock | 7 | — | \t — | 7 | 16 | — | \t — | 16 |
| Money\tmarket\tfunds | \t — | — | \t — | — | \t — | 30 | \t — | 30 |
| Subtotal | 8 | 61 | \t — | 69 | 133 | 30 | \t — | 163 |
| Total\tavailable-for-sale | 8 | \t 1,712 | 42 | \t 1,762 | 133 | \t 1,501 | 42 | $1,676 |
| TRADING: |  |  |  |  |  |  |  |  |
| Equity\tsecurities: |  |  |  |  |  |  |  |  |
| Mutual\tfunds | 10 | — | \t — | 10 | 7 | — | \t — | 7 |
| Total\ttrading | 10 | — | \t — | 10 | 7 | — | \t — | 7 |
| TOTAL | $18 | $1,712 | $42 | $1,772 | $140 | $1,501 | $42 | $1,683 |
| Held-to-maturity\tsecurities^(3) |  |  |  | — |  |  |  | 8 |
| Total\tmarketable\tsecurities |  |  |  | $1,772 |  |  |  | $1,691 |

Amortized	cost	approximated	fair	value	at	December	31,	2010	and	2009,	with	the	exception	of	certain	common	stock	investments	with	a	cost	basis	of	$6	million carried	at	their	fair	value	of	$7	million	and	$16	million	at	December	31,	2010	and	2009,	respectively.

Unsecured	debentures	are	instruments	similar	to	certificates	of	deposit	that	are	held	primarily	by	our	subsidiaries	in	Brazil.	The	unsecured	debentures	and certificates	of	deposit	included	here	do	not	qualify	as	cash	equivalents	and	meet	the	definition	of	a	security	under	the	relevant	guidance	and	are	therefore	classified as	available-for-sale	securities.

Held-to-maturity	securities	are	carried	at	amortized	cost	and	not	measured	at	fair	value	on	a	recurring	basis.	These	investments	consist	primarily	of	certificates	of deposit	and	government	debt	securities.	The	amortized	cost	approximated	fair	value	of	the	held-to-maturity	securities	at	December	31,	2009.

As	of	December	31,	2010,	all	available-for-sale	debt	securities	had	stated	maturities	less	than	one	year,	with	the	exception	of	$42	million	of	auction	rate	securities and	variable	rate	demand	notes	held	by	IPL,	a	subsidiary	of	the	Company	in	Indiana.	These	securities,	classified	as	other	debt	securities	in	the	table	above,	had	stated maturities	of	greater	than	ten	years.

During	the	second	quarter	of	2009,	three	of	the	Company's	generation	businesses	in	the	Dominican	Republic	exchanged	$110	million	of	accounts	receivable	due from	the	government-owned	distribution	companies	in	the	Dominican	Republic	for	sovereign	bonds	of	the	same	amount.	The	bonds,	which	were	classified	as	available- for-sale	securities,	were	adjusted	to	fair	value	when	acquired.	During	the	second	and	third	quarters	of	2009,	the	Company	used	a	portion	of	the	bonds	with	a	carrying value	of	$31	million	to	settle	third-party	liabilities	and	sold	the	remaining	bonds.	As	of	December	31,	2009,	all	of	the	sovereign	bonds	had	been	sold	or	transferred.

The	following	table	summarizes	the	pre-tax	gains	and	losses	related	to	available-for-sale	securities	for	the	years	ended	December	31,	2010,	2009	and	2008.	There were	no	realized	gains	or	losses	on	trading	securities	and	there	were	no	realized	losses	on	the	sale	of	available-for-sale	securities.	There	was	no	other-than-temporary impairment	of	marketable	securities	recognized	in	earnings	or	other	comprehensive	income	for	the	years	ended	December	31,	2010,	2009	or	2008.

|  | 2010 | 2009 | 2008 |
| :--- | :--- | :--- | :--- |
|  |  | (in\tmillions) |  |
| Gains\t(losses)\tincluded\tin\tother\tcomprehensive\tincome | $2 | $10 | $(2) |
| Gains\treclassified\tout\tof\tother\tcomprehensive\tincome\tinto\tearnings | — | 2 | — |
| Proceeds\tfrom\tsales | \t 5,888 | \t 4,466 | \t 5,006 |
| Gross\trealized\tgains\ton\tsales | 2 | 3 | — |

# 6.	DERIVATIVE	INSTRUMENTS	AND	HEDGING	ACTIVITIES

# Risk	Management	Objectives

The	Company	is	exposed	to	market	risks	associated	with	its	enterprise-wide	business	activities,	namely	the	purchase	and	sale	of	fuel	and	electricity	as	well	as foreign	currency	risk	and	interest	rate	risk.	In	order	to	manage	the	market	risks	associated	with	these	business	activities,	we	enter	into	contracts	that	incorporate derivatives	and	financial	instruments,	including	forwards,	futures,	options,	swaps	or	combinations	thereof,	as	appropriate.	The	Company	applies	hedge	accounting	for	all contracts	as	long	as	they	are	eligible	under	the	accounting	standards	for	derivatives	and	hedging.	While	derivative	transactions	are	not	entered	into	for	trading	purposes, some	contracts	are	not	eligible	for	hedge	accounting.

# Interest	Rate	Risk

AES	and	its	subsidiaries	utilize	variable	rate	debt	financing	for	construction	projects	and	operations,	resulting	in	an	exposure	to	interest	rate	risk.	Interest	rate swap,	cap	and	floor	agreements	are	entered	into	to	manage	interest	rate	risk	by	effectively	fixing	or	limiting	the	interest	rate	exposure	on	the	underlying	financing.	These interest	rate	contracts	range	in	maturity	through	2027,	and	are	typically	designated	as	cash	flow	hedges.	The	following	table	sets	forth,	by	underlying	type	of	interest	rate index,	the	Company's	current	and	maximum	outstanding	notional	under	its	interest	rate	derivative	instruments,	the	weighted	average	remaining	term	and	the	percentage of	variable-rate	debt	hedged	that	is	based	on	the	related	index	as	of	December	31,	2010	regardless	of	whether	the	derivative	instruments	are	in	qualifying	cash	flow hedging	relationships:

|  | Current |  | Maximum^(1) | Maximum^(1) |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Interest\tRate\tDerivatives | Derivative\nNotional | Derivative\nNotional\nTranslated\nto\tUSD | Derivative\nNotional | Derivative\nNotional\nTranslated\nto\tUSD | Weighted\nAverage\nRemaining\nTerm^(1) | %\tof\tDebt\nCurrently\nHedged\nby\tIndex^(2) |
|  |  | (in\tmillions) |  |  | (in\tyears) |  |
| LIBOR\t(U.S.\tDollar) | 2,543 | $2,543 | 2,671 | $2,671 | 10 | 69% |
| EURIBOR\t(Euro) | 1,233 | 1,651 | 1,233 | 1,651 | 13 | 72% |
| LIBOR\t(British\tPound\tSterling) | 44 | 68 | 44 | 68 | 10 | 69% |
| Securities\tIndustry\tand\tFinancial\tMarkets |  |  |  |  |  |  |
| Association\tMunicipal\tSwap\tIndex\t(U.S.\tDollar) | 40 | 40 | 40 | 40 | 12 | N/A^(3) |

The	Company's	interest	rate	derivative	instruments	primarily	include	accreting	and	amortizing	notionals.	The	maximum	derivative	notional	represents	the	largest notional	at	any	point	between	December	31,	2010	and	the	maturity	of	the	derivative	instrument,	which	includes	forward	starting	derivative	instruments.	The weighted	average	remaining	term	represents	the	remaining	tenor	of	our	interest	rate	derivatives	weighted	by	the	corresponding	maximum	notional. Excludes	variable-rate	debt	tied	to	other	indices	where	the	Company	has	no	interest	rate	derivatives.

The	debt	that	was	being	hedged	is	no	longer	exposed	to	variable	interest	payments	because	it	is	now	held	on	IPL's	behalf	and	no	longer	bears	interest.

Cross	currency	swaps	are	utilized	in	certain	instances	to	manage	the	risk	related	to	fluctuations	in	both	interest	rates	and	certain	foreign	currencies.	These	cross currency	contracts	range	in	maturity	through	2028.	The	following	table	sets	forth,	by	type	of	foreign	currency	denomination,	the	Company's	outstanding	notional	of	its cross	currency	derivative	instruments	as	of	December	31,	2010	which	are	all	in	qualifying	cash	flow	hedge	relationships.	These	swaps	are	amortizing	and	therefore	the notional	amount	represents	the	maximum	outstanding	notional	as	of	December	31,	2010:

|  |  | December	31,	2010 | December	31,	2010 |  |  |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  | Weighted | Weighted | Weighted |  | %\tof\tDebt | %\tof\tDebt |
|  |  | Notional | Average | Average |  | Currently | Currently |
|  |  | Translated | Remaining | Remaining |  | Hedged |  |
| Cross\tCurrency\tSwaps | Notional | to\tUSD | Term | (1) |  | by\tIndex | (2) |
|  | (in\tmillions) |  |  |  | (in\tyears) |  |  |
| Chilean\tUnidad\tde\tFomento\t(CLF) | 6 | $257 |  | 15 |  |  | 83% |

Represents	the	remaining	tenor	of	our	cross	currency	swaps	weighted	by	the	corresponding	notional.

Represents	the	proportion	of	foreign	currency	denominated	debt	hedged	by	the	same	foreign	currency	denominated	notional	of	the	cross	currency	swap.

# Foreign	Currency	Risk

We	are	exposed	to	foreign	currency	risk	as	a	result	of	our	investments	in	foreign	subsidiaries	and	affiliates.	AES	operates	businesses	in	many	foreign environments	and	such	operations	in	foreign	countries	may	be	impacted	by	significant	fluctuations	in	foreign	currency	exchange	rates.	Foreign	currency	options	and forwards	are	utilized,	where	possible,	to	manage	the	risk	related	to	fluctuations	in	certain	foreign	currencies.	These	foreign	currency	contracts	range	in	maturity	through 2011.	The	following	tables	set	forth,	by	type	of	foreign	currency	denomination,	the	Company's	outstanding	notional	over	the	remaining	terms	of	its	foreign	currency derivative	instruments	as	of	December	31,	2010	regardless	of	whether	the	derivative	instruments	are	in	qualifying	hedging	relationships:

|  |  |  |  | Weighted |
| :--- | :--- | :--- | :--- | :--- |
|  |  | Notional | Probability | Average |
| Foreign\tCurrency\tOptions | Notional^(1) | Translated\nto\tUSD^(1) | Adjusted\nNotional^(2) | Remaining\nTerm^(3) |
|  |  | (in\tmillions) |  | (in\tyears) |
| Brazilian\tReal\t(BRL) | 208 | $120 | $30 | &lt;1 |
| Euro\t(EUR) | 15 | 21 | 18 | &lt;1 |
| Philippine\tPeso\t(PHP) | 266 | 6 | 1 | &lt;1 |
| British\tPound\t(GBP) | 3 | 4 | 2 | &lt;1 |

Represents	contractual	notionals	at	inception	of	trade.

Represents	the	gross	notional	amounts	times	the	probability	of	exercising	the	option,	which	is	based	on	the	relationship	of	changes	in	the	option	value	with respect	to	changes	in	the	price	of	the	underlying	currency.

Represents	the	remaining	tenor	of	our	foreign	currency	options	weighted	by	the	corresponding	notional.

|  |  |  | Weighted |
| :--- | :--- | :--- | :--- |
| Foreign\tCurrency\tForwards | Notional | Notional\nTranslated\nto\tUSD | Average\nRemaining\nTerm^(1) |
|  | (in\tmillions) |  | (in\tyears) |
| Chilean\tPeso\t(CLP) | \t89,106 | $179 | &lt;1 |
| Colombian\tPeso\t(COP) | \t13,151 | 7 | &lt;1 |
| Argentine\tPeso\t(ARS) | 57 | 13 | &lt;1 |

Represents	the	remaining	tenor	of	our	foreign	currency	forwards	weighted	by	the	corresponding	notional.

In	addition,	certain	of	our	subsidiaries	have	entered	into	contracts	which	contain	embedded	derivatives	that	require	separate	valuation	and	accounting	due	to	the fact	that	the	item	being	purchased	or	sold	is	denominated	in	a	currency	other	than	the	functional	currency	of	that	subsidiary	or	the	currency	of	the	item.	These	contracts range	in	maturity	through	2025.	The	following	table	sets	forth,	by	type	of	foreign	currency	denomination,	the	Company's	outstanding	notional	over	the	remaining	terms of	its	foreign	currency	embedded	derivative	instruments	as	of	December	31,	2010:

|  |  |  | Weighted |
| :--- | :--- | :--- | :--- |
| Embedded\tForeign\tCurrency\tDerivatives | Notional | Notional\nTranslated\nto\tUSD | Average\nRemaining\nTerm^(1) |
|  | (in\tmillions) |  | (in\tyears) |
| Philippine\tPeso\t(PHP) | \t21,176 | $484 | 3 |
| Kazakhstani\tTenge\t(KZT) | \t31,084 | 210 | 10 |
| Argentine\tPeso\t(ARS) | 331 | 83 | 9 |
| Euro\t(EUR) | 28 | 38 | 4 |
| Brazilian\tReal\t(BRL) | 19 | 11 | 1 |
| Cameroon\tFranc\t(XAF) | 1,755 | 4 | 2 |

Represents	the	remaining	tenor	of	our	foreign	currency	embedded	derivatives	weighted	by	the	corresponding	notional.

We	are	exposed	to	the	impact	of	market	fluctuations	in	the	price	of	electricity,	fuel	and	environmental	credits.	Although	we	primarily	consist	of	businesses	with long-term	contracts	or	retail	sales	concessions	(which	provide	our	distribution	businesses	with	a	franchise	to	serve	a	specific	geographic	region),	a	portion	of	our	current and	expected	future	revenues	are	derived	from	businesses	without	significant	long-term	purchase	or	sales	contracts.	These	businesses	subject	our	results	of	operations	to the	volatility	of	prices	for	electricity,	fuel	and	environmental	credits	in	competitive	markets.	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	can	involve	the	use	of	commodity	forward	contracts, futures,	swaps	and	options.	Some	of	our	businesses	hedge	certain	aspects	of	their	commodity	risks	using	financial	hedging	instruments,	as	described	below.

We	also	enter	into	short-term	contracts	for	electricity	and	fuel	in	other	competitive	markets	in	which	we	operate.	When	hedging	the	output	of	our	generation assets,	we	have	power	purchase	agreements	or	other	hedging	instruments	that	lock	in	the	spread	in	dollars	per	MWh	between	the	cost	of	fuel	to	generate	a	unit	of electricity	and	the	price	at	which	the	electricity	can	be	sold	("Dark	Spread"	where	the	fuel	is	coal).	The	portion	of	our	sales	and	fuel	purchases	that	are	not	subject	to	such agreements	will	be	exposed	to	commodity	price	risk.	Eastern	Energy	sells	electricity	into	the	power	pools	managed	by	the	New	York	Independent	System	Operator ("NYISO").	In	addition,	Eastern	Energy	hedges	a	portion	of	its	power	exposure	by	entering	into	hedges	of	natural	gas	prices,	as	movements	in	natural	gas	prices	affect power	prices.	As	of	December	31,	2010,	Eastern	Energy	has	no	net	exposure	under	its	hedges	of	natural	gas	prices.	While	there	is	a	strong	relationship	between	natural gas	and	power	prices,	the	natural	gas	hedges	do	not	currently	qualify	for	hedge	accounting	treatment.	The	following	table	sets	forth	the	Company's	current	notionals under	its	commodity	hedges	at	Eastern	Energy	and	the	percentage	of	forecasted	electricity	sales	for	2011	hedged	as	of	December	31,	2010	regardless	of	whether	the derivative	instruments	are	in	qualifying	cash	flow	hedging	relationships:

The	PPAs	and	fuel	supply	agreements	entered	into	by	the	Company	are	evaluated	to	determine	if	they	meet	the	definition	of	a	derivative	or	contain	embedded derivatives,	either	of	which	require	separate	valuation	and	accounting.	To	be	a	derivative	under	the	accounting	standards	for	derivatives	and	hedging,	an	agreement would	need	to	have	a	notional	and	an	underlying,	require	little	or	no	initial	net	investment	and	could	be	net	settled.	Generally,	these	agreements	do	not	meet	the definition	of	a	derivative,	often	due	to	the	inability	to	be	net	settled.	On	a	quarterly	basis,	we	evaluate	the	markets	for	the	commodities	to	be	delivered	under	these agreements	to	determine	if	facts	and	circumstances	have	changed	such	that	the	agreements	could	then	be	net	settled	and	meet	the	definition	of	a	derivative.

Nonetheless,	certain	of	the	PPAs	and	fuel	supply	agreements	entered	into	by	certain	of	the	Company's	subsidiaries	are	derivatives	or	contain	embedded derivatives	requiring	separate	valuation	and	accounting.	These	agreements	range	in	maturity	through	2024.	The	following	table	sets	forth	by	type	of	commodity	the Company's	outstanding	notionals	for	the	remaining	term	of	its	commodity	derivative	(excluding	Eastern	Energy	which	is	presented	in	the	above	table)	and	embedded derivative	instruments	as	of	December	31,	2010:

|  |  | Weighted |
| :--- | :--- | :--- |
|  |  | Average |
|  |  | Remaining |
| Commodity\tDerivatives | Notional | Term^(1) |
|  | (in\tmillions) | (in\tyears) |
| Natural\tgas\t(MMBtu) | 34 | 12 |
| Petcoke\t(Metric\ttons) | 14 | 14 |
| Aluminum\t(MWh) | 17^(3) | 9 |
| Certified\tEmission\tReductions\t(CER) | 1 | 2 |
| Log\twood\t(Tons) | —\t\t(2) | 2 |
| Financial\ttransmission\trights\t(MW) | —\t\t(2) | &lt;1 |

Represents	the	remaining	tenor	of	our	commodity	and	embedded	derivatives	weighted	by	the	corresponding	volume. De	minimis	amount.

Our	exposure	is	to	fluctuations	in	the	price	of	aluminum	while	the	notional	is	based	on	the	amount	of	power	we	sell	under	the	PPA.

In	addition,	as	part	of	the	settlement	agreements	terminating	the	gas	transportation	contracts	with	Gasoducto	GasAndes	(Argentina)	S.A.	and	Gasoducto GasAndes	(Chile)	S.A.	discussed	in	Note	12—Contingencies,	we	have	an	embedded	derivative	related	to	the	dividends	that	could	result	from	our	13%	ownership	in these	two	gas	transportation	companies.

# Accounting	and	Reporting

The	following	table	sets	forth	the	Company's	derivative	instruments	as	of	December	31,	2010	and	2009	by	type	of	derivative	and	by	level	within	the	fair	value hierarchy.	Derivative	assets	and	liabilities	are	recognized	at	their	fair	value.	Derivative	assets	and	liabilities	are	combined	with	other	balances	and	included	in	the following	captions	in	our	Consolidated	Balance	Sheets:	current	derivative	assets	in	other	current	assets,	noncurrent	derivative	assets	in	other	noncurrent	assets,	current derivative	liabilities	in	accrued	and	other	liabilities	and	long-term	derivative	liabilities	in	other	long-term	liabilities.

|  | December	31,	2010 | December	31,	2010 | December	31,	2010 | December	31,	2010 | December	31,	2009 | December	31,	2009 | December	31,	2009 | December	31,	2009 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Level\t1 | Level\t2 | Level\t3 | Total | Level\t1 | Level\t2 | Level\t3 | Total |
|  |  | (in\tmillions) |  |  |  | (in\tmillions) |  |  |
| Assets |  |  |  |  |  |  |  |  |
| Current\tassets: |  |  |  |  |  |  |  |  |
| Foreign\tcurrency\tderivatives | $ — | $4(1) | $3 | $7 | $ — | $6 | $ — | $6 |
| Commodity\tand\tother\tderivatives: |  |  |  |  |  |  |  |  |
| Electricity | \t — | \t — | \t — | \t — | \t — | 22 | \t — | 22 |
| Natural\tgas | \t — | 1 | \t — | 1 | \t — | \t — | 11 | 11 |
| Other | \t — | 2 | 3 | 5 | \t — | \t — | 17 | 17 |
| Total\tcurrent\tassets | \t — | 7 | 6 | 13 | \t — | 28 | 28 | 56 |
| Noncurrent\tassets: |  |  |  |  |  |  |  |  |
| Interest\trate\tderivatives | \t — | 49 | \t — | 49 | \t — | 83 | 2 | 85 |
| Foreign\tcurrency\tderivatives | \t — | 4(1) | 27 | 31 | \t — | \t — | \t — | \t — |
| Cross\tcurrency\tderivatives | \t — | \t — | 12 | 12 | \t — | \t — | \t — | \t — |
| Commodity\tand\tother\tderivatives | \t — | 4 | 16 | 20 | \t — | \t — | \t — | \t — |
| Total\tnoncurrent\tassets | \t — | 57 | 55 | \t 112 | \t — | 83 | 2 | 85 |
| Total\tassets | $ — | $64 | $61 | $125 | $ — | $111 | $30 | $141 |
| Liabilities |  |  |  |  |  |  |  |  |
| Current\tliabilities: |  |  |  |  |  |  |  |  |
| Interest\trate\tderivatives | $ — | $137^(1) | $ — | $137 | $ — | $118 | $7 | $125 |
| Cross\tcurrency\tderivatives | \t — | \t — | 2 | 2 | \t — | \t — | \t — | \t — |
| Foreign\tcurrency\tderivatives | \t — | 13 | \t — | 13 | \t — | 3 | \t — | 3 |
| Commodity\tand\tother\tderivatives: |  |  |  |  |  |  |  |  |
| Electricity | \t — | 1 | \t — | 1 | \t — | 2 | \t — | 2 |
| Natural\tgas | \t — | \t — | \t — | \t — | \t — | 5 | \t — | 5 |
| Other | \t — | \t — | \t — | \t — | \t — | \t — | 2 | 2 |
| Total\tcurrent\tliabilities | \t — | 151 | 2 | \t 153 | \t — | 128 | 9 | \t 137 |
| Long-term\tliabilities: |  |  |  |  |  |  |  |  |
| Interest\trate\tderivatives | \t — | 246^(1) | 1 | \t 247 | \t — | 150 | 7 | \t 157 |
| Cross\tcurrency\tderivatives | \t — | \t — | \t — | \t — | \t — | \t — | 12 | 12 |
| Foreign\tcurrency\tderivatives | \t — | 15 | 8 | 23 | \t — | 2 | \t — | 2 |
| Commodity\tand\tother\tderivatives: |  |  |  |  |  |  |  |  |
| Natural\tgas | \t — | \t — | \t — | \t — | \t — | \t — | 2 | 2 |
| Other | \t — | \t — | 1 | 1 | \t — | \t — | \t — | \t — |
| Total\tlong-term\tliabilities | \t — | 261 | 10 | \t 271 | \t — | 152 | 21 | \t 173 |
| Total\tliabilities | $ — | $412 | $12 | $424 | $ — | $280 | $30 | $310 |

Includes	the	impact	of	consolidating	Cartagena	beginning	January	1,	2010	under	VIE	accounting	guidance	as	follows:	$1	million	of	current	assets	and	$4	million of	noncurrent	assets	on	foreign	currency	derivatives	and	$19	million	of	current	liabilities	and	$46	million	of	long-term	liabilities	for	interest	rate	derivatives	as	of December	31,	2010.

The	following	table	sets	forth	the	fair	value	and	balance	sheet	classification	of	derivative	instruments	as	of	December	31,	2010	and	2009:

|  | December	31,	2010 | December	31,	2010 | December	31,	2010 | December	31,	2009 | December	31,	2009 | December	31,	2009 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Designated | Not\tDesignated |  | Designated | Not\tDesignated |  |
|  | as\tHedging\nInstruments | as\tHedging\nInstruments | Total | as\tHedging\nInstruments | as\tHedging\nInstruments | Total |
|  |  | (in\tmillions) |  |  | (in\tmillions) |  |
| Assets |  |  |  |  |  |  |
| Other\tcurrent\tassets: |  |  |  |  |  |  |
| Foreign\tcurrency\tderivatives | $— | $7(1) | $7 | $— | $6 | $6 |
| Commodity\t&amp;\tother\tderivatives: |  |  |  |  |  |  |
| Electricity | — | — | \t — | 22 | — | 22 |
| Natural\tgas | — | 1 | 1 | — | 11 | 11 |
| Other | — | 5 | 5 | — | 17 | 17 |
| Total\tother\tcurrent\tassets | — | 13 | 13 | 22 | 34 | 56 |
| Other\tassets: |  |  |  |  |  |  |
| Interest\trate\tderivatives | 49 | — | 49 | 85 | — | 85 |
| Foreign\tcurrency\tderivatives | — | 31^(1) | 31 | — | — | \t — |
| Cross\tcurrency\tderivatives | 12 | — | 12 | — | — | \t — |
| Commodity\t&amp;\tother\tderivatives: | — | 20 | 20 | — | — | \t — |
| Total\tother\tassets—noncurrent | 61 | 51 | \t 112 | 85 | — | 85 |
| Total\tassets | $61 | $64 | $125 | $107 | $34 | $141 |
| Liabilities |  |  |  |  |  |  |
| Accrued\tand\tother\tliabilities: |  |  |  |  |  |  |
| Interest\trate\tderivatives | $126^(1) | $11 | $137 | $115 | $10 | $125 |
| Cross\tcurrency\tderivatives | 2 | — | 2 | — | — | \t — |
| Foreign\tcurrency\tderivatives | 8 | 5 | 13 | 2 | 1 | 3 |
| Commodity\t&amp;\tother\tderivatives: |  |  |  |  |  |  |
| Electricity | 1 | — | 1 | 2 | — | 2 |
| Natural\tgas | — | — | \t — | — | 5 | 5 |
| Other | — | — | \t — | — | 2 | 2 |
| Total\taccrued\tand\tother\tliabilities | 137 | 16 | \t 153 | 119 | 18 | \t 137 |
| Other\tlong-term\tliabilities: |  |  |  |  |  |  |
| Interest\trate\tderivatives | 232^(1) | 15 | \t 247 | 141 | 16 | \t 157 |
| Cross\tcurrency\tderivatives | — | — | \t — | 12 | — | 12 |
| Foreign\tcurrency\tderivatives | — | 23 | 23 | — | 2 | 2 |
| Commodity\t&amp;\tother\tderivatives: |  |  |  |  |  |  |
| Natural\tgas | — | — | \t — | — | 2 | 2 |
| Other | — | 1 | 1 | — | — | \t — |
| Total\tother\tlong-term\tliabilities | 232 | 39 | \t 271 | 153 | 20 | \t 173 |
| Total\tliabilities | $369 | $55 | $424 | $272 | $38 | $310 |

The	Company	has	elected	not	to	offset	net	derivative	positions	in	the	financial	statements.	Accordingly,	the	Company	does	not	offset	such	derivative	positions against	the	fair	value	of	amounts	(or	amounts	that	approximate	fair	value)	recognized	for	the	right	to	reclaim	cash	collateral	(a	receivable)	or	the	obligation	to	return	cash collateral	(a	payable)	under	master	netting	arrangements.	At	December	31,	2010	and	2009,	we	held	$0	and	$8	million,	respectively,	of	cash	collateral	that	we	received from	counterparties	to	our	derivative	positions,	which	is	recorded	in	restricted	cash	and	in	accrued	and	other	liabilities	in	the	Consolidated	Balance	Sheets.	Beyond	the cash	collateral	we	received,	our	derivative	assets	are	exposed	to	the	credit	risk	of	the	respective	counterparty	and,	due	to	this	credit	risk,	the	fair	value	of	our	derivative assets	(as	shown	in	the	above	two	tables)	have	been	reduced	by	a	credit	valuation	adjustment.	Also,	at	December	31,	2010	and	2009,	we	had	no	cash	collateral	posted with	(held	by)	counterparties	to	our	derivative	positions.

The	table	below	sets	forth	the	pre-tax	accumulated	other	comprehensive	income	(loss)	expected	to	be	recognized	as	an	increase	(decrease)	to	income	from continuing	operations	before	income	taxes	over	the	next	twelve	months	as	of	December	31,	2010	for	the	following	types	of	derivative	instruments:

The	balance	in	accumulated	other	comprehensive	loss	related	to	derivative	transactions	will	be	reclassified	into	earnings	as	interest	expense	is	recognized	for interest	rate	hedges	and	cross	currency	swaps,	as	depreciation	is	recognized	for	interest	rate	hedges	during	construction,	as	foreign	currency	transaction	gains	and	losses are	recognized	for	hedges	of	foreign	currency	exposure,	and	as	electricity	sales	and	fuel	purchases	are	recognized	for	hedges	of	forecasted	electricity	and	fuel transactions.	These	balances	are	included	in	the	consolidated	statements	of	cash	flows	as	operating	and/or	investing	activities	based	on	the	nature	of	the	underlying transaction.

For	the	years	ended	December	31,	2010,	2009	and	2008,	pre-tax	gains	(losses)	of	$(1)	million,	$7	million,	and	$(1)	million	net	of	noncontrolling	interests, respectively,	were	reclassified	into	earnings	as	a	result	of	the	discontinuance	of	a	cash	flow	hedge	because	it	was	probable	that	the	forecasted	transaction	would	not	occur by	the	end	of	the	originally	specified	time	period	(as	documented	at	the	inception	of	the	hedging	relationship)	or	within	an	additional	two-month	time	period	thereafter.

The	following	table	sets	forth	the	pre-tax	gains	(losses)	recognized	in	accumulated	other	comprehensive	loss	("AOCL")	and	earnings	related	to	the	effective portion	of	derivative	instruments	in	qualifying	cash	flow	hedging	relationships,	as	defined	in	the	accounting	standards	for	derivatives	and	hedging,	for	the	years	ended December	31,	2010	and	2009:

|  | Gains	(Losses) |  |  | Reclassified |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | Recognized\tin\nAOCL | Recognized\tin\nAOCL |  | from\tAOCL\ninto\tEarnings | from\tAOCL\ninto\tEarnings |
|  | 2010 | 2009 | Statement\tof\tOperations | 2010 | 2009 |
|  | (in\tmillions) |  |  | (in\tmillions) |  |
| Interest\trate\tderivatives | $(243)^(3) | $49 | Interest\texpense | $(108)^(1) | $ (72)^(1) |
|  |  |  | Non-regulated\tcost\tof\tsales | (2) | \t — |
|  |  |  | Net\tequity\tin\tearnings\tof\taffiliates | (1) | \t —\t\t(2) |
| Cross\tcurrency\tderivatives | 11 | 48 | Interest\texpense | (1) | 2 |
|  |  |  | Foreign\tcurrency\ttransaction\tgains\t(losses) | \t — | 43 |
| Foreign\tcurrency\tderivatives | (9) | 2 | Foreign\tcurrency\ttransaction\tgains\t(losses) | (3) | \t —\t\t(2) |
| Commodity\tderivatives—electricity | (8) | \t 120 | Non-regulated\trevenue | 11 | \t 193 |
| Total | $(249) | $219 |  | $(104) | $166 |

Includes	amounts	that	were	reclassified	from	AOCL	related	to	derivative	instruments	that	previously,	but	no	longer,	qualify	for	cash	flow	hedge	accounting.

Excludes	$(113)	million	and	$(35)	million	related	to	discontinued	operations	for	the	years	ended	December	31,	2010	and	2009,	respectively. De	minimis	amount.

Includes	$(29)	million	related	to	Cartagena	for	the	year	ended	December	31,	2010,	which	was	consolidated	prospectively	beginning	January	1,	2010	under	VIE accounting	guidance.

Amounts	recognized	in	AOCL	due	to	derivative	instruments	that	currently	are,	or	previously	were	(but	no	longer	are)	qualifying	cash	flow	hedging	relationships, as	defined	in	the	accounting	standards	for	derivatives	and	hedging,	after	income	taxes,	during	the	year	ended	December	31,	2008	are	as	follows:

|  | Balance,<br>January	1 | Reclassification<br>to	earnings | Change	in<br>fair	value | Balance,<br>December	31 |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (in\tmillions) |  |  |
| 2008 | $(232) | $76 | $(107) | $(263) |

The	following	table	sets	forth	the	pre-tax	gains	(losses)	recognized	in	earnings	related	to	the	ineffective	portion	of	derivative	instruments	in	qualifying	cash	flow hedging	relationships,	as	defined	in	the	accounting	standards	for	derivatives	and	hedging,	for	the	years	ended	December	31,	2010	and	2009:

|  | Classification	in | Recognized	in	Earnings | Recognized	in	Earnings |
| :--- | :--- | :--- | :--- |
|  | Consolidated\tStatement\tof\tOperations | \t\t2010 | \t\t2009 |
|  |  | (in\tmillions) |  |
| Interest\trate\tderivatives | Interest\texpense | $(15) | $(8) |
|  | Net\tequity\tin\tearnings\tof\taffiliates | —\t\t(1) | (1) |
| Cross\tcurrency\tderivatives | Interest\texpense | 5 | (11) |
| Foreign\tcurrency\tderivatives | Foreign\tcurrency\ttransaction\tgains\t(losses) | —\t\t(1) | —\t\t(1) |
| Commodity\tderivatives—electricity | Non-regulated\trevenue | — | (2) |
| Total |  | $(10) | $(22) |

# De	minimis	amount.

The	Company	recognized	after-tax	losses	of	$45	million,	net	of	noncontrolling	interests,	related	to	the	ineffective	portion	of	derivative	instruments	in	qualifying cash	flow	hedging	relationships,	as	defined	in	the	accounting	standards	for	derivatives	and	hedging,	for	the	year	ended	December	31,	2008.

The	following	table	sets	forth	the	pre-tax	gains	(losses)	recognized	in	earnings	related	to	derivative	instruments	not	designated	as	hedging	instruments	under	the accounting	standards	for	derivatives	and	hedging,	for	the	years	ended	December	31,	2010	and	2009:

|  | Classification | Gains	(Losses) |  |
| :--- | :--- | :--- | :--- |
|  | in\tConsolidated | Recognized\t\tin\tEarnings | Recognized\t\tin\tEarnings |
|  | Statement\tof\tOperations | \t\t\t\t2010 | \t\t\t\t2009 |
|  |  | (in\tmillions) |  |
| Interest\trate\tderivatives | Interest\texpense | $(7) | $(25) |
| Foreign\texchange\tderivatives | Foreign\tcurrency\ttransaction\tgains\t(losses) | (36) | (38) |
|  | Net\tequity\tin\tearnings\tof\taffiliates | (2) | —\t\t(1) |
| Commodity\tderivatives—natural\tgas | Non-regulated\trevenue | 47 | (6) |
|  | Non-regulated\tcost\tof\tsales | 3 | (8) |
| Commodity\t&amp;\tother\tderivatives | Non-regulated\trevenue | 21 | 1 |
|  | Non-regulated\tcost\tof\tsales | 2 | (24) |
|  | Other\tincome | — | 8 |
|  | Net\tequity\tin\tearnings\tof\taffiliates | —\t\t(1) | —\t\t(1) |
| Total |  | $28 | $(92) |

The	Company	recognized	after-tax	gains	of	$10	million	net	of	noncontrolling	interests	related	to	the	changes	in	fair	value	of	derivative	instruments	not	in qualifying	cash	flow	hedging	relationships,	as	defined	in	the	accounting	standards	for	derivatives	and	hedging,	for	the	year	ended	December	31,	2008.

In	addition,	IPL	has	two	derivative	instruments	for	which	the	gains	and	losses	are	accounted	for	in	accordance	with	accounting	standards	for	regulated	operations, as	regulatory	assets	or	liabilities.	Gains	and	losses	on	these	derivatives	due	to	changes	in	the	fair	value	of	these	derivatives	are	probable	of	recovery	through	future	rates and	are	initially	recognized	as	an	adjustment	to	the	regulatory	asset	or	liability	and	recognized	through	earnings	when	the	related	costs	are	recovered	through	IPL's	rates. Therefore,	these	gains	and	losses	are	excluded	from	the	above	table.	The	following	table	sets	forth	the	change	in	regulatory	assets	and	liabilities	resulting	from	the change	in	the	fair	value	of	these	derivatives	for	the	years	ended	December	31,	2010	and	2009:

# Credit	Risk-Related	Contingent	Features

The	following	businesses	have	derivative	agreements	that	contain	credit	contingent	provisions	which	would	permit	the	counterparties	with	which	we	are	in	a	net liability	position	to	require	collateral	credit	support	when	the	fair	value	of	the	derivatives	exceeds	the	unsecured	thresholds	established	in	the	agreements.	These thresholds	vary	based	on	our	subsidiaries'	credit	ratings	and	as	their	credit	ratings	are	lowered,	the	thresholds	decrease,	requiring	more	collateral	support.

Eastern	Energy,	our	generation	business	in	New	York,	enters	into	commodity	derivative	transactions	with	several	counterparties	who	have	market	exposure	limits defined	in	their	transaction	agreements.	Pursuant	to	the	aforementioned	credit	contingent	provisions,	if	Eastern	Energy's	credit	rating	were	to	fall	below	the	minimum thresholds	established	in	each	of	the	respective	transaction	agreements,	the	counterparties	could	demand	immediate	collateralization	of	the	entire	mark-to-market	value of	the	derivatives	(excluding	credit	valuation	adjustments)	if	the	derivatives	were	in	a	net	liability	position.	As	of	December	31,	2010,	Eastern	Energy	has	$1	million	in net	liability	positions	but	had	posted	no	collateral.	As	of	December	31,	2009,	Eastern	Energy	had	net	liability	positions	of	$2	million	and	had	posted	a	nominal	amount of	collateral	to	support	these	positions	based	on	its	current	credit	rating	and	the	related	thresholds	in	the	agreements.

Gener,	our	generation	business	in	Chile,	has	a	cross	currency	swap	agreement	with	a	counterparty	to	swap	Chilean	inflation	indexed	bonds	issued	in	December 2007	into	U.S.	Dollars.	Pursuant	to	the	aforementioned	credit	contingent	provisions,	if	Gener's	credit	rating	were	to	fall	below	the	minimum	threshold	established	in	the swap	agreements,	the	counterparty	can	demand	immediate	collateralization	of	the	entire	mark-to-market	value	of	the	swaps	(excluding	credit	valuation	adjustments)	if Gener	is	in	a	net	liability	position,	which	was	zero	and	$12	million,	respectively,	at	December	31,	2010	and	2009.	As	of	December	31,	2010	and	2009,	Gener	had	posted zero	and	$25	million,	respectively,	in	the	form	of	a	letter	of	credit	to	support	these	swaps.

# 7.	INVESTMENTS	IN	AND	ADVANCES	TO	AFFILIATES

The	following	table	summarizes	the	relevant	effective	equity	ownership	interest	and	carrying	values	for	the	Company's	investments	accounted	for	under	the equity	method	as	of	December	31,	2010	and	2009.

| Affiliate | Country | 2010 | 2009 | 2010 | 2009 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  | Carrying\tValue | Carrying\tValue | Ownership\tInterest\t% | Ownership\tInterest\t% |
|  |  | (in\tmillions) |  |  |  |
| AES\tSolar\tEnergy\tLtd. | United\tStates | $256 | $224 | 50% | 50% |
| AES\tSolar\tPower\tLtd. | United\tStates | 8 | — | 50% | —\t\t% |
| Barry^(1) | United\tKingdom | — | — | 100% | 100% |
| Cartagena | Spain | N/A | — | N/A | 71% |
| CEMIG^(2) | Brazil | 22 | — | 72% | 10% |
| Chigen\taffiliates | China | 146 | 182 | 25% | 27% |
| China\tWind | China | 69 | 52 | 49% | 49% |
| Elsta | Netherlands | 202 | 204 | 50% | 50% |
| Guacolda | Chile | 149 | 131 | 35% | 35% |
| IC\tIctas\tEnergy\tGroup | Turkey | 151 | 104 | 51% | 51% |
| InnoVent^(1) | France | 31 | 30 | 40% | 40% |
| JHRH | China | 39 | — | 35% | —\t\t% |
| OPGC | India | 224 | 208 | 49% | 49% |
| Trinidad\tGeneration\tUnlimited^(1) | Trinidad | 20 | 16 | 10% | 10% |
| Other\taffiliates |  | 3 | 6 | —\t\t% | —\t\t% |
| Total\tinvestments\tin\tand\tadvances\tto\taffiliates |  | $1,320 | $1,157 |  |  |

Represent	VIEs	in	which	we	hold	a	variable	interest,	but	are	not	the	primary	beneficiary.

The	Company	sold	its	interest	in	CEMIG	during	the	year	ended	December	31,	2010;	and	retains	its	equity	ownership	in	Cayman	Energy	Traders	("CET").	See additional	discussion	of	the	sale	below.

AES	Solar	Energy	Ltd.—In	March	2008,	the	Company	formed	AES	Solar	Energy	Ltd	("AES	Solar"),	a	joint	venture	with	Riverstone	Holdings	LLC ("Riverstone").	AES	Solar	develops	land-based	solar	photovoltaic	panels	that	capture	sunlight	to	convert	into	electricity	that	feed	directly	into	power	grids.	AES	Solar	is accounted	for	under	the	equity	method	of	accounting	based	on	the	Company's	50%	ownership	and	significant	influence,	but	not	control	over	the	joint	venture.	Under	the terms	of	the	agreement,	the	Company	and	Riverstone	may	each	provide	up	to	$500	million	of	capital	over	the	next	five	years.	As	of	December	31,	2010,	AES	had invested	approximately	$312	million	in	the	joint	venture.

AES	Solar	Power	Ltd.—In	March	2010,	the	Company	formed	AES	Solar	Power	Ltd.	("AES	Solar	Power"),	a	joint	venture	with	Riverstone.	AES	Solar	Power develops	solar	photovoltaic	projects	in	the	United	States.	AES	Solar	Power	is	accounted	for	under	the	equity	method	of	accounting	based	on	the	Company's 50%	ownership	and	significant	influence,	but	not	control	over	the	joint	venture.	Under	the	terms	of	the	agreement,	the	Company	and	Riverstone	may	each	provide	up	to $100	million	of	capital	over	the	next	five	years.	As	of	December	31,	2010,	AES	had	invested	approximately	$11	million	in	the	joint	venture.

AES	Barry	Ltd.—The	Company	holds	a	100%	ownership	interest	in	AES	Barry	Ltd.	("Barry"),	a	dormant	entity	in	the	United	Kingdom	that	disposed	of	its generation	and	other	operating	assets.	As	a	result	of	a	debt	agreement,	no	material	financial	or	operating	decisions	can	be	made	without	the	banks'	consent,	and	the Company	does	not	control	Barry.	As	of	December	31,	2010	and	2009,	other	long-term	liabilities	included	$53	million	and	$54	million,	respectively,	related	to	this	debt agreement.

Cartagena	Energia—The	Company	owns	71%	of	Cartagena	Energia	("Cartagena"),	a	1,199	MW	power	plant	in	Cartagena,	Spain	completed	in	November	2007. The	Company's	initial	investment	in	Cartagena	was	approximately	$29	million.	As	a	result	of	the	accounting	guidance	issued	in	2009	regarding	VIEs,	the	Company consolidated	Cartagena	effective	January	1,	2010.	Cartagena	is	no	longer	accounted	for	under	the	equity	method	of	accounting.	For	further	discussion,	see	Note	1 —General	and	Summary	of	Significant	Accounting	Policies.

CEMIG—During	the	second	quarter	of	2010,	the	Company,	through	its	Brazilian	subsidiary,	Southern	Electric	Brasil	Participações	Ltda.	("SEB"),	transferred	its shares	of	Companhia	Energética	de	Minas	Gerais	("CEMIG"),	an	integrated	utility	in	Minas	Gerais,	Brazil,	to	Andrade	Gutierrez	Concessões	S.A.	and	an	affiliated company	(jointly	referred	to	as,	"AG").	AG	also	assumed	SEB's	debt	with	Banco	Nacional	de	Desenvolvimento	Econômico	e	Social	("BNDES")	in	the	amount	of approximately	$1.4	billion	(the	"BNDES	Loan")	including	all	unpaid	interest	and	penalties.	In	exchange,	SEB	received	$25	million	and	obtained	a	full	release	from	any claims	of	BNDES	and	originating	from	the	BNDES	Loan.	See	Note	12—Contingencies,	for	additional	information	regarding	these	claims	and	proceedings.

Prior	to	the	transfer	of	shares,	the	Company,	through	SEB,	a	VIE,	had	a	14.8%	voting	interest	in	CEMIG.	The	Company	holds	its	interest	in	SEB	through	its equity	ownership	in	Cayman	Energy	Traders	("CET"),	a	holding	company	whose	sole	activity	is	its	investment	in	SEB.	Although	our	interest	in	CEMIG	was	below	20%, AES	had	significant	influence	over	the	operational	and	financial	policies	of	CEMIG	through	representation	on	the	board	of	directors	of	CEMIG.	In	2002,	the	Company determined	there	was	an	other-than-temporary	impairment	of	its	investment	in	CEMIG	and	wrote	it	down	to	fair	market	value,	$155	million.	Additionally,	AES established	a	valuation	allowance	against	a	deferred	tax	asset	related	to	its	investment	in	CEMIG.	The	total	amount	of	these	charges,	net	of	tax,	was	$587	million.	As	a result,	the	Company's	investment	in	CEMIG	was	a	$484	million	net	liability	at	December	31,	2009	and	was	included	in	"Other	long-term	liabilities"	on	the	Consolidated Balance	Sheet.	The	Company	discontinued	the	application	of	the	equity	method	in	accordance	with	its	accounting	policy	regarding	equity	method	investments.

The	consummation	of	the	share	purchase	and	sale	agreement	along	with	AG's	assumption	of	the	BNDES	Loan	in	June	2010	resulted	in	the	reversal	of	the Company's	net	long-term	liability	along	with	the	associated	cumulative	translation	adjustment,	resulting	in	the	recognition	of	a	$115	million	pre-tax	gain	reflected	in "Net	equity	in	earnings	of	affiliates"	on	the	Consolidated	Statement	of	Operations	for	the	year	ended	December	31,	2010.	Additionally,	$70	million	of	net	tax	expense resulting	from	the	CEMIG	sale	transaction	was	recorded	as	"income	tax	expense,"	rather	than	equity	earnings,	since	the	expense	is	attributable	to	a	consolidated corporate	level	partner	in	the	CEMIG	investment.

# The	Company	retains	its	ownership	in	CET.

China	Wind—In	May	2007,	the	Company	entered	into	a	joint	venture	with	Guohua	Energy	Investment	Co.	Ltd.	("Guohua")	for	a	49%	interest	in	Guohua	AES (Huanghua)	Wind	Power	Co.,	Ltd.	("AES	Huanghua")	that	is	primarily	engaged	to	develop,	construct,	own	and	operate	wind	projects	in	Huanghua.	Huanghua	I	went live	in	the	third	quarter	of	2009	and	Huanghua	II	went	live	in	April	2010.	In	the	second	and	third	quarters	of	2008,	the	Company	acquired	a	49%	interest	in	Guohua	AES ("Hulunbeier")	Wind	Power	Co.,	Ltd.	and	entered	into	joint	venture	agreements	with	Guohua	for	49%	interest	in	Guohua	AES	("Xinba'erhu")	Wind	Power	Co.,	Ltd. ("Dong	Qi")	which	went	live	in	June	2010	and	Guohua	AES	("Chenba'erhu")	Wind	Power	Co.,	Ltd.	("Chen	Qi")	which	is	expected	to	go	live	in	2011.	The	Company invested	approximately	$12	million	in	the	aforementioned	projects	in	2010,	bringing	the	cumulative	investment	to	$62	million.

Jianghe	Rural	Electrification	Development	Co.,	LTD	("JHRH")—	On	June	3,	2010,	the	Company	entered	into	an	agreement	to	acquire	a	35%	ownership	in	this joint	venture	which	operates	seven	hydro	plants	in	China.	The	agreement	entitled	the	Company	to	acquire	up	to	a	49%	interest.	The	purchase	of	an	additional	14% ownership	is	expected	to	be	completed	by	May	2011.

Trinidad	Generation	Unlimited—In	2007,	the	Company	began	pursuing	a	development	project	to	construct	and	operate	a	720	MW	combined	cycle	power	plant in	Trinidad	through	its	wholly	owned	subsidiary,	Trinidad	Generation	Unlimited	("TGU").	In	July	2008,	a	shareholder	agreement	was	executed	establishing	the Company's	ownership	interest	in	TGU	at	60%	with	the	remaining	40%	interest	held	by	the	Government	of	Trinidad	and	Tobago.	Although	the	Company's	ownership	in TGU	was	reduced	to	10%	in	2009,	the	Company	continues	to	account	for	its	investment	in	Trinidad	as	an	equity	method	investment	because	AES	continues	to	exercise significant	influence	through	the	supermajority	vote	requirement	for	any	significant	future	project	development	activities.

# Summarized	Financial	Information

The	following	tables	summarize	financial	information	of	the	Company's	50%-or-less	owned	affiliates	and	majority-owned	unconsolidated	subsidiaries	that	are accounted	for	using	the	equity	method.

At	December	31,	2010,	retained	earnings	included	$168	million	related	to	the	undistributed	earnings	of	the	Company's	50%-or-less	owned	affiliates.	Distributions received	from	these	affiliates	were	$49	million,	$35	million	and	$50	million	for	the	years	ended	December	31,	2010,	2009	and	2008,	respectively.

Refer	to	Item	1	of	this	Form	10-K	for	additional	information	on	these	affiliates.

# 8.	GOODWILL	AND	OTHER	INTANGIBLE	ASSETS

The	following	table	summarizes	the	changes	in	the	carrying	amount	of	goodwill,	by	segment	for	the	years	ended	December	31,	2010,	2009	and	2008.	There	was no	goodwill	associated	with	our	North	America—Utilities	segment	during	the	years	ended	December	31,	2010,	2009	and	2008.

|  | Latin<br>America	-<br>Generation | Latin<br>America	-<br>Utilities | North<br>America	-<br>Generation | Europe	-<br>Generation | Asia	-<br>Generation | Corporate<br>and	Other | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Balance\tas\tof\tDecember\t31,\t2008 |  |  |  |  |  |  |  |
| Goodwill | $926 | $140 | $121 | $127 | $78 | $101 | $1,493 |
| Accumulated\timpairment\tlosses | (24) | (7) | (20) | (19) | — | (2) | (72) |
| Net\tbalance | 902 | 133 | 101 | 108 | 78 | 99 | \t 1,421 |
| Impairment\tlosses | — | — | — | (118) | — | (4) | (122) |
| Goodwill\tassociated\twith\tthe\tsale\tof\ta\tbusiness | — | — | — | — | (2) | — | (2) |
| Foreign\tcurrency\ttranslation\tand\tother | — | — | (10) | 10 | 2 | — | 2 |
| Balance\tas\tof\tDecember\t31,\t2009 |  |  |  |  |  |  |  |
| Goodwill | 926 | 140 | 111 | 137 | 78 | 101 | \t 1,493 |
| Accumulated\timpairment\tlosses | (24) | (7) | (20) | (137) | — | (6) | (194) |
| Net\tbalance | 902 | 133 | 91 | — | 78 | 95 | \t 1,299 |
| Impairment\tlosses | — | — | (18) | — | — | (3) | (21) |
| Foreign\tcurrency\ttranslation\tand\tother | — | — | (10) | — | 3 | — | (7) |
| Balance\tas\tof\tDecember\t31,\t2010 |  |  |  |  |  |  |  |
| Goodwill | 926 | 140 | 101 | 137 | 81 | 101 | \t 1,486 |
| Accumulated\timpairment\tlosses | (24) | (7) | (38) | (137) | — | (9) | (215) |
| Net\tbalance | $902 | $133 | $63 | $— | $81 | $92 | $1,271 |

During	the	third	quarter	of	2010,	Deepwater,	our	petcoke-fired	merchant	generation	facility	in	Texas,	reported	in	the	North	America	Generation	segment, incurred	a	goodwill	impairment	of	$18	million.	The	Company	determined	that	there	was	an	impairment	indicator	for	Deepwater's	goodwill.	This	determination	was based	primarily	on	the	fact	that	Deepwater	did	not	operate	for	more	than	30	days	in	the	third	quarter	of	2010,	incurred	current	operating	and	cash	flow	losses	and,	at	that time,	was	forecasting	operating	and	cash	flow	losses	for	the	remainder	of	2010	through	2014.	This	resulted	from	a	decrease	in	future	power	price	expectations	and	an increase	in	pet	coke	prices	affecting	the	market.	The	Company	performed	the	two-step	goodwill	impairment	test	of	Deepwater's	goodwill	as	of	August	31,	2010	and recognized	the	entire	$18	million	carrying	amount	of	goodwill	as	goodwill	impairment.

In	2009,	Kilroot,	our	subsidiary	in	the	United	Kingdom,	reported	in	the	Europe	Generation	segment,	incurred	a	goodwill	impairment	loss	of	$118	million.	Kilroot is	a	generation	plant	fired	primarily	by	coal.	Factors	contributing	to	the	impairment	included:	reduced	profit	expectations	based	on	latest	estimates	of	future	commodity prices	and	reduced	expectations	on	the	recovery	of	cash	flows	on	the	existing	plant	following	the	Company's	decision	to	forgo	capital	expenditures	to	meet	emission allowance	requirements	taking	effect	in	2024.	Additionally,	one	of	our	subsidiaries	located	in	the	Ukraine	and	reported	within	"Corporate	and	Other"	incurred	a goodwill	impairment	loss	of	$4	million.	For	the	year	ended	December	31,	2008,	the	Company	had	no	goodwill	impairment.

The	following	tables	summarize	the	balances	comprising	other	intangible	assets	in	the	accompanying	Consolidated	Balance	Sheets	as	of	December	31,	2010	and 2009:

|  | December	31,	2010 | December	31,	2010 | December	31,	2010 | December	31,	2009 | December	31,	2009 | December	31,	2009 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Gross | Accumulated | Net | Gross | Accumulated | Net |
|  | Balance | Amortization | Balance | Balance | Amortization | Balance |
|  |  | (in\tmillions) |  |  | (in\tmillions) |  |
| Subject\tto\tAmortization |  |  |  |  |  |  |
| Project\tdevelopment\trights^(1) | $141 | $— | $141 | $ — | $— | $ — |
| Sales\tconcessions | 162 | (88) | 74 | 167 | (84) | 83 |
| Contractual\tpayment\trights^(2) | 65 | (4) | 61 | — | — | — |
| Land\tuse\trights | 50 | (2) | 48 | 48 | (1) | 47 |
| Management\trights | 66 | (30) | 36 | 64 | (27) | 37 |
| Emission\tallowances^(3) | 26 | — | 26 | 18 | — | 18 |
| Inseparable\tintangible\tassets^(4) | 8 | (4) | 4 | 253 | (83) | 170 |
| Other^(5) | 94 | (32) | 62 | 118 | (28) | 90 |
| Subtotal | 612 | (160) | 452 | 668 | (223) | 445 |
| Indefinite-Lived\tIntangible\tAssets |  |  |  |  |  |  |
| Land\tuse\trights | 51 | — | 51 | 50 | — | 50 |
| Emission\tallowances^(6) | 8 | — | 8 | 15 | — | 15 |
| Other | 5 | — | 5 | — | — | — |
| Subtotal | 64 | — | 64 | 65 | — | 65 |
| Total | $676 | $(160) | $516 | $733 | $(223) | $510 |

Represent	development	rights,	including	but	not	limited	to,	land	control,	various	permits	and	right	to	acquire	equity	interests	in	development	projects	resulting from	asset	acquisitions	by	our	Wind	group.

Represent	legal	rights	to	receive	system	reliability	payments	from	the	regulator.

Acquired	or	purchased	emission	allowances	are	expensed	when	utilized	and	included	in	net	income	for	the	year.

Represent	various	intangible	assets	relating	to	an	asset	acquisition	in	the	state	of	New	York	in	1999.	During	the	fourth	quarter	of	2010,	the	unamortized	amount	of $158	million	was	recognized	as	impairment	expense	as	part	of	Eastern	Energy	long-lived	asset	impairment	evaluation.

Consists	of	various	intangible	assets	including	PPAs	and	transmission	rights,	none	of	which	is	individually	significant.

Represent	perpetual	emission	allowances	without	an	expiration	date.

The	following	table	summarizes,	by	category,	intangible	assets	acquired	during	the	years	ended	December	31,	2010	and	2009:

In	2009,	the	Company	reclassified	$42	million	from	other	assets	into	intangible	assets	at	a	subsidiary	in	Latin	America.

The	following	table	summarizes	the	estimated	amortization	expense,	broken	down	by	intangible	asset	category,	for	2011	through	2015:

|  |  | Estimated	amortization	expense | Estimated	amortization	expense | Estimated	amortization	expense |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2011 | 2012 | 2013 | 2014 | 2015 |
|  |  |  | (in\tmillions) |  |  |
| Contractual\tpayment\trights | $9 | $9 | $9 | $9 | $9 |
| Sales\tconcessions | 6 | 6 | 6 | 6 | 6 |
| All\tother | 7 | 6 | 5 | 4 | 4 |
| Total | $22 | $21 | $20 | $19 | $19 |

Intangible	asset	amortization	expense	was	$21	million,	$24	million	and	$19	million	for	the	years	ended	December	31,	2010,	2009	and	2008,	respectively.

# 9.	REGULATORY	ASSETS	&	LIABILITIES

The	Company	has	recorded	regulatory	assets	and	liabilities	that	it	expects	to	pass	through	to	its	customers	in	accordance	with,	and	subject	to,	regulatory provisions	as	follows:

| Energy	purchases | $62 | $144 | Over	tariff	reset	period |
| :--- | :--- | :--- | :--- |
| Transmission\tcosts,\tregulatory\tfees\tand\tother | 82 | 120 | Over\ttariff\treset\tperiod |
| El\tSalvador\ttariff\trecoveries^(2) | 67 | 125 | \tOver\ttariff\treset\tperiod |
| Other^(3) | 1 | 6 | \tVarious |
| Total\tcurrent\tregulatory\tassets | 212 | 395 |  |
| Noncurrent\tregulatory\tassets: |  |  |  |
| Defined\tbenefit\tpension\tobligations\tat\tIPL^(4)(5) | 235 | 217 | \tVarious |
| Income\ttaxes\trecoverable\tfrom\tcustomers^(4)(6) | 66 | 70 | \tVarious |
| Brazil\ttariff\trecoveries:^(1) |  |  |  |
| Energy\tpurchases | 18 | 22 | \tOver\ttariff\treset\tperiod |
| Transmission\tcosts,\tregulatory\tfees\tand\tother | 32 | 30 | \tOver\ttariff\treset\tperiod |
| Other^(3) | 119 | 111 | \tVarious |
| Total\tnoncurrent\tregulatory\tassets | 470 | 450 |  |
| TOTAL\tREGULATORY\tASSETS | $682 | $845 |  |
| REGULATORY\tLIABILITIES |  |  |  |
| Current\tregulatory\tliabilities: |  |  |  |
| Efficiency\tprogram\tcosts^(7) | $58 | $133 | \tOver\ttariff\treset\tperiod |
| Brazil\ttariff\trecoveries:^(1) |  |  |  |
| Energy\tpurchases | 118 | 61 | \tOver\ttariff\treset\tperiod |
| Transmission\tcosts,\tregulatory\tfees\tand\tother | 71 | 67 | \tOver\ttariff\treset\tperiod |
| Other^(8) | 39 | 35 | \tVarious |
| Total\tcurrent\tregulatory\tliabilities | 286 | 296 |  |
| Noncurrent\tregulatory\tliabilities: |  |  |  |
| Asset\tretirement\tobligations^(9) | 509 | 482 | \tOver\tlife\tof\tassets |
| Brazil\tspecial\tobligations^(10) | 435 | 402 | \tTo\tbe\tdetermined |
| Brazil\ttariff\trecoveries:^(1) |  |  |  |
| Energy\tpurchases | 69 | 42 | \tOver\ttariff\treset\tperiod |
| Transmission\tcosts,\tregulatory\tfees\tand\tother | 57 | 35 | \tOver\ttariff\treset\tperiod |
| Efficiency\tprogram\tcosts^(7) | 54 | 4 | \tOver\ttariff\treset\tperiod |
| Other^(8) | 13 | 17 | \tVarious |
| Total\tnoncurrent\tregulatory\tliabilities | 1,137 | 982 |  |
| TOTAL\tREGULATORY\tLIABILITIES | $1,423 | $1,278 |  |

(1) Recoverable	per	National	Electric	Energy	Agency	("ANEEL")	regulations	through	the	Annual	Tariff	Adjustment	("IRT").	These	costs	are	generally	non- controllable	costs	and	primarily	consist	of	purchased	electricity,	energy	transmission	costs	and	sector	costs	that	are	considered	volatile.	These	costs	are	recovered in	24	installments	through	the	annual	IRT	process	and	are	amortized	over	the	tariff	reset	period.

(2) Deferred	fuel	costs	incurred	by	our	El	Salvador	subsidiaries	associated	with	purchase	of	energy	from	the	El	Salvador	spot	market	and	the	power	generation	plants. In	El	Salvador,	the	deferred	fuel	adjustment	represents	the	variance	between	the	actual	fuel	costs	and	the	fuel	costs	recovered	in	the	tariffs.	The	variance	is recovered	semi-annually	at	the	tariff	reset	period.

(3) Includes	assets	with	and	without	a	rate	of	return.	All	current	regulatory	assets	earned	a	rate	of	return	as	of	December	31,	2010	and	2009.	Other	noncurrent regulatory	assets	that	did	not	earn	a	rate	of	return	were	$95	million	and	$90	million,	as	of	December	31,	2010	and	2009,	respectively.	Those	without	a	rate	of return	that	are	recoverable	primarily	consist	of	transmission	service	costs	and	other	administrative	costs	from	IPL's	participation	in	the	Midwest	ISO	market. Recovery	of	costs	is	probable,	but	the	timing	is	not	yet	determined.

(4) Past	expenditures	on	which	the	Company	does	not	earn	a	rate	of	return.

(5) The	regulatory	accounting	standards	allow	the	defined	pension	and	postretirement	benefit	obligation	to	be	recorded	as	a	regulatory	asset	equal	to	the	previously unrecognized	actuarial	gains	and	losses	and	prior	service	costs	that	are	expected	to	be	recovered	through	future	rates.	Pension	expense	is	recognized	based	on	the plan's	actuarially	determined	pension	liability.	Recovery	of	costs	is	probable,	but	not	yet	determined.	Pension	contributions	made	by	our	Brazilian	subsidiaries are	not	included	in	regulatory	assets	as	those	contributions	are	not	covered	by	the	established	tariff	in	Brazil.

(6) Probable	of	recovery	through	future	rates,	based	upon	established	regulatory	practices,	which	permit	the	recovery	of	current	taxes.	This	amount	is	expected	to	be recovered,	without	interest,	over	the	period	as	book-tax	temporary	differences	reverse	and	become	current	taxes.

(7) Payments	received	for	costs	expected	to	be	incurred	to	improve	the	efficiency	of	our	plants	in	Brazil	that	are	refunded	as	part	of	the	IRT.

(8) Other	Current	and	Noncurrent	Regulatory	Liabilities	consist	of:

•	 Deferred	fuel	costs,	which	are	expected	to	be	refunded	to	customers	as	a	credit	against	future	fuel	adjustment	charges.	In	the	United	States,	deferred	fuel costs	at	IPL	represent	variances	between	estimated	and	actual	fuel	and	purchased	power	costs.	IPL	is	required	to	refund	overestimated	fuel	and	purchased power	costs	in	future	rates.

•Penalties	and	fees	from	regulators	at	our	Brazilian	subsidiaries.

•Financial	transmission	rights	used	to	hedge	exposure	in	the	Midwest	ISO	market	that	are	credited	per	specific	rate	orders.

•The	cost	incurred	by	electricity	generators	due	to	variance	in	energy	prices	during	rationing	periods	(Free	Energy).	Our	Brazilian	subsidiaries	are	authorized to	recover	or	refund	this	cost	associated	with	monthly	energy	price	variances	between	the	wholesale	energy	market	prices	owed	to	the	power	generation plants	producing	Free	Energy	and	the	capped	price	reimbursed	by	the	local	distribution	companies	which	are	passed	through	to	the	final	customers	through energy	tariffs.

(9) Obligations	for	removal	costs	which	do	not	have	an	associated	legal	retirement	obligation	as	defined	by	the	accounting	standards	on	asset	retirement	obligations.

(10) Obligations	established	by	ANEEL	in	Brazil	associated	with	electric	utility	concessions	and	represent	amounts	received	from	customers	or	donations	not	subject to	return.	These	donations	are	allocated	to	support	energy	network	expansion	and	to	improve	utility	operations	to	meet	customers'	needs.	The	term	of	the obligation	is	established	by	ANEEL.	Settlement	shall	occur	when	the	concession	ends.

The	current	regulatory	assets	and	liabilities	are	recorded	in	"Other	current	assets"	and	"Accrued	and	other	liabilities,"	respectively,	on	the	accompanying Consolidated	Balance	Sheets.	The	noncurrent	regulatory	assets	and	liabilities	are	recorded	in	"Other	assets"	and	"Other	long-term	liabilities,"	respectively,	in	the accompanying	Consolidated	Balance	Sheets.

The	following	table	summarizes	regulatory	assets	by	region	as	of	December	31,	2010	and	2009:

|  | 2010 | 2009 |
| :--- | :--- | :--- |
|  | (in\tmillions) |  |
| Latin\tAmerica | $265 | $445 |
| North\tAmerica | \t 417 | \t 400 |
| Total\tregulatory\tassets | $682 | $845 |

The	following	table	summarizes	regulatory	liabilities	by	region	as	of	December	31,	2010	and	2009:

|  | December	31,<br>2010 | 2009 |
| :--- | :--- | :--- |
|  | (in\tmillions) |  |
| Latin\tAmerica | $897 | $772 |
| North\tAmerica | 526 | 506 |
| Total\tregulatory\tliabilities | $1,423 | $1,278 |

The	Company	has	two	types	of	debt	reported	on	its	Consolidated	Balance	Sheets:	non-recourse	and	recourse	debt.	Non-recourse	debt	is	used	to	fund	investments and	capital	expenditures	for	the	construction	and	acquisition	of	electric	power	plants,	wind	projects,	distribution	companies	and	other	project-related	investments	at	our subsidiaries.	Non-recourse	debt	is	generally	secured	by	the	capital	stock,	physical	assets,	contracts	and	cash	flows	of	the	related	subsidiary.	Absent	guarantees, intercompany	loans	or	other	credit	support,	the	default	risk	is	limited	to	the	respective	business	and	is	without	recourse	to	the	Parent	Company	and	other	subsidiaries, though	the	Company's	equity	investments	and/or	subordinated	loans	to	projects	(if	any)	are	at	risk.	Recourse	debt	is	direct	borrowings	by	the	Parent	Company	and	is used	to	fund	development,	construction	or	acquisitions,	including	serving	as	funding	for	equity	investments	or	loans	to	the	affiliates.	The	Parent	Company's	debt	is, among	other	things,	recourse	to	the	Parent	Company	and	is	structurally	subordinated	to	the	affiliates'	debt.

The	following	table	summarizes	the	carrying	amount	and	estimated	fair	values	of	the	Company's	recourse	and	non-recourse	debt	as	of	December	31,	2010	and 2009:

|  |  | December	31, |  |  |
| :--- | :--- | :--- | :--- | :--- |
|  | 2010 |  | 2009 | 2009 |
|  | Carrying\nAmount | Fair\nValue | Carrying\nAmount | Fair\nValue |
|  |  | (in\tmillions) |  |  |
| Non-recourse\tdebt | $15,121 | $15,471 | $ 14,022 | $14,405 |
| Recourse\tdebt | 4,612 | 4,868 | 5,515 | 5,603 |
| Total\tdebt | $19,733 | $20,339 | $ 19,537 | $20,008 |

Recourse	and	non-recourse	debt	are	carried	at	amortized	cost.	The	fair	value	of	recourse	debt	is	estimated	based	on	quoted	market	prices.	The	fair	value	of	non- recourse	debt	is	estimated	differently	based	upon	the	type	of	loan.	The	fair	value	of	fixed	rate	loans	is	estimated	using	quoted	market	prices,	if	available	or	a	discounted cash	flow	analysis.	In	the	discounted	cash	flow	analysis,	the	discount	rate	is	based	on	the	credit	rating	of	the	individual	debt	instruments	if	available,	or	the	credit	rating of	the	subsidiary.	If	the	subsidiary's	credit	rating	is	not	available,	a	synthetic	credit	rating	is	determined	using	certain	key	metrics,	including	cash	flow	ratios	and	interest coverage,	as	well	as	other	industry	specific	factors.	For	subsidiaries	located	outside	of	the	U.S.,	in	the	event	that	the	country	rating	is	lower	than	the	credit	rating previously	determined,	the	country	rating	is	used	for	the	purposes	of	the	discounted	cash	flow	analysis.	The	fair	value	of	recourse	and	non-recourse	debt	excludes accrued	interest	at	the	valuation	date.

The	estimated	fair	value	was	determined	using	available	market	information	as	of	December	31,	2010	and	2009.	The	Company	is	not	aware	of	any	factors	that would	significantly	affect	the	estimated	fair	value	amounts	since	December	31,	2010.

The	following	table	summarizes	the	carrying	amount	and	terms	of	non-recourse	debt	as	of	December	31,	2010	and	2009:

| NON-RECOURSE	DEBT | NON-RECOURSE	DEBT | Interest<br>Rate^(1) | Maturity | 2010 | 2009 |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | (in\tmillions) |  |
| VARIABLE\tRATE:^(2) |  |  |  |  |  |
| Bank\tloans |  | 2.39% | \t2011\t–\t2027 | $3,840 | $3,118 |
| Notes\tand\tbonds | Notes\tand\tbonds | \t12.14% | \t2011\t–\t2020 | 2,982 | 1,922 |
| Debt\tto\t(or\tguaranteed\tby)\tmultilateral,\texport\tcredit\tagencies\tor\tdevelopment\tbanks | (3) | 2.95% | \t2011\t–\t2027 | 1,848 | 1,679 |
| Other | Other | 4.13% | \t2011\t–\t2038 | 365 | 922 |
| FIXED\tRATE: |  |  |  |  |  |
| Bank\tloans | Bank\tloans | 8.44% | \t2011\t–\t2023 | 424 | 446 |
| Notes\tand\tbonds |  | 7.35% | \t2011\t–\t2037 | 5,007 | 5,450 |
| Debt\tto\t(or\tguaranteed\tby)\tmultilateral,\texport\tcredit\tagencies\tor\tdevelopment\tbanks | (3) | 6.41% | \t2011\t–\t2027 | 467 | 406 |
| Other |  | 6.32% | \t2011\t–\t2039 | 188 | 79 |
| SUBTOTAL | SUBTOTAL |  |  | $15,121^(4) | $14,022^(4) |
| Less:\tCurrent\tmaturities |  |  |  | (2,577) | (1,718) |
| TOTAL | TOTAL |  |  | $12,544 | $12,304 |

(1) Weighted	average	interest	rate	at	December	31,	2010.

(2) The	Company	has	interest	rate	swaps	and	interest	rate	option	agreements	in	an	aggregate	notional	principal	amount	of	approximately	$4.3	billion	on	non-recourse debt	outstanding	at	December	31,	2010.	The	swap	agreements	economically	change	the	variable	interest	rates	on	the	portion	of	the	debt	covered	by	the	notional amounts	to	fixed	rates	ranging	from	approximately	0.71%	to	6.98%.	The	option	agreements	fix	interest	rates	within	a	range	from	4.03%	to	7.00%.	The	agreements expire	at	various	dates	from	2016	through	2027.

(3) Multilateral	loans	include	loans	funded	and	guaranteed	by	bilaterals,	multilaterals,	development	banks	and	other	similar	institutions.

(4) Non-recourse	debt	of	$708	million	as	of	December	31,	2009	was	excluded	from	non-recourse	debt	and	included	in	current	and	long-term	liabilities	of	held	for sale	and	discontinued	businesses	in	the	accompanying	Consolidated	Balance	Sheets.

Non-recourse	debt	as	of	December	31,	2010	is	scheduled	to	reach	maturity	as	set	forth	in	the	table	below:

As	of	December	31,	2010,	AES	subsidiaries	with	facilities	under	construction	had	a	total	of	approximately	$432	million	of	committed	but	unused	credit	facilities available	to	fund	construction	and	other	related	costs.	Excluding	these	facilities	under	construction,	AES	subsidiaries	had	approximately	$893	million	in	a	number	of available	but	unused	committed	revolving	credit	lines	to	support	their	working	capital,	debt	service	reserves	and	other	business	needs.	These	credit	lines	can	be	used	in one	or	more	of	the	following	ways:	solely	for	borrowings;	solely	for	letters	of	credit;	or	a	combination	of	these	uses.	The	weighted	average	interest	rate	on	borrowings from	these	facilities	was	3.24%	at	December	31,	2010.

# Non-Recourse	Debt	Covenants,	Restrictions	and	Defaults

The	terms	of	the	Company's	non-recourse	debt	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.	Compliance	with	certain	covenants	may	not	be	objectively	determinable.

As	of	December	31,	2010	and	2009,	approximately	$803	million	and	$653	million,	respectively,	of	restricted	cash	was	maintained	in	accordance	with	certain covenants	of	the	non-recourse	debt	agreements,	and	these	amounts	were	included	within	"Restricted	cash"	and	"Debt	service	reserves	and	other	deposits"	in	the accompanying	Consolidated	Balance	Sheets.

Various	lender	and	governmental	provisions	restrict	the	ability	of	certain	of	the	Company's	subsidiaries	to	transfer	their	net	assets	to	the	Parent	Company.	Such restricted	net	assets	of	subsidiaries	amounted	to	approximately	$5.4	billion	at	December	31,	2010.

The	following	table	summarizes	the	Company's	subsidiary	non-recourse	debt	in	default	or	accelerated	as	of	December	31,	2010	and	is	included	in	the	current portion	of	non-recourse	debt	unless	otherwise	indicated:

|  | Primary	Nature | December	31,	2010 | December	31,	2010 |
| :--- | :--- | :--- | :--- |
| Subsidiary | of\t\tDefault | Default | Net\tAssets |
|  |  | (in\tmillions) |  |
| Maritza | Covenant | $986 | $262 |
| Sonel | Covenant | 390 | 357 |
| Kelanitissa | Covenant | 28 | 31 |
| Aixi | Payment | 4 | (8) |
| Total |  | $1,408 |  |

None	of	the	subsidiaries	that	are	currently	in	default	are	subsidiaries	that	met	the	applicable	definition	of	materiality	under	AES'	corporate	debt	agreements	as	of December	31,	2010	in	order	for	such	defaults	to	trigger	an	event	of	default	or	permit	acceleration	under	such	indebtedness.	The	bankruptcy	or	acceleration	of	material amounts	of	debt	at	such	entities	would	cause	a	cross	default	under	the	recourse	senior	secured	credit	facility.	However,	as	a	result	of	additional	dispositions	of	assets, other	significant	reductions	in	asset	carrying	values	or	other	matters	in	the	future	that	may	impact	our	financial	position	and	results	of	operations	or	the	financial	position or	results	of	the	individual	subsidiary,	it	is	possible	that	one	or	more	of	these	subsidiaries	could	fall	within	the	definition	of	a	"material	subsidiary"	and	thereby	upon	a bankruptcy	or	acceleration	of	its	non-recourse	debt	trigger	an	event	of	default	and	possible	acceleration	of	the	indebtedness	under	the	AES	Parent	Company's outstanding	debt	securities.

The	following	table	summarizes	the	carrying	amount	and	terms	of	recourse	debt	of	the	Company	as	of	December	31,	2010	and	2009:

| Senior	Unsecured	Note | 9.375% | 2010 | $— | $214 |
| :--- | :--- | :--- | :--- | :--- |
| Senior\tSecured\tTerm\tLoan | \tLIBOR\t+\t1.75% | 2011 | 200 | 200 |
| Senior\tUnsecured\tNote | \t8.875% | 2011 | 129 | 129 |
| Senior\tUnsecured\tNote | \t8.375% | 2011 | 134 | 139 |
| Second\tPriority\tSenior\tSecured\tNote | \t8.75% | 2013 | — | 690 |
| Senior\tUnsecured\tNote | \t7.75% | 2014 | 500 | 500 |
| Senior\tUnsecured\tNote | \t7.75% | 2015 | 500 | 500 |
| Senior\tUnsecured\tNote | \t9.75% | 2016 | 535 | 535 |
| Senior\tUnsecured\tNote | \t8.00% | 2017 | \t 1,500 | \t 1,500 |
| Senior\tUnsecured\tNote | \t8.00% | 2020 | 625 | 625 |
| Term\tConvertible\tTrust\tSecurities | \t6.75% | 2029 | 517 | 517 |
| Unamortized\tdiscounts |  |  | (28) | (34) |
| SUBTOTAL |  |  | $4,612 | $5,515 |
| Less:\tCurrent\tmaturities |  |  | (463) | (214) |
| Total |  |  | $4,149 | $5,301 |

Recourse	debt	as	of	December	31,	2010	is	scheduled	to	reach	maturity	as	set	forth	in	the	table	below:

| December	31, | Annual	Maturities |
| :--- | :--- |
|  | (in\tmillions) |
| 2011 | $463 |
| 2012 | — |
| 2013 | — |
| 2014 | 497 |
| 2015 | 500 |
| Thereafter | 3,152 |
| Total\trecourse\tdebt | $4,612 |

On	July	29,	2010,	the	Company	entered	into	a	second	amendment	("Amendment	No.	2")	to	the	Fourth	Amended	and	Restated	Credit	and	Reimbursement Agreement,	dated	as	of	July	29,	2008,	among	the	Company,	various	subsidiary	guarantors	and	various	lending	institutions	(the	"Existing	Credit	Agreement")	that amends	and	restates	the	Existing	Credit	Agreement	(as	so	amended	and	restated	by	Amendment	No.	2,	the	"Fifth	Amended	and	Restated	Credit	Agreement").	The	Fifth Amended	and	Restated	Credit	Agreement	adjusted	the	terms	and	conditions	of	the	Existing	Credit	Agreement,	including	the	following	changes:

•changes	to	the	facility	fee	applicable	to	the	revolving	credit	loan	facility;

# Recourse	Debt	Covenants	and	Guarantees

Certain	of	the	Company's	obligations	under	the	senior	secured	credit	facility	are	guaranteed	by	its	direct	subsidiaries	through	which	the	Company	owns	its interests	in	the	AES	Shady	Point,	AES	Hawaii,	AES	Warrior	Run	and	AES	Eastern	Energy	businesses.	The	Company's	obligations	under	the	senior	secured	credit facility	are,	subject	to	certain	exceptions,	secured	by:

(i) all	of	the	capital	stock	of	domestic	subsidiaries	owned	directly	by	the	Company	and	65%	of	the	capital	stock	of	certain	foreign	subsidiaries	owned	directly or	indirectly	by	the	Company;	and

(ii) certain	intercompany	receivables,	certain	intercompany	notes	and	certain	intercompany	tax	sharing	agreements.

The	senior	secured	credit	facility	is	subject	to	mandatory	prepayment	under	certain	circumstances,	including	the	sale	of	a	guarantor	subsidiary.	In	such	a	situation, the	net	cash	proceeds	from	the	sale	of	a	Guarantor	or	any	of	its	subsidiaries	must	be	applied	pro	rata	to	repay	the	term	loan	using	60%	of	net	cash	proceeds,	reduced	to 50%	when	and	if	the	parent's	recourse	debt	to	cash	flow	ratio	is	less	than	5:1.	The	lenders	have	the	option	to	waive	their	pro	rata	redemption.

The	senior	secured	credit	facility	contains	customary	covenants	and	restrictions	on	the	Company's	ability	to	engage	in	certain	activities,	including,	but	not	limited to,	limitations	on	other	indebtedness,	liens,	investments	and	guarantees;	limitations	on	restricted	payments	such	as	shareholder	dividends	and	equity	repurchases; restrictions	on	mergers	and	acquisitions,	sales	of	assets,	leases,	transactions	with	affiliates	and	off-balance	sheet	or	derivative	arrangements;	and	other	financial	reporting requirements.

The	senior	secured	credit	facility	also	contains	financial	covenants	requiring	the	Company	to	maintain	certain	financial	ratios	including	a	cash	flow	to	interest coverage	ratio,	calculated	quarterly,	which	provides	that	a	minimum	ratio	of	the	Company's	adjusted	operating	cash	flow	to	the	Company's	interest	charges	related	to recourse	debt	of	1.3×	must	be	maintained	at	all	times	and	a	recourse	debt	to	cash	flow	ratio,	calculated	quarterly,	which	provides	that	the	ratio	of	the	Company's	total recourse	debt	to	the	Company's	adjusted	operating	cash	flow	must	not	exceed	a	maximum	at	any	time	of	calculation,	or	7.5×	at	December	31,	2010.

The	terms	of	the	Company's	senior	unsecured	notes	and	senior	secured	credit	facility	contain	certain	covenants	including,	without	limitation,	limitation	on	the Company's	ability	to	incur	liens	or	enter	into	sale	and	leaseback	transactions.

# TERM	CONVERTIBLE	TRUST	SECURITIES

Between	1999	and	2000,	AES	Trust	III,	a	wholly	owned	special	purpose	business	trust,	issued	approximately	10.35	million	of	$3.375	Term	Convertible	Preferred Securities	("TECONS")	(liquidation	value	$50)	for	total	proceeds	of	$517	million	and	concurrently	purchased	$517	million	of	6.75%	Junior	Subordinated	Convertible Debentures	due	2029	(the	"6.75%	Debentures"	of	the	Company).	The	TECONS	are	consolidated	and	classified	as	long-term	recourse	debt	on	the	Company's Consolidated	Balance	Sheet.

AES,	at	its	option,	can	redeem	the	6.75%	Debentures	which	would	result	in	the	required	redemption	of	the	TECONS	issued	by	AES	Trust	III,	currently	for	$50 per	TECON.	The	TECONS	must	be	redeemed	upon	maturity	of	the	6.75%	Debentures.	The	TECONS	are	convertible	into	the	common	stock	of	AES	at	each	holder's option	prior	to	October	15,	2029	at	the	rate	of	1.4216,	representing	a	conversion	price	of	$35.17	per	share.	The	maximum	number	of	shares	of	common	stock	AES would	be	required	to	issue	should	all	holders	decide	to	convert	their	securities	would	be	14.7	million	shares.

Dividends	on	the	TECONS	are	payable	quarterly	at	an	annual	rate	of	6.75%.	The	Trust	is	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.	AES	has	not exercised	the	option	to	defer	any	dividends	at	this	time	and	all	dividends	due	under	the	Trust	have	been	paid.

AES	Trust	III	is	a	VIE	under	the	relevant	consolidation	accounting	guidance.	AES'	obligations	under	the	6.75%	Debentures	and	other	relevant	trust	agreements, in	aggregate,	constitute	a	full	and	unconditional	guarantee	by	AES	of	the	TECON	Trusts'	obligations.	Accordingly,	AES	consolidates	AES	Trust	III.	As	of December	31,	2010	and	2009,	the	sole	assets	of	AES	Trust	III	are	the	6.75%	Debentures.

# 11.	COMMITMENTS

OPERATING	LEASES—As	of	December	31,	2010,	the	Company	was	obligated	under	long-term	non-cancelable	operating	leases,	primarily	for	certain transmission	lines,	office	rental	and	site	leases.	Rental	expense	for	lease	commitments	under	these	operating	leases	for	the	years	ended	December	31,	2010,	2009	and 2008	was	$58	million,	$63	million	and	$74	million,	respectively.

The	table	below	sets	forth	the	future	minimum	lease	commitments	under	these	operating	leases	as	of	December	31,	2010	for	2011	through	2015	and	thereafter:

CAPITAL	LEASES—Several	AES	subsidiaries	lease	operating	and	office	equipment	and	vehicles	that	are	considered	capital	lease	transactions.	These	capital leases	are	recognized	in	Property,	Plant	and	Equipment	within	"Electric	generation	and	distribution	assets"	and	primarily	relate	to	transmission	lines	at	our	subsidiaries in	Brazil.	The	gross	value	of	the	leased	assets	as	of	December	31,	2010	and	2009	was	$99	million	and	$106	million,	respectively.

The	following	table	summarizes	the	future	minimum	lease	payments	under	capital	leases	together	with	the	present	value	of	the	net	minimum	lease	payments	as	of December	31,	2010	for	2011	through	2015	and	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.	In	May	2007,	the	subsidiary	purchased	a	portion	of	the	lessor's	interest in	a	trust	estate	that	holds	the	leased	plants.	Future	minimum	lease	commitments	under	the	lease	agreement	are	reduced	by	the	subsidiary's	interest	in	the	plants.	Rental expense	was	$34	million	for	each	of	the	years	ended	December	31,	2010,	2009	and	2008.

The	following	table	summarizes	the	future	minimum	lease	commitments	under	the	sale/leaseback	arrangement	as	of	December	31,	2010	for	2011	through	2015 and	thereafter:

CONTRACTS—Operating	subsidiaries	of	the	Company	have	entered	into	contracts	for	the	purchase	of	electricity	from	third	parties	that	primarily	include energy	auction	agreements	at	our	Brazil	subsidiaries	with	extended	terms	from	2011	through	2042	and	in	some	cases	are	subject	to	variable	quantities	or	prices. Purchases	in	the	years	ended	December	31,	2010,	2009	and	2008	were	approximately	$2.4	billion,	$2.1	billion	and	$1.5	billion,	respectively.

The	table	below	sets	forth	the	future	minimum	commitments	under	these	electricity	purchase	contracts	at	December	31,	2010	for	2011	through	2015	and 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	and	in	some	cases	are	subject	to	variable	quantities	or	prices.	Purchases	in	the	years	ended	December	31,	2010,	2009	and	2008	were	$1.9	billion, $1.3	billion	and	$1.3	billion,	respectively.

The	table	below	sets	forth	the	future	minimum	commitments	under	these	fuel	contracts	as	of	December	31,	2010	for	2011	through	2015	and	thereafter:

The	Company's	subsidiaries	have	entered	into	other	various	long-term	contracts.	These	contracts	are	mainly	for	construction	projects,	service	and	maintenance, transmission	of	electricity	and	other	operation	services.	Payments	under	these	contracts	for	the	years	ended	December	31,	2010,	2009	and	2008	were	$1.7	billion, $2.8	billion	and	$1.9	billion,	respectively.

The	table	below	sets	forth	the	future	minimum	commitments	under	these	other	purchase	contracts	as	of	December	31,	2010	for	2011	through	2015	and	thereafter:

# 12.	CONTINGENCIES

# ENVIRONMENTAL	LIABILITIES

The	Company	will	record	liabilities	when	an	environmental	assessment	indicates	that	remedial	actions	are	probable	and	that	costs	can	be	reasonably	estimated.	As of	December	31,	2010,	the	Company	has	recognized	liabilities	of	$28	million	for	estimated	environmental	remediation	costs	and	potential	fines	and	penalties.	These	are reported	on	the	Consolidated	Balance	Sheet	within	"accrued	and	other	liabilities"	and	"other	long-term	liabilities."	Due	to	the	uncertainties	associated	with environmental	assessment	and	remediation	activities,	actual	future	costs	of	compliance	or	remediation	could	be	higher	or	lower	than	the	amount	currently	accrued. Certain	expenditures	many	also	be	capitalized	in	accordance	with	the	Company's	property,	plant	and	equipment	policies	and	are	excluded	from	environmental	liabilities in	accordance	with	accounting	guidelines.	Any	capital	expenditures	incurred	of	this	nature	would	be	incremental	to	amounts	reserved.

# ENVIRONMENTAL	REGULATION

The	Company	is	subject	to	numerous	environmental	laws	and	regulations	in	the	jurisdictions	in	which	it	operates.	The	Company	expenses	environmental regulation	compliance	costs	as	incurred	unless	the	underlying	expenditure	qualifies	for	capitalization	under	its	property,	plant	and	equipment	policies.	The	Company faces	certain	risks	and	uncertainties	related	to	these	environmental	laws	and	regulations,	including	existing	and	potential	greenhouse	gas	("GHG")	legislation	or regulations,	and	actual	or	potential	laws	and	regulations	pertaining	to	water	discharges,	waste	management	(including	disposal	of	coal	combustion	byproducts),	and certain	air	emissions,	such	as	SO ,	NO ,	particulate	matter	and	mercury.	Such	risks	and	uncertainties	could	result	in	increased	capital	expenditures	or	other	compliance costs	which	could	have	a	material	adverse	effect	on	certain	of	our	United	States	or	international	subsidiaries,	and	our	consolidated	results	of	operations.	For	further information	about	environmental	risks,	see	Item	1A.—Risk	Factors,	"Our	businesses	are	subject	to	stringent	environmental	laws	and	regulations,"	"Our	businesses	are subject	to	enforcement	initiatives	from	environmental	regulatory	agencies,"	and	"Regulators,	politicians,	non-governmental	organizations	and	other	private	parties	have expressed	concern	about	greenhouse	gas,	or	GHG,	emissions	and	the	potential	risks	associated	with	climate	change	and	are	taking	actions	which	could	have	a	material adverse	impact	on	our	consolidated	results	of	operations,	financial	condition	and	cash	flows."

# Legislation	and	Regulation	of	GHG	Emissions

Currently	in	the	United	States	there	is	no	Federal	legislation	establishing	mandatory	GHG	emissions	reduction	programs	(including	CO)	affecting	the	electric power	generation	facilities	of	the	Company's	subsidiaries.	There	are	numerous	state	programs	regulating	GHG	emissions	from	electric	power	generation	facilities	and there	is	a	possibility	that	federal	GHG	legislation	will	be	enacted	within	the	next	several	years.	Further,	the	EPA	has	adopted	regulations	pertaining	to	GHG	emissions and	has	announced	its	intention	to	propose	new	regulations	for	electric	generating	units	under	Section	111	of	the	United	States	Clean	Air	Act	("CAA").

Potential	United	States	Federal	GHG	Legislation.	Federal	legislation	passed	the	United	States	House	of	Representatives	in	2009	that,	if	adopted,	would	impose	a nationwide	cap-and-trade	program	to	reduce	GHG	emissions.	In	the	United	States	Senate,	several	different	draft	bills	pertaining	to	GHG	legislation	have	been considered	at	various	times	since	then,	including	comprehensive	GHG	legislation	similar	to	the	legislation	that	passed	the	United	States	House	of	Representatives	and more	limited	legislation	focusing	only	on	the	utility	and	electric	generation	industry.	It	is	uncertain	whether	any	such	legislation	or	any	new	legislation	pertaining	to GHG	emissions	will	be	voted	on	or	passed	by	the	Senate.	If	any	legislation	is	passed	by	the	Senate,	it	is	uncertain	whether	such	legislation	will	be	reconciled	with	the House	of	Representatives'	legislation	and	ultimately	enacted	into	law.	However,	if	any	such	legislation	is	enacted,	the	impact	could	be	material	to	the	Company.

The	EPA	promulgated	a	final	rule	on	June	3,	2010,	(the	"Tailoring	Rule")	that	sets	thresholds	for	GHG	emissions	that	would	trigger	PSD	permitting	requirements. The	Tailoring	Rule,	which	became	effective	in	January	of	2011,	provides	that	sources	already	subject	to	PSD	permitting	requirements	need	to	install	Best	Available Control	Technology	("BACT")	for	greenhouse	gases	if	a	proposed	modification	would	result	in	the	increase	of	more	than	75,000	tons	per	year	of	GHG	emissions.	Also, under	the	Tailoring	Rule,	commencing	in	July	of	2011,	any	new	sources	of	GHG	emissions	that	would	emit	over	100,000	tons	per	year	of	GHG	emissions,	in	addition	to any	modification	that	would	result	in	GHG	emissions	exceeding	75,000	tons	per	year	would	require	PSD	review	and	be	subject	to	related	permitting	requirements.	The EPA	anticipates	that	it	will	adjust	downward	the	permitting	thresholds	of	100,000	tons	and	75,000	tons	for	new	sources	and	modifications,	respectively,	in	future rulemaking	actions.	The	Tailoring	Rule	substantially	reduces	the	number	of	sources	subject	to	PSD	requirements	for	GHG	emissions	and	the	number	of	sources	required to	obtain	Title	V	air	permits,	although	new	thermal	power	plants	may	still	be	subject	to	PSD	and	Title	V	requirements	because	annual	GHG	emissions	from	such	plants typically	far	exceed	the	100,000	ton	threshold	noted	above.	The	75,000	ton	threshold	for	increased	GHG	emissions	from	modifications	to	existing	sources	may	reduce the	likelihood	that	future	modifications	to	plants	owned	by	some	of	our	United	States	subsidiaries	would	trigger	PSD	requirements,	although	some	projects	that would	expand	capacity	or	electric	output	are	likely	to	exceed	this	threshold,	and	in	any	such	cases	the	capital	expenditures	necessary	to	comply	with	the	PSD requirements	could	be	significant.

In	December	2010,	the	EPA	entered	into	a	settlement	agreement	with	several	states	and	environmental	groups	to	resolve	a	petition	for	review	challenging	EPA's new	source	performance	standards	("NSPS")	rulemaking	for	electric	utility	steam	generating	units	("EUSGUs")	based	on	the	NSPS'	failure	to	address	GHG	emissions. Under	the	settlement	agreement,	the	EPA	has	committed	to	propose	GHG	emissions	standards	for	EUSGUs	by	July	26,	2011	and	to	finalize	GHG	emissions	standards for	EUSGUs	by	May	26,	2012.	The	NSPS	will	establish	GHG	emission	standards	for	newly	constructed	and	reconstructed	EUSGUs.	The	NSPS	also	will	establish guidelines	regarding	the	best	system	for	achieving	further	GHG	emissions	reductions	from	EUSGUs	and,	based	on	such	guidelines,	individual	states	will	be	required	to submit	a	plan	to	the	EPA	to	establish	GHG	emission	standards	for	existing	EUSGUs	within	their	state.	It	is	impossible	to	estimate	the	impact	and	compliance	cost associated	with	any	future	NSPS	applicable	to	EUSGUs	until	such	regulations	are	finalized.	However,	the	compliance	costs	could	have	a	material	and	adverse	impact	on our	consolidated	financial	condition	or	results	of	operations.

Regional	Greenhouse	Gas	Initiative.	The	primary	regulation	of	GHG	emissions	affecting	the	United	States	plants	of	the	Company's	subsidiaries	has	been	through the	Regional	Greenhouse	Gas	Initiative	("RGGI").	Under	RGGI,	ten	Northeastern	States	have	coordinated	to	establish	rules	that	require	reductions	in	CO 	emissions from	power	plant	operations	within	those	states	through	a	cap-and-trade	program.	States	participating	in	RGGI	in	which	our	subsidiaries	have	generating	facilities include	Connecticut,	Maryland,	New	York	and	New	Jersey.	Under	RGGI,	power	plants	must	acquire	one	carbon	allowance	through	auction	or	in	the	emission	trading markets	for	each	ton	of	CO 	emitted.

In	July	2003,	the	European	Community	"Directive	2003/87/EC	on	Greenhouse	Gas	Emission	Allowance	Trading"	was	created,	which	requires	member	states	to limit	emissions	of	CO 	from	large	industrial	sources	within	their	countries.	To	do	so,	member	states	are	required	to	implement	EC-approved	national	allocation	plans ("NAPs").	Under	the	NAPs,	member	states	are	responsible	for	allocating	limited	CO 	allowances	within	their	borders.	Directive	2003/87/EC	does	not	dictate	how	these allocations	are	to	be	made,	and	NAPs	that	have	been	submitted	thus	far	have	varied	in	their	allocation	methodologies.	For	these	and	other	reasons,	uncertainty	remains with	respect	to	the	implementation	of	the	European	Union	Emissions	Trading	System	("EU	ETS")	that	commenced	in	January	2005.	The	European	Union	has announced	that	it	intends	to	keep	the	EU	ETS	in	place	after	2012,	even	if	the	Kyoto	Protocol	is	not	extended	or	replaced	by	another	agreement.	The	Company's subsidiaries	operate	eight

electric	power	generation	facilities,	and	another	subsidiary	has	one	under	construction,	within	six	member	states	which	have	adopted	NAPs	to	implement	Directive 2003/87/EC.	At	this	time,	the	Company	cannot	determine	fully	whether	achieving	and	maintaining	compliance	with	the	NAPs,	to	which	its	subsidiaries	are	subject,	will have	a	material	impact	on	its	consolidated	operations	or	results.	The	risk	and	benefit	associated	with	achieving	compliance	with	applicable	NAPs	at	several	facilities	of the	Company's	subsidiaries	are	not	the	responsibility	of	the	Company's	subsidiaries,	as	they	are	subject	to	contractual	provisions	that	transfer	the	costs	associated	with compliance	to	contract	counterparties.	However,	one	such	contract	counterparty,	GDF-Suez,	is	currently	disputing	these	provisions	with	AES	Energia	Cartagena	S.R.L. The	matter	has	been	submitted	to	arbitration	and	the	parties	are	currently	awaiting	a	decision.	See	Item	3.—Legal	Proceedings—in	this	Form	10-K	for	more	detail regarding	this	dispute.	In	connection	with	this	dispute	or	any	similar	dispute	that	might	arise	with	other	contract	counterparties,	there	can	be	no	assurance	that	the Company	and/or	the	relevant	subsidiary	would	prevail,	or	that	the	failure	to	prevail	in	any	such	dispute	will	not	have	a	material	adverse	effect	on	the	Company	and	its financial	condition	or	consolidated	results	of	operations.

On	February	16,	2005,	the	Kyoto	Protocol	became	effective.	The	Kyoto	Protocol	requires	the	industrialized	countries	that	have	ratified	it	to	significantly	reduce their	GHG	emissions,	including	CO .	The	vast	majority	of	developing	countries	which	have	ratified	the	Kyoto	Protocol	have	no	GHG	reduction	requirements,	including many	of	the	countries	in	which	the	Company's	subsidiaries	operate.	Of	the	28	countries	in	which	the	Company's	subsidiaries	currently	operate	all	but	one—the	United States	(including	Puerto	Rico)—have	ratified	the	Kyoto	Protocol.

In	addition	to	the	risks	and	uncertainties	related	to	GHG	regulations	or	potential	legislation,	the	Company	faces	certain	risks	and	uncertainties	related	to regulations	or	legislation	concerning	other	types	of	air	emissions.	In	the	United	States	the	CAA	and	various	state	laws	and	regulations	regulate	emissions	of	air pollutants,	including	SO ,	NO ,	particulate	matter	("PM"),	mercury	and	other	hazardous	air	pollutants	("HAPs").	The	applicable	rules	and	steps	taken	by	the	Company to	comply	with	the	rules	are	discussed	in	further	detail	below.

The	EPA	promulgated	the	"Clean	Air	Interstate	Rule"	("CAIR")	on	March	10,	2005,	which	required	allowance	surrender	for	SO	and	NO X,	emissions	from existing	power	plants	located	in	28	eastern	states	and	the	District	of	Columbia.	CAIR	was	subsequently	challenged	in	federal	court	on	July	11,	2008	and	the	United States	Court	of	Appeals	for	the	D.C.	Circuit	issued	an	opinion	striking	down	much	of	CAIR	and	remanding	it	to	the	EPA.

In	response	to	the	D.C.	Circuit's	opinion,	on	July	6,	2010,	the	EPA	issued	a	new	proposed	rule	(the	"Transport	Rule")	to	replace	CAIR.	The	final	Transport	Rule is	scheduled	to	be	issued	by	July	2011.	The	Clean	Air	Transport	Rule	would	require	significant	reductions	in	SO 	and	NO X	emissions	in	31	states	and	the	District	of Columbia	starting	in	2012,	including	several	states	where	subsidiaries	of	the	Company	conduct	business.

The	Transport	Rule	contemplates	three	possible	options	for	reducing	SO 	and	NO X	emissions	in	the	designated	states.	The	EPA's	preferred	option	contemplates	a set	limit	or	budget	on	SO 	and	NO X	emissions	for	each	of	the	states,	with	limited	interstate	trading	of	emissions	allowances	and	unlimited	intrastate	trading	of	SO	and NO X	emissions	allowances.	Affected	power	plants	would	receive	emissions	allowances	based	on	the	applicable	state	emissions	budgets.	The	EPA's	second	option	under the	Transport	Rule	would	establish	emission	budgets	for	each	state	but	only	allow	intrastate	trading	of	emissions	allowances.	The	final	option	would	set	emission	rate limitations	for	each	power	plant	but	would	allow	for	some	intrastate	averaging	of	emission	rates.	Under	any	of	the	proposed	options,	additional	air	emission	control technology	may	be	required	by	some	of	our	subsidiaries,	and	the	cost	of	implementing	any	such	technology	could	affect	the	financial	condition	or	results	of	operations of	these	subsidiaries	or	the	Parent	Company.	The	EPA	has	received	public	comments	on	the	Transport	Rule,	and	such	public	comments	will	be	considered	by	the	EPA prior	to	promulgating	a	final	rule.

In	July	1999,	the	EPA	published	the	"Regional	Haze	Rule"	to	reduce	haze	and	protect	visibility	in	designated	federal	areas.	On	June	15,	2005,	the	EPA	proposed amendments	to	the	Regional	Haze	Rule	that,	among	other	things,	set	guidelines	for	determining	when	to	require	the	installation	of	"best	available	retrofit	technology" ("BART")	at	older	plants.	The	amendment	to	the	Regional	Haze	Rule	required	states	to	consider	the	visibility	impacts	of	the	haze	produced	by	an	individual	facility,	in addition	to	other	factors,	when	determining	whether	that	facility	must	install	potentially	costly	emissions	controls.	States	were	required	to	submit	their	regional	haze	state implementation	plans	("SIPs")	to	the	EPA	by	December	2007,	but	only	13	states	met	this	deadline.	The	EPA	has	yet	to	approve	any	state's	Regional	Haze	state implementation	plan.	The	statute	requires	compliance	within	five	years	after	the	EPA	approves	the	relevant	SIP,	although	individual	states	may	impose	more	stringent compliance	schedules.

In	Europe,	the	Company	is,	and	will	continue	to	be,	required	to	reduce	air	emissions	from	our	facilities	to	comply	with	applicable	EC	Directives,	including Directive	2001/80/EC	on	the	limitation	of	emissions	of	certain	pollutants	into	the	air	from	large	combustion	plants	(the	"LCPD"),	which	sets	emission	limit	values	for NO X,	SO ,	and	particulate	matter	for	large-scale	industrial	combustion	plants	for	all	member	states.	Until	June	2004,	existing	coal	plants	could	"opt-in"	or	"opt-out"	of the	LCPD	emissions	standards.	Those	plants	that	opted	out	will	be	required	to	cease	all	operations	by	2015	and	may	not	operate	for	more	than	20,000	hours	after	2008. Those	that	opted-in,	like	the	Company's	AES	Kilroot	facility	in	the	United	Kingdom,	must	invest	in	abatement	technology	to	achieve	specific	SO 	reductions.	Kilroot installed	a	new	flue	gas	desulphurization	system	in	the	second	quarter	of	2009	in	order	to	satisfy	SO 	reduction	requirements.	The	Company's	other	coal	plants	in	Europe are	either	exempt	from	the	Directive	due	to	their	size	or	have	opted-in	but	will	not	require	any	additional	abatement	technology	to	comply	with	the	LCPD.

On	January	18	2011,	the	President	of	Chile	approved	a	new	air	emissions	regulation	submitted	to	him	by	the	national	environmental	regulatory	agency ("CONAMA").	The	new	regulation	establishes	limits	on	emissions	of	NO X,	SO ,	metals	and	particulate	matter	for	both	existing	and	new	thermal	power	plants,	with more	stringent	limitations	on	new	facilities.	The	regulation	will	become	effective	upon	approval	of	the	General	Comptroller	of	Chile.	The	regulation	will	require	AES Gener,	our	Chilean	subsidiary,	to	install	emissions	reduction	equipment	at	its	existing	thermal	plants	from	late	2011	through	2015.	The	exact	costs	of	compliance	with such	regulation	have

not	yet	been	determined	and	the	Company	believes	some	of	the	compliance	costs	are	contractually	passed	through	to	counterparties.	However,	the	compliance	costs could	be	material.

# Water	Discharges

The	Company	also	faces	certain	risks	and	uncertainties	related	to	environmental	laws	and	regulations	pertaining	to	water	discharge.	The	Company's	facilities	are subject	to	a	variety	of	rules	governing	water	discharges.	In	particular,	the	Company	is	subject	to	the	United	States	Clean	Water	Act	Section	316(b)	rule	regarding existing	power	plant	cooling	water	intake	structures	issued	by	the	EPA	in	2005	(69	Fed.	Reg.	41579,	July	9,	2004),	and	the	subsequent	Circuit	Court	of	Appeals	decision and	Supreme	Court	decision	regarding	this	rule.	The	rule	as	originally	issued	could	affect	12	of	the	Company's	United	States	power	plants	and	the	rule's	requirements would	be	implemented	via	each	plant's	National	Pollutant	Discharge	Elimination	System	("NPDES")	water	quality	permit	renewal	process.	These	permits	are	usually processed	by	state	water	quality	agencies.	To	protect	fish	and	other	aquatic	organisms,	the	2004	rule	requires	existing	steam	electric	generating	facilities	to	utilize	the best	technology	available	for	cooling	water	intake	structures.	To	comply,	a	steam	electric	generating	facility	must	first	prepare	a	Comprehensive	Demonstration	Study	to assess	the	facility's	effect	on	the	local	aquatic	environment.	Since	each	facility's	design,	location,	existing	control	equipment	and	results	of	impact	assessments	must	be taken	into	consideration,	costs	will	likely	vary.	The	timing	of	capital	expenditures	to	achieve	compliance	with	this	rule	will	vary	from	site	to	site.	On	January	25,	2007, the	United	States	Court	of	Appeals	for	the	Second	Circuit	decision	(Docket	Nos.	04-6692	to	04-6699)	vacated	and	remanded	major	parts	of	the	2004	rule	back	to	the EPA.	In	November	2007,	three	industry	petitioners	sought	review	of	the	Second	Circuit's	decision	by	the	United	States	Supreme	Court,	and	this	review	was	granted	by the	United	States	Supreme	Court	in	April	2008.	In	its	April	2009	decision,	the	United	States	Supreme	Court	granted	the	EPA	authority	to	use	a	cost-benefit	analysis when	setting	technology-based	requirements	under	Section	316(b)	of	the	Clean	Water	Act,	and	expressed	no	view	on	the	remaining	bases	for	the	Second	Circuit's remand.	New	draft	rule	316(b)	regulations	are	expected	to	be	proposed	by	the	EPA	by	March	14,	2011,	and	finalized	by	July	27,	2010.	Until	such	regulations	are	final, the	EPA	has	instructed	state	regulatory	agencies	to	use	their	best	professional	judgment	in	determining	how	to	evaluate	what	constitutes	best	technology	available	for minimizing	adverse	environmental	impacts	from	cooling	water	intake	structures.	Certain	states	in	which	the	Company	operates	power	generation	facilities,	such	as	New York,	have	been	delegated	authority	and	are	moving	forward	with	best	technology	available	determinations	in	the	absence	of	any	final	rule	from	the	EPA.	On September	27,	2010,	the	California	Office	of	Administrative	Law	approved	a	policy	adopted	by	the	California	Water	Resources	Control	Board	with	respect	to	power plant	cooling	water	intake	structures.	This	policy	became	effective	on	October	1,	2010	and	establishes	technology-based	standards	to	implement	Section	316(b)	of	the United	States	Clean	Water	Act.	At	this	time,	it	is	contemplated	that	the	Company's	Redondo	Beach,	Huntington	Beach	and	Alamitos	power	plants	in	California	will need	to	have	in	place	"best	technology	available"	by	December	31,	2020,	or	repower	the	facilities.	At	present,	the	Company	cannot	predict	the	final	requirements	under Section	316(b)	or	whether	compliance	with	the	anticipated	new	316(b)	rule	will	have	a	material	impact	on	our	operations	or	results,	but	the	Company	expects	that	capital investments	and/or	modifications	resulting	from	such	requirements	could	be	significant.

# Waste	Management

The	Company	also	faces	certain	risks	and	uncertainties	related	to	environmental	laws	and	regulations	pertaining	to	waste	management.	In	the	course	of operations,	the	Company's	facilities	generate	solid	and	liquid	waste	materials	requiring	eventual	disposal	or	processing.	With	the	exception	of	coal	combustion byproducts	("CCB"),	the	wastes	are	not	usually	physically	disposed	of	on	our	property,	but	are	shipped	off	site	for	final	disposal,	treatment	or	recycling.	CCB,	which consists	of	bottom	ash,	fly	ash	and	air	pollution	control	wastes,	is

disposed	of	at	some	of	our	coal-fired	power	generation	plant	sites	using	engineered,	permitted	landfills.	Waste	materials	generated	at	our	electric	power	and	distribution facilities	include	CCB,	oil,	scrap	metal,	rubbish,	small	quantities	of	industrial	hazardous	wastes	such	as	spent	solvents,	tree	and	land	clearing	wastes	and	polychlorinated biphenyl	contaminated	liquids	and	solids.	The	Company	endeavors	to	ensure	that	all	of	its	solid	and	liquid	wastes	are	disposed	of	in	accordance	with	applicable	national, regional,	state	and	local	regulations.	On	December	22,	2009,	a	dike	at	a	coal	ash	containment	area	at	the	Tennessee	Valley	Authority's	plant	in	Kingston,	Tennessee failed,	and	over	1	billion	gallons	of	ash	was	released	into	adjacent	waterways	and	properties.	Following	such	incident,	there	has	been	heightened	focus	on	the	regulation of	CCBs.	On	June	21,	2010,	the	EPA	published	in	the	Federal	Register	a	proposed	rule	to	regulate	CCB	under	the	Resource	Conservation	and	Recovery	Act	("RCRA"). The	proposed	rule	provides	two	possible	options	for	CCB	regulation,	both	options	contemplate	heightened	structural	integrity	requirements	for	surface	impoundments	of CCB.

The	first	option	contemplates	regulation	of	CCB	as	a	hazardous	waste	subject	to	regulation	under	Subtitle	C	of	the	RCRA.	Under	this	option,	existing	surface impoundments	containing	CCB	would	be	required	to	be	retrofitted	with	composite	liners	and	these	impoundments	would	likely	be	phased	out	over	several	years.	State and/or	federal	permit	programs	would	be	developed	for	storage,	transport	and	disposal	of	CCB.	States	could	bring	enforcement	actions	for	non-compliance	with permitting	requirements,	and	the	EPA	would	have	oversight	responsibilities	as	well	as	the	authority	to	bring	lawsuits	for	non-compliance.

The	second	option	contemplates	regulation	of	CCB	under	Subtitle	D	of	the	RCRA.	Under	this	option,	the	EPA	would	create	national	criteria	applicable	to	CCB landfills	and	surface	impoundments.	Existing	impoundments	would	also	be	required	to	be	retrofitted	with	composite	liners	and	would	likely	be	phased	out	over	several years.	This	option	would	not	contain	federal	or	state	permitting	requirements.	The	primary	enforcement	mechanism	under	regulation	pursuant	to	Subtitle	D	would	be private	lawsuits.

The	public	comment	period	for	this	proposed	regulation	has	expired,	and	the	EPA	is	required	to	consider	the	public	comments	prior	to	promulgating	a	final	rule. Requirements	under	a	final	rule	are	expected	to	become	effective	by	January	2012,	with	a	compliance	schedule	of	five	years.	While	the	exact	impact	and	compliance cost	associated	with	future	regulations	of	CCB	cannot	be	established	until	such	regulations	are	finalized,	there	can	be	no	assurance	that	the	Company's	businesses, financial	condition	or	results	of	operations	would	not	be	materially	and	adversely	affected	by	such	regulations.

# GUARANTEES,	LETTERS	OF	CREDIT

In	connection	with	certain	project	financing,	acquisition,	power	purchase	and	other	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.	In	the	normal	course	of	business,	AES	has	entered	into various	agreements,	mainly	guarantees	and	letters	of	credit,	to	provide	financial	or	performance	assurance	to	third	parties	on	behalf	of	AES	businesses.	These agreements	are	entered	into	primarily	to	support	or	enhance	the	creditworthiness	otherwise	achieved	by	a	business	on	a	stand-alone	basis,	thereby	facilitating	the availability	of	sufficient	credit	to	accomplish	their	intended	business	purposes.	Most	of	the	contingent	obligations	primarily	relate	to	future	performance	commitments which	the	Company	or	its	businesses	expect	to	fulfill	within	the	normal	course	of	business.	The	expiration	dates	of	these	guarantees	vary	from	less	than	one	year	to	more than	16	years.	In	addition	to	the	contingent	obligations	of	the	Parent	Company	identified	in	the	table	below,	the	Company's	subsidiaries	had	letters	of	credit	outstanding to	support	various	contingent	obligations.

The	following	table	summarizes	the	Parent	Company's	contingent	contractual	obligations	as	of	December	31,	2010.	Amounts	presented	in	the	table	below represent	the	Parent	Company's	current	undiscounted

exposure	to	guarantees	and	the	range	of	maximum	undiscounted	potential	exposure.	The	maximum	exposure	is	not	reduced	by	the	amounts,	if	any,	that	could	be recovered	under	the	recourse	or	collateralization	provisions	in	the	guarantees.	The	amounts	include	obligations	made	by	the	Parent	Company	for	the	direct	benefit	of	the lenders	associated	with	the	non-recourse	debt	of	businesses	of	$101	million.

|  |  | Number	of | Each |
| :--- | :--- | :--- | :--- |
| Contingent\tcontractual\tobligations | Amount | Agreements | Agreement |
|  | (in\tmillions) |  | (in\tmillions) |
| Guarantees | $415 | 24 | &lt;$1\t-\t$62 |
| Letters\tof\tcredit\tunder\tthe\tsenior\tsecured\tcredit\tfacility | 85 | 30 | &lt;$1\t-\t$26 |
| Total | $500 | 54 |  |

The	risks	associated	with	these	obligations	include	change	of	control,	construction	cost	overruns,	political	risk,	tax	indemnities,	spot	market	power	prices,	sponsor support	and	liquidated	damages	under	power	purchase	agreements	and	other	agreements	for	projects	in	development,	under	construction	and	operating.	While	the Company	does	not	expect	to	be	required	to	fund	any	material	amounts	under	these	contingent	contractual	obligations	during	2011	or	beyond	that	are	not	recognized	on the	Consolidated	Balance	Sheet,	many	of	the	events	which	would	give	rise	to	such	an	obligation	are	beyond	the	Parent	Company's	control.	There	can	be	no	assurance that	the	Parent	Company	would	have	adequate	sources	of	liquidity	to	fund	its	obligations	under	these	contingent	contractual	obligations	if	it	were	required	to	make substantial	payments	thereunder.

During	2010,	the	Company	paid	letter	of	credit	fees	ranging	from	3.19%	to	3.75%	per	annum	on	the	outstanding	amounts	of	letters	of	credit.

# LITIGATION

The	Company	believes,	based	upon	information	it	currently	possesses	and	taking	into	account	established	reserves	for	liabilities	and	its	insurance	coverage,	that the	ultimate	outcome	of	these	proceedings	and	actions	is	unlikely	to	have	a	material	effect	on	the	Company's	financial	statements.	However,	even	where	no	reserve	has

been	recognized,	it	is	reasonably	possible	that	some	matters	could	be	decided	unfavorably	to	the	Company,	and	could	require	the	Company	to	pay	damages	or	make expenditures	in	amounts	that	could	be	material.

In	1989,	Centrais	Elétricas	Brasileiras	S.A.	("Eletrobrás")	filed	suit	in	the	Fifth	District	Court	in	the	State	of	Rio	de	Janeiro	against	Eletropaulo	Eletricidade	de São	Paulo	S.A.	("EEDSP")	relating	to	the	methodology	for	calculating	monetary	adjustments	under	the	parties'	financing	agreement.	In	April	1999,	the	Fifth	District Court	found	for	Eletrobrás	and	in	September	2001,	Eletrobrás	initiated	an	execution	suit	in	the	Fifth	District	Court	to	collect	approximately	R$1.10	billion	($659 million)	from	Eletropaulo	(as	estimated	by	Eletropaulo)	and	a	lesser	amount	from	an	unrelated	company,	Companhia	de	Transmissão	de	Energia	Elétrica	Paulista ("CTEEP")	(Eletropaulo	and	CTEEP	were	spun	off	from	EEDSP	pursuant	to	its	privatization	in	1998).	In	November	2002,	the	Fifth	District	Court	rejected	Eletropaulo's defenses	in	the	execution	suit.	Eletropaulo	appealed	and	in	September	2003,	the	Appellate	Court	of	the	State	of	Rio	de	Janeiro	("AC")	ruled	that	Eletropaulo	was	not	a proper	party	to	the	litigation	because	any	alleged	liability	had	been	transferred	to	CTEEP	pursuant	to	the	privatization.	In	June	2006,	the	Superior	Court	of	Justice ("SCJ")	reversed	the	Appellate	Court's	decision	and	remanded	the	case	to	the	Fifth	District	Court	for	further	proceedings,	holding	that	Eletropaulo's	liability,	if	any, should	be	determined	by	the	Fifth	District	Court.	Eletropaulo's	subsequent	appeals	to	the	Special	Court	(the	highest	court	within	the	SCJ)	and	the	Supreme	Court	of Brazil	were	dismissed.	Eletrobrás	later	requested	that	the	amount	of	Eletropaulo's	alleged	debt	be	determined	by	an	accounting	expert	appointed	by	the	Fifth	District Court.	Eletropaulo	consented	to	the	appointment	of	such	an	expert,	subject	to	a	reservation	of	rights.	In	February	2010,	the	Fifth	District	Court	appointed	an	accounting expert	to	determine	the	amount	of	the	alleged	debt	and	the	responsibility	for	its	payment	in	light	of	the	privatization,	in	accordance	with	the	methodology	proposed	by Eletrobrás.	Pursuant	to	its	reservation	of	rights,	Eletropaulo	filed	an	interlocutory	appeal	with	the	AC	asserting	that	the	expert	was	required	to	determine	the	issues	in accordance	with	the	methodology	proposed	by	Eletropaulo,	and	that	Eletropaulo	should	be	entitled	to	take	discovery	and	present	arguments	on	the	issues	to	be determined	by	the	expert.	In	April	2010,	the	AC	issued	a	decision	agreeing	with	Eletropaulo's	arguments	and	directing	the	Fifth	District	Court	to	proceed	accordingly. Eletrobrás	may	restart	the	accounting	proceedings	at	the	Fifth	District	Court	at	any	time,	which	would	proceed	according	to	the	AC's	April	2010	decision.	In	the	Fifth District	Court	proceedings,	the	expert's	conclusions	will	be	subject	to	the	Fifth	District	Court's	review	and	approval.	If	Eletropaulo	is	determined	to	be	responsible	for the	debt,	after	the	amount	of	the	alleged	debt	is	determined,	Eletrobrás	will	be	entitled	to	resume	the	execution	suit	in	the	Fifth	District	Court	at	any	time.	If	Eletrobrás does	so,	Eletropaulo	will	be	required	to	provide	security	in	the	amount	of	its	alleged	liability.	In	that	case,	if	Eletrobrás	requests	the	seizure	of	such	security	and	the	Fifth District	Court	grants	such	request,	Eletropaulo's	results	of	operations	may	be	materially	adversely	affected,	and	in	turn	the	Company's	results	of	operations	could	be materially	adversely	affected.	In	addition,	in	February	2008,	CTEEP	filed	a	lawsuit	in	the	Fifth	District	Court	against	Eletrobrás	and	Eletropaulo	seeking	a	declaration that	CTEEP	is	not	liable	for	any	debt	under	the	financing	agreement.	The	parties	are	disputing	the	proper	venue	for	the	CTEEP	lawsuit.	Eletropaulo	believes	it	has meritorious	defenses	to	the	claims	asserted	against	it	and	will	defend	itself	vigorously	in	these	proceedings;	however,	there	can	be	no	assurances	that	it	will	be	successful in	its	efforts.

In	August	2000,	the	FERC	announced	an	investigation	into	the	organized	California	wholesale	power	markets	to	determine	whether	rates	were	just	and reasonable.	Further	investigations	involved	alleged	market	manipulation.	FERC	requested	documents	from	each	of	the	AES	Southland,	LLC	plants	and	AES Placerita,	Inc.	AES	Southland	and	AES	Placerita	have	cooperated	fully	with	the	FERC	investigations.	AES	Southland	was	not	subject	to	refund	liability	because	it	did not	sell	into	the	organized	spot	markets	due	to	the	nature	of	its	tolling	agreement.	After	hearings	at	FERC,	AES	Placerita	was	found	subject	to	refund	liability	of $588,000	plus	interest	for	spot	sales	to	the	California	Power	Exchange	from	October	2,	2000	to	June	20,	2001.	As	FERC	investigations	and	hearings	progressed, numerous	appeals	on	related	issues	were	filed	with	the	U.S.	Court	of	Appeals	for	the	Ninth	Circuit.

Over	the	years,	the	Ninth	Circuit	issued	several	opinions	that	had	the	potential	to	expand	the	scope	of	the	FERC	proceedings	and	increase	refund	exposure	for	AES Placerita	and	other	sellers	of	electricity.	Following	remand	of	one	of	the	Ninth	Circuit	appeals	in	March	2009,	FERC	started	a	new	hearing	process	involving	AES Placerita	and	other	sellers.	In	May	2009,	AES	Placerita	entered	into	a	settlement,	approved	by	FERC	in	July	2009,	concerning	the	claims	before	FERC	against	AES Placerita	relating	to	the	California	energy	crisis	of	2000-2001,	including	the	California	refund	proceeding.	Pursuant	to	the	settlement,	AES	Placerita	paid	$6	million	and assigned	a	receivable	of	$168,119	due	to	it	from	the	California	Power	Exchange	in	return	for	a	release	of	all	claims	against	it	at	FERC	by	the	settling	parties	and	other consideration.	More	than	98%	of	the	buyers	in	the	market	elected	to	join	the	settlement.	A	small	amount	of	AES	Placerita's	settlement	payment	was	placed	in	escrow	for buyers	that	did	not	join	the	settlement	("non-settling	parties").	It	is	unclear	whether	the	escrowed	funds	will	be	enough	to	satisfy	any	additional	sums	that	might	be determined	to	be	owed	to	non-settling	parties	at	the	conclusion	of	the	FERC	proceedings	concerning	the	California	energy	crisis.	However,	any	such	additional	sums	are expected	to	be	immaterial	to	the	Company's	consolidated	financial	statements.	In	November	2009,	one	non-settling	party,	the	Sacramento	Municipal	Utility	District ("SMUD"),	filed	an	appeal	of	the	FERC's	approval	of	the	settlement	which	is	pending	in	the	Ninth	Circuit.	SMUD's	appeal	has	been	stayed	pending	further	order	of	the court.	The	settlement	agreement	is	still	effective	and	will	continue	to	remain	effective	unless	it	is	vacated	by	the	Ninth	Circuit.	SMUD	has	reached	a	settlement	in principal	with	buyers	of	electricity	that,	if	approved	by	FERC,	will	leave	only	immaterial	claims	of	non-settling	parties	against	AES	Placerita.

In	August	2001,	the	Grid	Corporation	of	Orissa,	India,	now	Gridco	Ltd.	("Gridco"),	filed	a	petition	against	the	Central	Electricity	Supply	Company	of	Orissa	Ltd. ("CESCO"),	an	affiliate	of	the	Company,	with	the	Orissa	Electricity	Regulatory	Commission	("OERC"),	alleging	that	CESCO	had	defaulted	on	its	obligations	as	an OERC-licensed	distribution	company,	that	CESCO	management	abandoned	the	management	of	CESCO,	and	asking	for	interim	measures	of	protection,	including	the appointment	of	an	administrator	to	manage	CESCO.	Gridco,	a	state-owned	entity,	is	the	sole	wholesale	energy	provider	to	CESCO.	Pursuant	to	the	OERC's August	2001	order,	the	management	of	CESCO	was	replaced	with	a	government	administrator	who	was	appointed	by	the	OERC.	The	OERC	later	held	that	the Company	and	other	CESCO	shareholders	were	not	necessary	or	proper	parties	to	the	OERC	proceeding.	In	August	2004,	the	OERC	issued	a	notice	to	CESCO,	the Company	and	others	giving	the	recipients	of	the	notice	until	November	2004	to	show	cause	why	CESCO's	distribution	license	should	not	be	revoked.	In	response, CESCO	submitted	a	business	plan	to	the	OERC.	In	February	2005,	the	OERC	issued	an	order	rejecting	the	proposed	business	plan.	The	order	also	stated	that	the CESCO	distribution	license	would	be	revoked	if	an	acceptable	business	plan	for	CESCO	was	not	submitted	to	and	approved	by	the	OERC	prior	to	March	31,	2005.	In its	April	2,	2005	order,	the	OERC	revoked	the	CESCO	distribution	license.	CESCO	has	filed	an	appeal	against	the	April	2,	2005	OERC	order	and	that	appeal	remains pending	in	the	Indian	courts.	In	addition,	Gridco	asserted	that	a	comfort	letter	issued	by	the	Company	in	connection	with	the	Company's	indirect	investment	in	CESCO obligates	the	Company	to	provide	additional	financial	support	to	cover	all	of	CESCO's	financial	obligations	to	Gridco.	In	December	2001,	Gridco	served	a	notice	to arbitrate	pursuant	to	the	Indian	Arbitration	and	Conciliation	Act	of	1996	on	the	Company,	AES	Orissa	Distribution	Private	Limited	("AES	ODPL"),	and	Jyoti	Structures ("Jyoti")	pursuant	to	the	terms	of	the	CESCO	Shareholders	Agreement	between	Gridco,	the	Company,	AES	ODPL,	Jyoti	and	CESCO	(the	"CESCO	arbitration").	In	the arbitration,	Gridco	appeared	to	be	seeking	approximately	$189	million	in	damages,	plus	undisclosed	penalties	and	interest,	but	a	detailed	alleged	damage	analysis	was not	filed	by	Gridco.	The	Company	counterclaimed	against	Gridco	for	damages.	In	June	2007,	a	2-to-1	majority	of	the	arbitral	tribunal	rendered	its	award	rejecting Gridco's	claims	and	holding	that	none	of	the	respondents,	the	Company,	AES	ODPL,	or	Jyoti,	had	any	liability	to	Gridco.	The	respondents'	counterclaims	were	also rejected.	In	September	2007,	Gridco	filed	a	challenge	of	the	arbitration	award	with	the	local	Indian	court.	In	June	2008,	Gridco	filed	a	separate	application	with	the	local Indian	court	for	an	order	enjoining	the	Company	from	selling	or	otherwise	transferring	its	shares	in

Orissa	Power	Generation	Corporation	Ltd.'s	("OPGC"),	an	equity	method	investment,	and	requiring	the	Company	to	provide	security	in	the	amount	of	the	contested damages	in	the	CESCO	arbitration	until	Gridco's	challenge	to	the	arbitration	award	is	resolved.	In	June	2010,	a	2-to-1	majority	of	the	arbitral	tribunal	awarded	the Company	some	of	its	costs	relating	to	the	arbitration.	In	August	2010,	Gridco	filed	a	challenge	of	the	cost	award	with	the	local	Indian	court.	The	Company	believes	that it	has	meritorious	defenses	to	the	claims	asserted	against	it	and	will	defend	itself	vigorously	in	these	proceedings;	however,	there	can	be	no	assurances	that	it	will	be successful	in	its	efforts.

In	early	2002,	Gridco	made	an	application	to	the	OERC	requesting	that	the	OERC	initiate	proceedings	regarding	the	terms	of	OPGC's	existing	PPA	with	Gridco. In	response,	OPGC	filed	a	petition	in	the	Indian	courts	to	block	any	such	OERC	proceedings.	In	early	2005,	the	Orissa	High	Court	upheld	the	OERC's	jurisdiction	to initiate	such	proceedings	as	requested	by	Gridco.	OPGC	appealed	that	High	Court's	decision	to	the	Supreme	Court	and	sought	stays	of	both	the	High	Court's	decision and	the	underlying	OERC	proceedings	regarding	the	PPAs	terms.	In	April	2005,	the	Supreme	Court	granted	OPGC's	requests	and	ordered	stays	of	the	High	Court's decision	and	the	OERC	proceedings	with	respect	to	the	PPA's	terms.	The	matter	is	awaiting	further	hearing.	Unless	the	Supreme	Court	finds	in	favor	of	OPGC's	appeal or	otherwise	prevents	the	OERC's	proceedings	regarding	the	PPA's	terms,	the	OERC	will	likely	lower	the	tariff	payable	to	OPGC	under	the	PPA,	which	would	have	an adverse	impact	on	OPGC's	financials.	OPGC	believes	that	it	has	meritorious	claims	and	defenses	and	will	assert	them	vigorously	in	these	proceedings;	however,	there can	be	no	assurances	that	it	will	be	successful	in	its	efforts.

AES	Florestal,	Ltd.	("Florestal"),	had	been	operating	a	pole	factory	and	had	other	assets,	including	a	wooded	area	known	as	"Horto	Renner,"	in	the	State	of	Rio Grande	do	Sul,	Brazil	(collectively,	"Property").	Florestal	had	been	under	the	control	of	AES	Sul	("Sul")	since	October	1997,	when	Sul	was	created	pursuant	to	a privatization	by	the	Government	of	the	State	of	Rio	Grande	do	Sul.	After	it	came	under	the	control	of	Sul,	Florestal	performed	an

environmental	audit	of	the	entire	operational	cycle	at	the	pole	factory.	The	audit	discovered	200	barrels	of	solid	creosote	waste	and	other	contaminants	at	the	pole factory.	The	audit	concluded	that	the	prior	operator	of	the	pole	factory,	Companhia	Estadual	de	Energia	Elétrica	("CEEE"),	had	been	using	those	contaminants	to	treat the	poles	that	were	manufactured	at	the	factory.	Sul	and	Florestal	subsequently	took	the	initiative	of	communicating	with	Brazilian	authorities,	as	well	as	CEEE,	about the	adoption	of	containment	and	remediation	measures.	The	Public	Attorney's	Office	has	initiated	a	civil	inquiry	(Civil	Inquiry	n.	24/05)	to	investigate	potential	civil liability	and	has	requested	that	the	police	station	of	Triunfo	institute	a	police	investigation	(IP	number	1041/05)	to	investigate	potential	criminal	liability	regarding	the contamination	at	the	pole	factory.	The	parties	filed	defenses	in	response	to	the	civil	inquiry.	The	Public	Attorney's	Office	then	requested	an	injunction	which	the	judge rejected	on	September	26,	2008.	The	Public	Attorney's	office	has	a	right	to	appeal	the	decision.	The	environmental	agency	("FEPAM")	has	also	started	a	procedure (Procedure	n.	088200567/059)	to	analyze	the	measures	that	shall	be	taken	to	contain	and	remediate	the	contamination.	Also,	in	March	2000,	Sul	filed	suit	against	CEEE in	the	2nd	Court	of	Public	Treasure	of	Porto	Alegre	seeking	to	register	in	Sul's	name	the	Property	that	it	acquired	through	the	privatization	but	that	remained	registered in	CEEE's	name.	During	those	proceedings,	AES	subsequently	waived	its	claim	to	re-register	the	Property	and	asserted	a	claim	to	recover	the	amounts	paid	for	the Property.	That	claim	is	pending.	In	November	2005,	the	7th	Court	of	Public	Treasure	of	Porto	Alegre	ruled	that	the	Property	must	be	returned	to	CEEE.	CEEE	has	had sole	possession	of	Horto	Renner	since	September	2006	and	of	the	rest	of	the	Property	since	April	2006.	In	February	2008,	Sul	and	CEEE	signed	a	"Technical Cooperation	Protocol"	pursuant	to	which	they	requested	a	new	deadline	from	FEPAM	in	order	to	present	a	proposal.	In	March	2008,	the	State	Prosecution	office	filed	a Public	Class	Action	against	AES	Florestal,	AES	Sul	and	CEEE,	requiring	an	injunction	for	the	removal	of	the	alleged	sources	of	contamination	and	the	payment	of	an indemnity	in	the	amount	of	R$6	million	($4	million).	The	injunction	was	rejected	and	the	case	is	in	the	evidentiary	stage	awaiting	the	judge's	determination	concerning the	production	of	expert	evidence.	The	above-referenced	proposal	was	delivered	on	April	8,	2008.	FEPAM	responded	by	indicating	that	the	parties	should	undertake	the first	step	of	the	proposal	which	would	be	to	retain	a	contractor.	In	its	response,	Sul	indicated	that	such	step	should	be	undertaken	by	CEEE	as	the	relevant	environmental events	resulted	from	CEEE's	operations.	It	is	estimated	that	remediation	could	cost	approximately	R$14.7	million	($9	million).	Discussions	between	Sul	and	CEEE	are ongoing.

In	July	2004,	the	Corporación	Dominicana	de	Empresas	Eléctricas	Estatales	("CDEEE")	filed	lawsuits	against	Itabo,	an	affiliate	of	the	Company,	in	the	First	and Fifth	Chambers	of	the	Civil	and	Commercial	Court	of	First	Instance	for	the	National	District.	CDEEE	alleges	in	both	lawsuits	that	Itabo	spent	more	than	was	necessary to	rehabilitate	two	generation	units	of	an	Itabo	power	plant	and,	in	the	Fifth	Chamber	lawsuit,	that	those	funds

were	paid	to	affiliates	and	subsidiaries	of	AES	Gener	and	Coastal	Itabo,	Ltd.	("Coastal"),	a	former	shareholder	of	Itabo,	without	the	required	approval	of	Itabo's	board of	administration.	In	the	First	Chamber	lawsuit,	CDEEE	seeks	an	accounting	of	Itabo's	transactions	relating	to	the	rehabilitation.	In	November	2004,	the	First	Chamber dismissed	the	case	for	lack	of	legal	basis.	On	appeal,	in	October	2005	the	Court	of	Appeals	of	Santo	Domingo	ruled	in	Itabo's	favor,	reasoning	that	it	lacked	jurisdiction over	the	dispute	because	the	parties'	contracts	mandated	arbitration.	The	Supreme	Court	of	Justice	is	considering	CDEEE's	appeal	of	the	Court	of	Appeals'	decision.	In the	Fifth	Chamber	lawsuit,	which	also	names	Itabo's	former	president	as	a	defendant,	CDEEE	seeks	$15	million	in	damages	and	the	seizure	of	Itabo's	assets.	In	October 2005,	the	Fifth	Chamber	held	that	it	lacked	jurisdiction	to	adjudicate	the	dispute	given	the	arbitration	provisions	in	the	parties'	contracts.	The	First	Chamber	of	the	Court of	Appeal	ratified	that	decision	in	September	2006.	In	a	related	proceeding,	in	May	2005,	Itabo	filed	a	lawsuit	in	the	U.S.	District	Court	for	the	Southern	District	of	New York	seeking	to	compel	CDEEE	to	arbitrate	its	claims.	The	petition	was	denied	in	July	2005.	Itabo's	appeal	of	that	decision	to	the	U.S.	Court	of	Appeals	for	the	Second Circuit	has	been	stayed	since	September	2006.	Further,	in	September	2006,	in	an	International	Chamber	of	Commerce	arbitration,	an	arbitral	tribunal	determined	that	it lacked	jurisdiction	to	decide	arbitration	claims	concerning	these	disputes.	Itabo	believes	it	has	meritorious	claims	and	defenses	and	will	assert	them	vigorously	in	these proceedings;	however,	there	can	be	no	assurances	that	it	will	be	successful	in	its	efforts.

In	April	2006,	a	putative	class	action	was	filed	in	the	U.S.	District	Court	for	the	Southern	District	of	Mississippi	("District	Court")	on	behalf	of	certain	individual plaintiffs	and	all	residents	and/or	property	owners	in	the	State	of	Mississippi	who	allegedly	suffered	harm	as	a	result	of	Hurricane	Katrina,	and	against	the	Company	and numerous	unrelated	companies,	whose	alleged	greenhouse	gas	emissions	contributed	to	alleged	global	warming	which,	in	turn,	allegedly	increased	the	destructive capacity	of	Hurricane	Katrina.	The	plaintiffs	assert	unjust	enrichment,	civil	conspiracy/aiding	and	abetting,	public	and	private	nuisance,	trespass,	negligence,	and fraudulent	misrepresentation	and	concealment	claims	against	the	defendants.	The	plaintiffs	seek	damages	relating	to	loss	of	property,	loss	of	business,	clean-up	costs, personal	injuries	and	death,	but	do	not	quantify	their	alleged	damages.	In	August	2007,	the	District	Court	dismissed	the	case.	The	plaintiffs	subsequently	appealed	to	the U.S.	Court	of	Appeals	for	the	Fifth	Circuit,	which,	in	October	2009,	affirmed	the	District	Court's	dismissal	of	the	plaintiffs'	unjust	enrichment,	fraudulent misrepresentation,	and	civil	conspiracy	claims.	However,	the	Fifth	Circuit	reversed	the	District	Court's	dismissal	of	the	plaintiffs'	public	and	private	nuisance,	trespass, and	negligence	claims,	and	remanded	those	claims	to	the	District	Court	for	further	proceedings.	In	February	2010,	the	Fifth	Circuit	granted	the	petitions	for	en	banc rehearing	filed	by	the	Company	and	other	defendants,	and	thereby	vacated	its	October	2009	decision.	In	May	2010,	the	Fifth	Circuit	dismissed	the	appeal	on	the	ground that	it	had	lost	its	quorum	for	en	banc	review.	In	August	2010,	the	plaintiffs	filed	a	petition	for	a	writ	of	mandamus	in	the	U.S.	Supreme	Court,	requesting	the	Supreme Court	to	direct	the	Fifth	Circuit	to	reinstate	the	appeal	and	return	it	to	the	panel	that	issued	the	October	2009	decision.	In	January	2011,	the	Supreme	Court	denied	the petition,	ending	the	case.

In	July	2007,	the	Competition	Committee	of	the	Ministry	of	Industry	and	Trade	of	the	Republic	of	Kazakhstan	(the	"Competition	Committee")	ordered Nurenergoservice,	an	AES	subsidiary,	to	pay	approximately	KZT	18	billion	($120	million)	for	alleged	antimonopoly	violations	in	2005	through	the	first	quarter	of	2007. The	Competition	Committee's	order	was	affirmed	by	the	economic	court	in	April	2008	("April	2008	Decision").	The	economic	court	also	issued	an	injunction	to	secure Nurenergoservice's	alleged	liability,	freezing	Nurenergoservice's	bank	accounts	and	prohibiting	Nurenergoservice	from	transferring	or	disposing	of	its	property. Nurenergoservice's	subsequent	appeals	to	the	court	of	appeals	were	rejected.	In	February	2009,	the	Antimonopoly	Agency	(the	Competition	Committee's	successor) seized	approximately	KZT	783	million	($5	million)	from	a	frozen	Nurenergoservice	bank	account	in	partial	satisfaction	of	Nurenergoservice's	alleged	damages	liability. However,	on	appeal	to	the	Kazakhstan	Supreme	Court,	in	October	2009,	the	Supreme	Court	annulled	the	decisions	of	the	lower	courts	because	of	procedural irregularities	and	remanded	the	case	to	the	economic	court	for	reconsideration.	On	remand,	in	January	2010,	the	economic	court	reaffirmed	its	April	2008

Decision.	Nurenergoservice's	appeals	in	the	court	of	appeals	(first	panel)	and	the	court	of	appeals	(second	panel)	were	unsuccessful.	Nurenergoservice	intends	to	file	a further	appeal	to	the	Kazakhstan	Supreme	Court.	In	separate	but	related	proceedings,	in	August	2007,	the	Competition	Committee	ordered	Nurenergoservice	to	pay approximately	KZT	1.8	billion	($12	million)	in	administrative	fines	for	its	alleged	antimonopoly	violations.	Nurenergoservice's	appeal	to	the	administrative	court	was rejected	in	February	2009.	Given	the	adverse	court	decisions	against	Nurenergoservice,	the	Antimonopoly	Agency	may	attempt	to	seize	Nurenergoservice's	remaining assets,	which	are	immaterial	to	the	Company's	consolidated	financial	statements.	The	Antimonopoly	Agency	has	not	indicated	whether	it	intends	to	assert	claims	against Nurenergoservice	for	alleged	antimonopoly	violations	post	first	quarter	2007.	Nurenergoservice	believes	it	has	meritorious	defenses	to	the	claims	asserted	against	it; however,	there	can	be	no	assurances	that	it	will	prevail	in	these	proceedings.

In	September	1996,	a	public	civil	action	was	asserted	against	Eletropaulo	and	Associação	Desportiva	Cultural	Eletropaulo	(the	"Associação")	relating	to	alleged environmental	damage	caused	by	construction	of	the	Associação	near	Guarapiranga	Reservoir.	The	initial	decision	that	was	upheld	by	the	Appellate	Court	of	the	State	of Sao	Paulo	in	2006	found	that	Eletropaulo	should	repair	the	alleged	environmental	damage	by	demolishing	certain	construction	and	reforesting	the	area,	and	either sponsor	an	environmental	project	which	would	cost	approximately	R$1	million	($599	thousand)	as	of	December	31,	2010,	or	pay	an	indemnification	amount	of approximately	R$10.2	million	($6	million).	Eletropaulo	has	appealed	this	decision	to	the	Supreme	Court	and	is	awaiting	a	decision.

On	February	2,	2009,	the	Cayuga	facility	received	a	Notice	of	Violation	from	the	New	York	State	Department	of	Environmental	Conservation	("NYSDEC")	that the	facility	had	exceeded	the	permitted	volume	limit	of	coal	ash	that	can	be	disposed	of	in	the	on-site	landfill.	Cayuga	has	met	with	NYSDEC	and	submitted	a	Landfill Liner	Demonstration	Report	to	them.	Such	report	found	that	the	landfill	has	adequate	engineering	integrity	to	support	the	additional	coal	ash	and	there	is	no	inherent environmental	threat.	NYSDEC	has	indicated	they	accept	the	finding	of	the	report.	A	permit	modification	was	approved	by	the	NYSDEC	on	May	14,	2010	and

such	permit	modification	allows	for	closure	of	this	approximately	10-acre	portion	of	the	landfill.	The	construction	in	accordance	with	the	approved	permit	modification was	completed	in	November	2010	and	the	certification	report	for	this	construction	project	is	currently	being	drafted	to	submit	to	the	NYSDEC	in	the	second	quarter	of 2011.	While	at	this	time	it	is	not	possible	to	predict	what	impact,	if	any,	this	matter	may	have	on	the	Company,	its	results	of	operations	or	its	financial	position,	based upon	the	discussions	to	date,	the	Company	does	not	believe	the	impact	will	be	material.

In	September	2009,	the	Public	Defender's	Office	of	the	State	of	Rio	Grande	do	Sul	("PDO")	filed	a	class	action	against	AES	Sul	in	the	16th	District	Court	of Porto	Alegre,	Rio	Grande	do	Sul	("District	Court"),	claiming	that	AES	Sul	has	been	illegally	passing	PIS	and	COFINS	taxes	(taxes	based	on	AES	Sul's	income)	to consumers.	According	to	ANEEL's	Order	No.	93/05,	the	federal	laws	of	Brazil,	and	the	Brazilian	Constitution,	energy	companies	such	as	AES	Sul	are	entitled	to highlight	PIS	and	COFINS	taxes	in	power	bills	to	final	consumers,	as	the	cost	of	those	taxes	is	included	in	the	energy	tariffs	that	are	applicable	to	final	consumers. Before	AES	Sul	had	been	served	with	the	action,	the	District	Court	dismissed	the	lawsuit	in	October	2009	on	the	ground	that	AES	Sul	had	been	properly	highlighting PIS	and	COFINS	taxes	in	consumer	bills	in	accordance	with	Brazilian	law.	In	April	2010,	the	PDO	appealed	to	the	Appellate	Court	of	the	State	of	Rio	Grande	do	Sul ("AC").	In	November	2010,	the	AC	affirmed	the	dismissal.	The	PDO	is	expected	to	appeal.	If	the	dismissal	is	ever	reversed	and	AES	Sul	does	not	prevail	in	the	lawsuit and	is	ordered	to	cease	recovering	PIS	and	COFINS	taxes	pursuant	to	its	energy	tariff,	its	potential	prospective	losses	could	be	approximately	R$9.6	million	($6	million) per	month,	as	estimated	by	AES	Sul.	In	addition,	if	AES	Sul	is	ordered	to	reimburse	consumers,	its	potential	retrospective	liability	could	be	approximately	R$1.2	billion ($718	million),	as	estimated	by	AES	Sul.	AES	Sul	believes	it	has	meritorious	defenses	to	the	claims	asserted	against	it	and	will	defend	itself	vigorously	in	these proceedings	if	it	is	served	with	the	action;	however,	there	can	be	no	assurances	that	it	would	be	successful	in	its	efforts.	Furthermore,	if	AES	Sul	does	not	prevail	in	the litigation	it	will	seek	to	adjust	its	energy	tariff	to	compensate	it	for	its	losses,	but	there	can	be	no	assurances	that	it	would	be	successful	in	obtaining	an	adjusted	energy tariff.

On	December	21,	2010,	AES-3C	Maritza	East	1	EOOD,	which	owns	an	unfinished	670MW	lignite-fired	power	plant	in	Bulgaria,	made	the	first	in	a	series	of demands	on	the	performance	bond	securing	the	construction	Contractor's	obligations	under	the	parties'	EPC	Contract.	The	Contractor	failed	to	complete	the	plant	on schedule.	The	total	amount	demanded	by	Maritza	under	the	performance	bond	is	approximately	€155	million	($205	million).	However,	the	Contractor	obtained	a temporary	injunction	from	a	French	court	preventing	the	issuing	bank	from	honoring	the	bond	demands.	As	the	performance	bond	is	governed	by	English	law,	Maritza obtained	a	judgment	from	an	English	court	that	the	bond	should	be	paid,	and	then	presented	this	judgment	to	the	French	court	which	issued	the	temporary	injunction. However,	on	February	10,	2011,	the	French	court	issued	a	decision	enjoining	the	issuing	bank	from	honoring	the	demands	on	the	performance	bond	pending	the determination	of	the	arbitration	between	Maritza	and	the	Contractor,	described	below.	Maritza	is	attempting	to	lift	that	injunction	or	otherwise	obtain	payment	on	its demands.	In	addition,	in	December	2010,	the	Contractor	issued	a	notice	of	dispute	alleging	that	the	lignite	that	has	been	supplied	by	Maritza	for	commissioning	of	the power	plant	is	out	of	specification,	allegedly	entitling	the	Contractor	to	an	extension	of	time	to	complete	the	power	plant,	an	increase	to	the	contract	price	of approximately	€62	million	($82	million),	and	other	relief.	The	Contractor	thereafter	advised	Maritza	that	it	had	stopped	commissioning	of	the	power	plant's	two	units because	of	the	characteristics	of	the	lignite	supplied,	and,	in	January	2011,	initiated	arbitration	on	its	lignite	claim.	Maritza	disputes	that	the	lignite	is	out	of	specification and	intends	to	defend	the	arbitration	and	assert	counterclaims	for	delay	liquidated	damages	and	other	relief	relating	to	the	Contractor's	failure	to	complete	the

power	plant	and	other	breaches	of	the	EPC	contract.	Maritza	believes	it	has	meritorious	claims	and	defenses	and	will	assert	them	vigorously	in	these	proceedings; however,	there	can	be	no	assurances	that	it	will	be	successful	in	its	efforts.

# 13.	BENEFIT	PLANS

DEFINED	CONTRIBUTION	PLAN—The	Company	sponsors	one	defined	contribution	plan,	qualified	under	section	401	of	the	Internal	Revenue	Code.	All U.S.	employees	of	the	Company	are	eligible	to	participate	in	the	plan	except	for	those	employees	who	are	not	covered	by	their	collective	bargaining	agreement.	The	plan provides	matching	contributions	in	AES	common	stock,	other	contributions	at	the	discretion	of	the	Compensation	Committee	of	the	Board	of	Directors	in	AES	common stock	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	fifth	anniversary	of	their	hire	date.	Company	contributions to	the	plans	were	approximately	$22	million,	$22	million,	and	$21	million	for	the	years	ended	December	31,	2010,	2009,	and	2008,	respectively.

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	29	defined	benefit	plans,	three	are	at U.S.	subsidiaries	and	the	remaining	plans	are	at	foreign	subsidiaries.

AES	adopted	the	measurement	date	provisions	of	the	pension	accounting	guidance,	which	require	a	year-end	measurement	date	of	plan	assets	and	obligations	for all	defined	benefit	plans,	for	the	fiscal	year	ended	December	31,	2008	and,	accordingly,	recognized	a	cumulative	adjustment	of	$1	million	to	retained	earnings	as	of December	31,	2008.

The	following	table	reconciles	the	Company's	funded	status,	both	domestic	and	foreign,	as	of	December	31,	2010	and	2009:

The	following	table	summarizes	the	amounts	recognized	on	the	Consolidated	Balance	Sheets	related	to	the	funded	status	of	the	plans,	both	domestic	and	foreign, as	of	December	31,	2010	and	2009:

|  |  | December	31, | December	31, |  |
| :--- | :--- | :--- | :--- | :--- |
|  | 2010 | 2010 | 2009 | 2009 |
|  | U.S. | Foreign | U.S. | Foreign |
|  |  | (in\tmillions) |  |  |
| AMOUNTS\tRECOGNIZED\tON\tTHE |  |  |  |  |
| CONSOLIDATED\tBALANCE\tSHEETS |  |  |  |  |
| Noncurrent\tassets | $ — | $34 | $ — | $32 |
| Accrued\tbenefit\tliability—current | \t — | (5) | \t — | (4) |
| Accrued\tbenefit\tliability—long-term | (204) | (1,290) | (187) | (1,121) |
| Net\tamount\trecognized\tat\tend\tof\tyear | $(204) | $(1,261) | $(187) | $(1,093) |

The	following	table	summarizes	the	Company's	accumulated	benefit	obligation,	both	domestic	and	foreign,	as	of	December	31,	2010	and	2009:

|  | 2010 |  | 2009 | 2009 |
| :--- | :--- | :--- | :--- | :--- |
|  | U.S. | Foreign | U.S. | Foreign |
|  |  | (in\tmillions) | (in\tmillions) |  |
| Accumulated\tBenefit\tObligation | $623 | $5,936 | $562 | $5,098 |
| Information\tfor\tpension\tplans\twith\tan\taccumulated\tbenefit\tobligation\tin\texcess\tof\tplan\tassets: |  |  |  |  |
| Projected\tbenefit\tobligation | $642 | $5,703 | $579 | $4,887 |
| Accumulated\tbenefit\tobligation | \t 623 | \t 5,657 | \t 562 | \t 4,855 |
| Fair\tvalue\tof\tplan\tassets | \t 438 | \t 4,410 | \t 392 | \t 3,765 |
| Information\tfor\tpension\tplans\twith\ta\tprojected\tbenefit\tobligation\tin\texcess\tof\tplan\tassets: |  |  |  |  |
| Projected\tbenefit\tobligation | $642 | $5,710 | $579 | $4,892 |
| Fair\tvalue\tof\tplan\tassets | \t 438 | \t 4,415 | \t 392 | \t 3,766 |

The	table	below	summarizes	the	significant	weighted	average	assumptions	used	in	the	calculation	of	benefit	obligation	and	net	periodic	benefit	cost,	both	domestic and	foreign,	as	of	December	31,	2010	and	2009:

|  | 2010 | 2010 | 2009 | 2009 |
| :--- | :--- | :--- | :--- | :--- |
|  | U.S. | Foreign | U.S. | Foreign |
| Benefit\tObligation: |  |  |  |  |
| Discount\trates | \t5.38% | 9.84% | \t5.93% | \t10.56% |
| Rates\tof\tcompensation\tincrease | \t4.00% | 6.00% | \t4.00% | 6.00% |
| Periodic\tBenefit\tCost: |  |  |  |  |
| Discount\trate | \t5.93% | \t10.56% | \t6.26% | \t11.78% |
| Expected\tlong-term\trate\tof\treturn\ton\tplan\tassets | \t8.00% | \t11.12% | \t8.00% | \t11.99% |
| Rate\tof\tcompensation\tincrease | \t4.00% | 6.00% | \t4.75% | 5.97% |

A	subsidiary	of	the	Company	has	a	defined	benefit	obligation	of	$607	million	and	$549	million	as	of	December	31,	2010	and	2009,	respectively,	and	uses	salary bands	to	determine	future	benefit	costs	rather	than	rates	of	compensation	increases.	Rates	of	compensation	increases	in	the	table	above	do	not	include	amounts	related	to this	specific	defined	benefit	plan.

The	Company	establishes	its	estimated	long-term	return	on	plan	assets	considering	various	factors,	which	include	the	targeted	asset	allocation	percentages, historic	returns	and	expected	future	returns.

The	measurement	of	pension	obligations,	costs	and	liabilities	is	dependent	on	a	variety	of	assumptions.	These	assumptions	include	estimates	of	the	present	value of	projected	future	pension	payments	to	all	plan	participants,	taking	into	consideration	the	likelihood	of	potential	future	events	such	as	salary	increases	and	demographic experience.	These	assumptions	may	have	an	effect	on	the	amount	and	timing	of	future	contributions.

The	assumptions	used	in	developing	the	required	estimates	include	the	following	key	factors:

•discount	rates;

•salary	growth;

•retirement	rates;

•inflation;

•expected	return	on	plan	assets;	and

•	 mortality	rates.

The	effects	of	actual	results	differing	from	the	Company's	assumptions	are	accumulated	and	amortized	over	future	periods	and,	therefore,	generally	affect	the Company's	recognized	expense	in	such	future	periods.

Sensitivity	of	the	Company's	pension	funded	status	to	the	indicated	increase	or	decrease	in	the	discount	rate	and	long-term	rate	of	return	on	plan	assets assumptions	is	shown	below.	Note	that	these	sensitivities	may	be	asymmetric	and	are	specific	to	the	base	conditions	at	year-end	2010.	They	also	may	not	be	additive,	so the	impact	of	changing	multiple	factors	simultaneously	cannot	be	calculated	by	combining	the	individual	sensitivities	shown.	The	December	31,	2010	funded	status	is affected	by	the	December	31,	2010	assumptions.	Pension	expense	for	2010	is	affected	by	the	December	31,	2009	assumptions.	The	impact	on	pension	expense	from	a one	percentage	point	change	in	these	assumptions	is	shown	in	the	table	below	(in	millions):

The	following	table	summarizes	the	components	of	the	net	periodic	benefit	cost,	both	domestic	and	foreign,	for	the	years	ended	December	31,	2010	through	2008:

|  | 2010 | 2010 | 2009 | 2009 | 2008 | 2008 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Components\tof\tNet\tPeriodic\tBenefit\tCost: | U.S. | Foreign | U.S. | Foreign | U.S. | Foreign |
|  |  |  | (in\tmillions) |  |  |  |
| Service\tcost | $7 | $17 | $7 | $13 | $6 | $11 |
| Interest\tcost | 33 | 511 | 34 | 459 | 32 | 453 |
| Expected\treturn\ton\tplan\tassets | (30) | (427) | (26) | (374) | (34) | (412) |
| Amortization\tof\tinitial\tnet\tasset | \t — | (1) | \t — | (2) | \t — | (3) |
| Amortization\tof\tprior\tservice\tcost | 3 | — | 4 | — | 3 | — |
| Amortization\tof\tnet\tloss | 12 | 38 | 16 | 7 | 1 | 2 |
| Settlement\tgain\trecognized | \t — | 1 | \t — | — | 1 | — |
| Total\tpension\tcost | $25 | $139 | $35 | $103 | $9 | $51 |

The	following	table	summarizes	the	amounts	reflected	in	Accumulated	Other	Comprehensive	Loss	on	the	Consolidated	Balance	Sheet	as	of	December	31,	2010 that	have	not	yet	been	recognized	as	components	of	net	periodic	benefit	cost:

|  |  |  | Amounts	expected	to	be | Amounts	expected	to	be |
| :--- | :--- | :--- | :--- | :--- |
|  | Accumulated\tOther |  | reclassified\tto\tearnings | reclassified\tto\tearnings |
|  | Comprehensive\tLoss |  | in\tnext\tfiscal\tyear | in\tnext\tfiscal\tyear |
|  | \t\t\t\tU.S. | \t\t\t\tForeign | \t\t\t\tU.S. | \t\t\t\tForeign |
|  |  | (in\tmillions) |  |  |
| Prior\tservice\tcost | $— | $(2) | $— | $— |
| Unrecognized\tnet\tactuarial\tgain\t(loss) | (3) | (876) | — | (23) |
| Total | $(3) | $(878) | $— | $(23) |

The	following	table	summarizes	the	Company's	target	allocation	for	2010	and	pension	plan	asset	allocation,	both	domestic	and	foreign,	as	of	December	31,	2010 and	2009:

|  |  |  |  | Percentage	of	Plan	Assets	as	of | Percentage	of	Plan	Assets	as	of |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | December\t31, |  |  |
|  | Target\tAllocations | Target\tAllocations | 2010 |  | 2009 | 2009 |
| Asset\tCategory | U.S. | Foreign | U.S. | Foreign | U.S. | Foreign |
| Equity\tsecurities | \t47% | \t15%\t-\t30% | 53.66% | 22.71% | 57.23% | 22.22% |
| Debt\tsecurities | \t39% | \t59%\t-\t85% | 26.71% | 73.36% | 34.50% | 73.34% |
| Real\testate | \t 0% | 0%\t-\t4% | —\t\t% | 2.09% | —\t\t% | 2.07% |
| Other | \t14% | 0%\t-\t6% | 19.63% | 1.84% | 8.27% | 2.37% |
| Total\tpension\tassets |  |  | \t100.00% | \t100.00% | \t100.00% | \t100.00% |

The	U.S.	plans	seek	to	achieve	the	following	long-term	investment	objectives:

•	 Maintenance	of	sufficient	income	and	liquidity	to	pay	retirement	benefits	and	other	lump	sum	payments;

•Long-term	rate	of	return	in	excess	of	the	annualized	inflation	rate;

•Long-term	rate	of	return,	net	of	relevant	fees,	that	meet	or	exceed	the	assumed	actuarial	rate;	and

•Long-term	competitive	rate	of	return	on	investments,	net	of	expenses,	that	is	equal	to	or	exceeds	various	benchmark	rates.

The	asset	allocation	is	reviewed	periodically	to	determine	a	suitable	asset	allocation	which	seeks	to	manage	risk	through	portfolio	diversification	and	takes	into account,	among	other	possible	factors,	the	above-stated	objectives,	in	conjunction	with	current	funding	levels,	cash	flow	conditions	and	economic	and	industry	trends.

The	following	table	summarizes	the	Company's	U.S.	plan	assets	by	category	of	investment	and	level	within	the	fair	value	hierarchy	as	of	December	31,	2010	and	2009:

|  | December	31,	2010 | December	31,	2010 | December	31,	2010 | December	31,	2010 | December	31,	2009 | December	31,	2009 | December	31,	2009 | December	31,	2009 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| U.S.\tPlans | Level\t1 | Level\t2 | Level\t3 | Total | Level\t1 | Level\t2 | Level\t3 | Total |
|  |  |  |  | (in\tmillions) | (in\tmillions) |  |  |  |
| Equity\tsecurities: |  |  |  |  |  |  |  |  |
| Common\tstock | $160 | $36 | $ — | $196 | $189 | $31 | $ — | $220 |
| Mutual\tfunds | 39 | \t — | \t — | 39 | 3 | \t — | \t — | 3 |
| Debt\tsecurities: |  |  |  |  |  |  |  |  |
| Government\tdebt\tsecurities | 38 | \t — | \t — | 38 | 48 | \t — | \t — | 48 |
| Corporate\tdebt\tsecurities | 66 | \t — | \t — | 66 | 71 | \t — | \t — | 71 |
| Mutual\tfunds^(1) | 2 | \t — | \t — | 2 | 2 | \t — | \t — | 2 |
| Other\tdebt\tsecurities | 11 | \t — | \t — | 11 | 15 | \t — | \t — | 15 |
| Other: |  |  |  |  |  |  |  |  |
| Cash\tand\tcash\tequivalents | 70 | \t — | \t — | 70 | 17 | \t — | \t — | 17 |
| Other\tinvestments | \t — | 16 | \t — | 16 | \t — | 16 | \t — | 16 |
| Total\tplan\tassets | $386 | $52 | $ — | $438 | $345 | $47 | $ — | $392 |

Mutual	funds	categorized	as	debt	securities	consist	of	mutual	funds	for	which	debt	securities	are	the	primary	underlying	investment.

The	investment	strategy	of	the	foreign	plans	seeks	to	maximize	return	on	investment	while	minimizing	risk.	The	assumed	asset	allocation	has	less	exposure	to equities	in	order	to	closely	match	market	conditions	and	near	term	forecasts.	The	following	table	summarizes	the	Company's	foreign	plan	assets	by	category	of investment	and	level	within	the	fair	value	hierarchy	as	of	December	31,	2010	and	2009:

|  | December	31,	2010 | December	31,	2010 | December	31,	2010 | December	31,	2009 | December	31,	2009 | December	31,	2009 | December	31,	2009 | December	31,	2009 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Foreign\tPlans | Level\t1 | Level\t2 | Level\t3 | Total | Level\t1 | Level\t2 | Level\t3 | Total |
|  |  |  |  | (in\tmillions) | (in\tmillions) |  |  |  |
| Equity\tsecurities: |  |  |  |  |  |  |  |  |
| Common\tstock | $30 | $— | $ — | $30 | $21 | $— | $ — | $21 |
| Mutual\tfunds | 524 | — | \t — | 524 | 472 | — | — | 472 |
| Private\tequity^(1) | \t — | — | 521 | 521 | \t — | — | 406 | 406 |
| Debt\tsecurities: |  |  |  |  |  |  |  |  |
| Certificates\tof\tdeposit | \t — | 4 | \t — | 4 | \t — | 7 | — | 7 |
| Unsecured\tdebentures | \t — | 19 | \t — | 19 | \t — | 14 | — | 14 |
| Government\tdebt\tsecurities | \t — | 234 | \t — | 234 | \t — | 206 | — | 206 |
| Mutual\tfunds^(2) | 95 | \t 3,110 | \t — | \t 3,205 | 88 | 2,646 | — | 2,734 |
| Other\tdebt\tsecurities | \t — | 11 | \t — | 11 | \t — | 5 | — | 5 |
| Real\testate: |  |  |  |  |  |  |  |  |
| Real\testate^(1) | \t — | — | 99 | 99 | \t — | — | 84 | 84 |
| Other: |  |  |  |  |  |  |  |  |
| Cash\tand\tcash\tequivalents | \t — | 4 | \t — | 4 | 20 | 2 | — | 22 |
| Participant\tloans^(3) | \t — | — | 83 | 83 | \t — | — | 74 | 74 |
| Total\tplan\tassets | $649 | $3,382 | $703 | $4,734 | $601 | $2,880 | $564 | $ 4,045 |

Plan	assets	of	our	Brazilian	subsidiaries	are	invested	in	private	equities	and	commercial	real	estate	through	the	plan	administrator	in	Brazil.	The	fair	value	of	these assets	is	determined	using	the	income	approach	through	annual	appraisals	based	on	a	discounted	cash	flow	analysis.

Loans	to	participants	are	stated	at	cost,	which	approximates	fair	value.

The	following	table	presents	a	reconciliation	of	all	plan	assets	measured	at	fair	value	using	significant	unobservable	inputs	(Level	3)	for	the	years	ended December	31,	2010	and	2009:

|  | 2010 | 2009 |
| :--- | :--- | :--- |
|  | (in\tmillions) |  |
| Balance\tat\tJanuary\t1 | $564 | $380 |
| Actual\treturn\ton\tplan\tassets: |  |  |
| Returns\trelating\tto\tassets\tstill\theld\tat\treporting\tdate | \t 104 | 46 |
| Purchases,\tsales,\tissuances\tand\tsettlements | 3 | 1 |
| Change\tdue\tto\texchange\trate\tchanges | 32 | \t 137 |
| Balance\tat\tDecember\t31 | $703 | $564 |

The	following	table	summarizes	the	scheduled	cash	flows	for	U.S.	and	foreign	expected	employer	contributions	and	expected	future	benefit	payments,	both domestic	and	foreign:

|  | U.S. |  | Foreign |
| :--- | :--- | :--- | :--- |
|  |  | (in\tmillions) |  |
| Expected\temployer\tcontribution\tin\t2011 | $36 |  | $165 |
| Expected\tbenefit\tpayments\tfor\tfiscal\tyear\tending: |  |  |  |
| 2011 | 32 |  | 432 |
| 2012 | 33 |  | 447 |
| 2013 | 35 |  | 464 |
| 2014 | 36 |  | 481 |
| 2015 | 38 |  | 498 |
| 2016\t-\t2020 | \t 212 |  | \t 2,751 |

# STOCK	PURCHASE	AGREEMENT

On	March	12,	2010,	the	Company	and	Terrific	Investment	Corporation	("Investor"),	a	wholly	owned	subsidiary	of	China	Investment	Corporation,	entered	into	a stockholder	agreement	(the	"Stockholder	Agreement")	in	connection	with	the	agreement	discussed	in	the	following	paragraph.	Under	the	Stockholder	Agreement,	as long	as	Investor	holds	more	than	5%	of	the	outstanding	shares	of	common	stock	of	the	Company,	Investor	will	have	the	right	to	designate	one	nominee,	who	must	be reasonably	acceptable	to	the	Board,	for	election	to	the	Board	of	Directors	of	the	Company.	Investor	has	not	designated	its	nominee	for	election	to	the	Board	of	Directors of	the	Company.	In	addition,	until	such	time	as	Investor	holds	5%	or	less	of	the	outstanding	shares	of	common	stock,	Investor	has	agreed	to	vote	its	shares	in	accordance with	the	recommendation	of	the

Company	on	any	matters	submitted	to	a	vote	of	the	stockholders	of	the	Company	relating	to	the	election	of	directors	and	compensation	matters.	Otherwise,	Investor	may vote	its	shares	at	its	discretion.	Further,	under	the	Stockholder	Agreement,	Investor	will	be	subject	to	a	standstill	restriction	which	generally	prohibits	Investor	from purchasing	additional	securities	of	the	Company	beyond	the	level	acquired	by	it	under	the	stock	purchase	agreement	entered	into	between	Investor	and	the	Company	on November	6,	2009.	In	addition,	Investor	has	agreed	to	a	lock-up	restriction	such	that	Investor	would	not	sell	its	shares	for	a	period	of	12	months	following	the	closing, subject	to	certain	exceptions.	The	standstill	and	lock-up	restrictions	also	terminate	at	such	time	as	Investor	holds	5%	or	less	of	the	outstanding	shares	of	common	stock. Investor	will	have	certain	registration	rights	and	preemptive	rights	under	the	Stockholder	Agreement	with	respect	to	its	shares	of	common	stock	of	the	Company.

# STOCK	REPURCHASE	PROGRAM

On	August	7,	2008,	the	Company's	Board	of	Directors	approved	a	share	repurchase	plan	for	up	to	$400	million	of	AES	common	stock.	The	Board	authorization permitted	the	Company	to	repurchase	shares	over	a	six	month	period	ended	February	7,	2009.	Shares	of	common	stock	repurchased	under	this	plan	through December	31,	2008	totaled	10,691,267	at	a	total	cost	of	$143	million	plus	commissions	of	$0.3	million	(average	of	$13.41	per	share	including	commissions).	The	Board authorization	of	the	stock	repurchase	program	expired	on	February	7,	2009.

The	shares	of	stock	repurchased	have	been	classified	as	treasury	stock	and	accounted	for	using	the	cost	method.	A	total	of	17,287,073	and	9,534,580	shares	were held	in	treasury	stock	at	December	31,	2010	and	2009,	respectively.	The	Company	has	not	retired	any	shares	held	in	treasury	during	the	years	ended	December	31,	2010, 2009	or	2008.

# COMPREHENSIVE	INCOME

The	components	of	comprehensive	income	for	the	years	ended	December	31,	2010,	2009	and	2008	were	as	follows:

|  | 2010 | 2009 | 2008 |
| :--- | :--- | :--- | :--- |
|  |  | (in\tmillions) |  |
| Net\tincome | $1,059 | $1,755 | $2,032 |
| Change\tin\tfair\tvalue\tof\tavailable-for-sale\tsecurities,\tnet\tof\tincome\ttax\t(expense)\tbenefit\tof\t$3,\t$(4)\tand\t$0, |  |  |  |
| respectively | (5) | 6 | — |
| Foreign\tcurrency\ttranslation\tadjustments,\tnet\tof\tincome\ttax\t(expense)\tbenefit\tof\t$(11),\t$(78)\tand\t$53,\trespectively | 468 | 742 | (1,052) |
| Derivative\tactivity: |  |  |  |
| Reclassification\tto\tearnings,\tnet\tof\tincome\ttax\t(expense)\tof\t$(30),\t$(41)\tand\t$(19),\trespectively | 91 | (141) | 90 |
| Change\tin\tderivative\tfair\tvalue,\tnet\tof\tincome\ttax\t(expense)\tbenefit\tof\t$56,\t$34\tand\t$(29),\trespectively | (242) | 214 | (158) |
| Total\tchange\tin\tfair\tvalue\tof\tderivatives | (151) | 73 | (68) |
| Change\tin\tunfunded\tpension\tobligation,\tnet\tof\tincome\ttax\tbenefit\tof\t$45,\t$69\tand\t$77,\trespectively | (88) | (139) | (149) |
| Other\tcomprehensive\tincome\t(loss) | 224 | 682 | (1,269) |
| Comprehensive\tincome | 1,283 | 2,437 | 763 |
| Less:\tComprehensive\tincome\tattributable\tto\tnoncontrolling\tinterests^(1) | (1,038) | (1,485) | (169) |
| Comprehensive\tincome\tattributable\tto\tThe\tAES\tCorporation | $245 | $952 | $594 |

(1) Reflects	the	(income)	loss	attributed	to	noncontrolling	interests	in	the	form	of	common	securities	and	dividends	on	preferred	stock.

The	following	table	summarizes	the	balances	comprising	accumulated	other	comprehensive	loss,	net	of	tax,	as	of	December	31,	2010	and	2009:

|  | December	31, |  |
| :--- | :--- | :--- |
|  | 2010 | 2009 |
|  | (in\tmillions) |  |
| Foreign\tcurrency\ttranslation\tadjustment | $1,824 | $2,312 |
| Unrealized\tderivative\tlosses | 344 | 224 |
| Unfunded\tpension\tobligation | 216 | 194 |
| Unrealized\tloss\ton\tsecurities\tavailable\tfor\tsale | (1) | (6) |
| Total | $2,383 | $2,724 |

The	following	table	summarizes	the	net	income	attributable	to	The	AES	Corporation	and	transfers	(to)	from	noncontrolling	interests	for	the	years	ended December	31,	2010	and	2009:

| Net	income	attributable	to	The	AES	Corporation | $9 | $658 |
| :--- | :--- | :--- |
| Transfers\t(to)\tfrom\tthe\tnoncontrolling\tinterests: |  |  |
| Decrease\tin\tThe\tAES\tCorporation's\tpaid-in\tcapital\tfor\tpurchase\tof\tsubsidiary\tshares | (25) | \t — |
| Net\ttransfers\t(to)\tfrom\tnoncontrolling\tinterest | (25) | \t — |
| Change\tfrom\tnet\tincome\tattributable\tto\tThe\tAES\tCorporation\tand\ttransfers\t(to)\tfrom\tnoncontrolling\tinterests | $(16) | $658 |

# 15.	SEGMENT	AND	GEOGRAPHIC	INFORMATION

The	management	reporting	structure	is	organized	along	our	two	lines	of	business	(Generation	and	Utilities)	and	three	regions:	(1)	Latin	America	&	Africa; (2)	North	America;	and	(3)	Europe,	Middle	East	&	Asia	(collectively	"EMEA"),	each	managed	by	a	regional	president.	The	segment	reporting	structure	uses	the Company's	management	reporting	structure	as	its	foundation	to	reflect	how	the	Company	manages	the	business	internally.	During	2010,	the	Company	modified	its internal	reporting	structure	to	move	the	management	of	the	Company's	generation	business	in	Jordan,	Amman	East,	from	Asia	to	Europe.	Accordingly,	Amman	East	is now	reported	within	the	Europe—Generation	segment.	All	prior	periods	have	been	retrospectively	restated	to	reflect	this	change	and	conform	to	current	period presentation.	The	Company	applied	the	segment	reporting	accounting	guidance,	which	provides	certain	quantitative	thresholds	and	aggregation	criteria,	and	the Company	concluded	it	has	six	reportable	segments	which	include:

Corporate	and	Other—The	Company's	Europe	Utilities,	Africa	Utilities,	Africa	Generation,	Wind	Generation	and	Climate	Solutions	operating	segments	are reported	within	"Corporate	and	Other"	because	they	do	not	meet	the	criteria	to	allow	for	aggregation	with	another	operating	segment	or	the	quantitative	thresholds	that would	require	separate	disclosure	under	segment	reporting	accounting	guidance.	None	of	these	operating	segments	are	currently	material	to	our	presentation	of reportable	segments,	individually	or	in	the	aggregate.	AES	Solar	and	certain	other	unconsolidated	businesses	are	accounted	for	using	the	equity	method	of	accounting; therefore,	their	operating	results	are	included	in	"Net	Equity	in	Earnings	of	Affiliates"	on	the	face	of	the	Consolidated	Statements	of	Operations,	not	in	revenue	or	gross margin.	"Corporate	and	Other"	also	includes	costs	related	to	corporate	overhead	costs	which	are	not	directly	associated	with	the	operations	of	our	six	reportable segments	and	other	intercompany	charges	such	as	self-insurance	premiums	which	are	fully	eliminated	in	consolidation.

The	Company	uses	Adjusted	Gross	Margin,	a	non-GAAP	measure,	to	evaluate	the	performance	of	its	segments.	Adjusted	Gross	Margin	is	defined	by	the Company	as:	Gross	Margin	plus	depreciation	and	amortization	less	general	and	administrative	expenses.

Segment	revenue	includes	inter-segment	sales	related	to	the	transfer	of	electricity	from	generation	plants	to	utilities	within	Latin	America.	No	material	inter- segment	revenue	relationships	exist	between	other	segments.	Corporate	allocations	include	certain	management	fees	and	self	insurance	activities	which	are	reflected within	segment	Adjusted	Gross	Margin.	All	intra-segment	activity	has	been	eliminated	with	respect	to	revenue	and	Adjusted	Gross	Margin	within	the	segment.	Inter- segment	activity	has	been	eliminated	within	the	total	consolidated	results.	All	balance	sheet	information	for	businesses	that	were	discontinued	or	classified	as	held	for sale	as	of	December	31,	2010	is	segregated	and	is	shown	in	the	line	"Discontinued	Businesses"	in	the	accompanying	segment	tables.

The	tables	below	present	the	breakdown	of	business	segment	balance	sheet	and	income	statement	data	as	of	and	for	the	years	ended	December	31,	2010	through 2008:

|  | Total	Revenue | Total	Revenue | Total	Revenue | Intersegment | Intersegment | Intersegment | External	Revenue | External	Revenue | External	Revenue |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2010 | 2009 | 2008 | 2010 | 2009 | 2008 | 2010 | 2009 | 2008 |
|  |  |  |  |  | (in\tmillions) |  |  |  |  |
| Revenue |  |  |  |  |  |  |  |  |  |
| Latin\tAmerica—Generation | $4,281 | $3,651 | $4,468 | $(1,017) | $(864) | $(991) | $3,264 | $2,787 | $3,477 |
| Latin\tAmerica—Utilities | 7,222 | 6,092 | 5,907 | — | \t — | \t — | 7,222 | 6,092 | 5,907 |
| North\tAmerica—Generation | 1,972 | 1,940 | 2,234 | — | \t — | \t — | 1,972 | 1,940 | 2,234 |
| North\tAmerica—Utilities | 1,145 | 1,068 | 1,079 | — | \t — | \t — | 1,145 | 1,068 | 1,079 |
| Europe—Generation | 1,362 | 820 | 1,143 | (2) | 2 | \t — | 1,360 | 822 | 1,143 |
| Asia—Generation | 618 | 375 | 345 | — | \t — | \t — | 618 | 375 | 345 |
| Corp/Other\tand\teliminations | 47 | 8 | 21 | 1,019 | 862 | 991 | 1,066 | 870 | 1,012 |
| Total\tRevenue | $16,647 | $13,954 | $15,197 | $— | $ — | $ — | $16,647 | $13,954 | $15,197 |

|  | Total	Adjusted	Gross | Total	Adjusted	Gross |  |  |  |  | External	Adjusted	Gross | External	Adjusted	Gross |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Margin | Margin | Margin | Intersegment | Intersegment | Intersegment | Margin | Margin | Margin |
|  | 2010 | 2009 | 2008 | 2010 | 2009 | 2008 | 2010 | 2009 | 2008 |
|  |  |  |  |  | (in\tmillions) |  |  |  |  |
| Adjusted\tGross\tMargin |  |  |  |  |  |  |  |  |  |
| Latin\tAmerica—Generation | $1,698 | $1,528 | $1,557 | $(1,010) | $(852) | $(978) | $688 | $676 | $579 |
| Latin\tAmerica—Utilities | \t 1,320 | \t 1,130 | \t 1,102 | 1,018 | 865 | 991 | 2,338 | 1,995 | 2,093 |
| North\tAmerica—Generation | 611 | 658 | 836 | 2 | (3) | 17 | 613 | 655 | 853 |
| North\tAmerica—Utilities | 407 | 401 | 419 | 2 | 2 | 2 | 409 | 403 | 421 |
| Europe—Generation | 355 | 244 | 299 | 3 | 4 | 2 | 358 | 248 | 301 |
| Asia—Generation | 255 | 111 | (11) | 2 | 4 | 4 | 257 | 115 | (7) |
| Corp/Other\tand\teliminations | 63 | 2 | (64) | (17) | (20) | (38) | 46 | (18) | (102) |
| Reconciliation\tto\tIncome\tfrom\tContinuing\tOperations\tbefore\tTaxes |  |  |  |  |  |  |  |  |  |
| Depreciation\tand\tamortization |  |  |  |  |  |  | (1,137) | (980) | (938) |
| Interest\texpense | Interest\texpense | Interest\texpense | Interest\texpense | Interest\texpense | Interest\texpense | Interest\texpense | (1,526) | (1,485) | (1,770) |
| Interest\tincome |  |  |  |  |  |  | 411 | 348 | 519 |
| Other\texpense | Other\texpense | Other\texpense | Other\texpense | Other\texpense | Other\texpense | Other\texpense | (239) | (111) | (161) |
| Other\tincome |  |  |  |  |  |  | 108 | 465 | 375 |
| Gain\ton\tsale\tof\tinvestments | Gain\ton\tsale\tof\tinvestments | Gain\ton\tsale\tof\tinvestments | Gain\ton\tsale\tof\tinvestments | Gain\ton\tsale\tof\tinvestments | Gain\ton\tsale\tof\tinvestments | Gain\ton\tsale\tof\tinvestments | — | 131 | 909 |
| Loss\ton\tsale\tof\tsubsidiary\tstock |  |  |  |  |  |  | — | — | (31) |
| Goodwill\timpairment | Goodwill\timpairment | Goodwill\timpairment | Goodwill\timpairment | Goodwill\timpairment | Goodwill\timpairment | Goodwill\timpairment | (21) | (122) | — |
| Asset\timpairment\texpense |  |  |  |  |  |  | (1,221) | (25) | (175) |
| Foreign\tcurrency\ttransaction\tgains\t(losses)\ton\tnet\tmonetary\tposition | Foreign\tcurrency\ttransaction\tgains\t(losses)\ton\tnet\tmonetary\tposition | Foreign\tcurrency\ttransaction\tgains\t(losses)\ton\tnet\tmonetary\tposition | Foreign\tcurrency\ttransaction\tgains\t(losses)\ton\tnet\tmonetary\tposition | Foreign\tcurrency\ttransaction\tgains\t(losses)\ton\tnet\tmonetary\tposition | Foreign\tcurrency\ttransaction\tgains\t(losses)\ton\tnet\tmonetary\tposition | Foreign\tcurrency\ttransaction\tgains\t(losses)\ton\tnet\tmonetary\tposition | (33) | 33 | (184) |
| Other\tnon-operating\texpense |  |  |  |  |  |  | (7) | (12) | (15) |
| Income\tfrom\tcontinuing\toperations\tbefore\ttaxes\tand\tequity\tin\tearnings\tof\taffiliates | Income\tfrom\tcontinuing\toperations\tbefore\ttaxes\tand\tequity\tin\tearnings\tof\taffiliates | Income\tfrom\tcontinuing\toperations\tbefore\ttaxes\tand\tequity\tin\tearnings\tof\taffiliates | Income\tfrom\tcontinuing\toperations\tbefore\ttaxes\tand\tequity\tin\tearnings\tof\taffiliates | Income\tfrom\tcontinuing\toperations\tbefore\ttaxes\tand\tequity\tin\tearnings\tof\taffiliates | Income\tfrom\tcontinuing\toperations\tbefore\ttaxes\tand\tequity\tin\tearnings\tof\taffiliates | Income\tfrom\tcontinuing\toperations\tbefore\ttaxes\tand\tequity\tin\tearnings\tof\taffiliates | $1,044 | $2,316 | $2,667 |

|  | Total	Assets | Total	Assets | Total	Assets | Amortization | Amortization | Amortization | Capital	Expenditures | Capital	Expenditures | Capital	Expenditures |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2010 | 2009 | 2008 | 2010 | 2009 | 2008 | 2010 | 2009 | 2008 |
|  |  |  |  |  | (in\tmillions) |  |  |  |  |
| Latin\tAmerica—Generation | $10,373 | $9,802 | $8,217 | $215 | $183 | $168 | $641 | $951 | $886 |
| Latin\tAmerica—Utilities | \t 10,081 | 9,233 | 7,124 | 254 | 220 | 221 | 649 | 413 | 437 |
| North\tAmerica—Generation | 4,926 | 6,226 | 6,444 | 206 | 208 | 197 | 81 | 98 | 134 |
| North\tAmerica—Utilities | 3,139 | 3,035 | 3,092 | 161 | 157 | 152 | 177 | 116 | 117 |
| Europe—Generation | 4,191 | 3,184 | 2,885 | 117 | 56 | 49 | 235 | 212 | 534 |
| Asia—Generation | 1,762 | 1,594 | 1,588 | 33 | 32 | 23 | 10 | 22 | 32 |
| Discontinued\tbusinesses | — | 1,196 | 1,387 | 8 | 44 | 53 | 4 | 4 | 13 |
| Corp/Other\tand\teliminations | 6,039 | 5,265 | 4,069 | 184 | 149 | 138 | 536 | 722 | 744 |
| Total | $40,511 | $39,535 | $34,806 | $1,178 | $1,049 | $1,001 | $2,333 | $2,538 | $2,897 |

|  | to	Affiliates | to	Affiliates | to	Affiliates | Equity	in	Earnings	(Loss) | Equity	in	Earnings	(Loss) | Equity	in	Earnings	(Loss) |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2010 | 2009 | 2008 | 2010 | 2009 | 2008 |
|  |  |  | (in\tmillions) |  |  |  |
| Latin\tAmerica—Generation | $150 | $129 | $81 | $48 | $30 | $9 |
| Latin\tAmerica—Utilities | — | — | \t — | \t — | \t — | \t — |
| North\tAmerica—Generation | — | 3 | 2 | (2) | (2) | (2) |
| North\tAmerica—Utilities | — | — | 1 | \t — | \t — | \t — |
| Europe—Generation | 353 | 308 | \t 232 | 19 | 50 | 28 |
| Asia—Generation | 409 | 390 | \t 371 | 3 | 28 | 12 |
| Discontinued\tbusinesses | — | — | \t — | \t — | \t — | \t — |
| Corp/Other\tand\teliminations | 408 | 327 | \t 214 | 115 | (14) | (14) |
| Total | $1,320 | $1,157 | $901 | $183 | $92 | $33 |

The	table	below	presents	information,	by	country,	about	the	Company's	consolidated	operations	for	each	of	the	years	ended	December	31,	2010	through	2008	and as	of	December	31,	2010	and	2009,	respectively.	Revenue	is	recorded	in	the	country	in	which	it	is	earned	and	assets	are	recorded	in	the	country	in	which	they	are located.

|  |  |  |  | Property,	Plant	&amp; |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | Revenue | Revenue | Revenue | Equipment,\tnet | Equipment,\tnet |
|  | 2010 | 2009 | 2008 | 2010 | 2009 |
|  |  |  | (in\tmillions) |  |  |
| United\tStates | $2,615 | $2,545 | $2,745 | $6,167 | $7,016 |
| Non-U.S.: |  |  |  |  |  |
| Brazil | 6,473 | 5,394 | 5,501 | 6,413 | 5,799 |
| Chile | 1,355 | 1,239 | 1,349 | 2,560 | 2,321 |
| Argentina | 887 | 684 | 949 | 459 | 448 |
| El\tSalvador | 648 | 619 | 484 | 261 | 254 |
| Dominican\tRepublic | 535 | 429 | 601 | 625 | 634 |
| Philippines^(1) | 501 | 250 | 148 | 784 | 765 |
| Cameroon | 422 | 370 | 379 | 823 | 742 |
| Spain^(2) | 411 | — | — | 667 | — |
| Mexico | 409 | 329 | 463 | 786 | 802 |
| Colombia | 393 | 347 | 291 | 387 | 390 |
| United\tKingdom | 385 | 241 | 342 | 527 | 433 |
| Ukraine | 356 | 286 | 403 | 86 | 80 |
| Hungary | 296 | 317 | 466 | 80 | 196 |
| Puerto\tRico | 253 | 267 | 251 | 596 | 609 |
| Panama | 194 | 168 | 210 | 921 | 834 |
| Kazakhstan | 138 | 123 | 234 | 63 | 48 |
| Jordan | 120 | 104 | 47 | 224 | 231 |
| Sri\tLanka | 100 | 109 | 184 | 69 | 74 |
| Bulgaria^(3) | 44 | — | — | 1,825 | 1,835 |
| Qatar^(4) | — | — | — | — | — |
| Pakistan^(5) | — | — | — | — | — |
| Oman^(6) | — | — | — | — | — |
| Other\tNon-U.S. | 112 | 133 | 150 | 298 | 285 |
| Total\tNon-U.S. | \t 14,032 | \t 11,409 | \t 12,452 | \t 18,454 | \t 16,780 |
| Total | $16,647 | $13,954 | $15,197 | $24,621 | $23,796 |

# 16.	SHARE-BASED	COMPENSATION

STOCK	OPTIONS—AES	grants	options	to	purchase	shares	of	common	stock	under	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.	Stock	options	are	generally granted	based	upon	a	percentage	of	an	employee's	base	salary.	Stock	options	issued	under	these	plans	in	2010,	2009	and	2008	have	a	three-year	vesting	schedule	and vest	in	one-third	increments	over	the	three-year	period.	The	stock	options	have	a	contractual	term	of	ten	years.	At	December	31,	2010,	approximately	20	million	shares were	remaining	for	award	under	the	plans.	In	all	circumstances,	stock	options	granted	by	AES	do	not	entitle	the	holder	the	right,	or	obligate	AES,	to	settle	the	stock option	in	cash	or	other	assets	of	AES.

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

|  | 2010 | 2009 | 2008 |
| :--- | :--- | :--- | :--- |
| Expected\tvolatility | 38\t% | 66\t% | 37\t% |
| Expected\tannual\tdividend\tyield | \t —\t\t% | \t —\t\t% | \t —\t\t% |
| Expected\toption\tterm\t(years) | 6 | 6 | 6 |
| Risk-free\tinterest\trate | \t2.86\t% | \t2.01\t% | \t3.04\t% |

The	Company	exclusively	relies	on	implied	volatility	as	the	expected	volatility	to	determine	the	fair	value	using	the	Black-Scholes	option-pricing	model.	The implied	volatility	may	be	exclusively	relied	upon	due	to	the	following	factors:

•The	Company	utilizes	a	valuation	model	that	is	based	on	a	constant	volatility	assumption	to	value	its	employee	share	options;

•The	implied	volatility	is	derived	from	options	to	purchase	AES	common	stock	that	are	actively	traded;

•The	market	prices	of	both	the	traded	options	and	the	underlying	shares	are	measured	at	a	similar	point	in	time	and	on	a	date	reasonably	close	to	the	grant date	of	the	employee	share	options;

•The	traded	options	have	exercise	prices	that	are	both	near-the-money	and	close	to	the	exercise	price	of	the	employee	share	options;	and

•The	remaining	maturities	of	the	traded	options	on	which	the	estimate	is	based	are	at	least	one	year.

Pursuant	to	share-based	compensation	accounting	guidance,	the	Company	used	a	simplified	method	to	determine	the	expected	term	based	on	the	average	of	the original	contractual	term	and	the	pro	rata	vesting	period.	This	simplified	method	was	used	for	stock	options	granted	during	2010,	2009	and	2008.	This	is	appropriate given	a	lack	of	relevant	stock	option	exercise	data.	This	simplified	method	may	be	used	as	the	Company's	stock	options	have	the	following	characteristics:

•The	stock	options	are	granted	at-the-money;

•Exercisability	is	conditional	only	on	performing	service	through	the	vesting	date;

•If	an	employee	terminates	service	prior	to	vesting,	the	employee	forfeits	the	stock	options;

•If	an	employee	terminates	service	after	vesting,	the	employee	has	a	limited	time	to	exercise	the	stock	option;	and

•The	stock	option	is	nonhedgeable	and	not	transferable.

The	Company	does	not	discount	the	grant	date	fair	values	to	estimate	post-vesting	restrictions.	Post-vesting	restrictions	include	black-out	periods	when	the employee	is	not	able	to	exercise	stock	options	based	on	their	potential	knowledge	of	information	prior	to	the	release	of	that	information	to	the	public.

The	following	table	summarizes	the	components	of	stock-based	compensation	related	to	employee	stock	options	recognized	in	the	Company's	financial statements:

|  | 2010 | 2009 | 2008 |
| :--- | :--- | :--- | :--- |
|  |  | (in\tmillions) |  |
| Pre-tax\tcompensation\texpense | $9 | $10 | $12 |
| Tax\tbenefit | (2) | (3) | (3) |
| Stock\toptions\texpense,\tnet\tof\ttax | $7 | $7 | $9 |
| Total\tintrinsic\tvalue\tof\toptions\texercised | $2 | $3 | $9 |
| Total\tfair\tvalue\tof\toptions\tvested | 11 | 13 | \t 13 |
| Cash\treceived\tfrom\tthe\texercise\tof\tstock\toptions | 2 | 6 | \t 17 |
| Windfall\ttax\tbenefits\trealized\tfrom\tthe\texercised\tstock\toptions | \t — | \t — | 1 |

There	was	no	cash	used	to	settle	stock	options	or	compensation	cost	capitalized	as	part	of	the	cost	of	an	asset	for	the	years	ended	December	31,	2010,	2009	and 2008.	As	of	December	31,	2010,	$5	million	of	total	unrecognized	compensation	cost	related	to	stock	options	is	expected	to	be	recognized	over	a	weighted	average	period of	1.5	years.	There	were	no	modifications	to	stock	option	awards	during	the	year	ended	December	31,	2010.

A	summary	of	the	option	activity	for	the	year	ended	December	31,	2010	follows	(number	of	options	in	thousands,	dollars	in	millions	except	per	option	amounts):

|  | Options | Weighted<br>Average<br>Exercise<br>Price | Weighted	Average<br>Remaining<br>Contractual	Term<br>(in	years) | Aggregate<br>Intrinsic<br>Value |
| :--- | :--- | :--- | :--- | :--- |
| Outstanding\tat\tDecember\t31,\t2009 | \t22,372 | $17.59 |  |  |
| Exercised | (338) | 6.09 |  |  |
| Forfeited\tand\texpired | \t(2,380) | 30.89 |  |  |
| Granted | 828 | 12.17 |  |  |
| Outstanding\tat\tDecember\t31,\t2010 | \t20,482 | $16.04 | 3.1 | $25 |
| Vested\tand\texpected\tto\tvest\tat\tDecember\t31,\t2010 | \t20,150 | $16.10 | 2.6 | $24 |
| Eligible\tfor\texercise\tat\tDecember\t31,\t2010 | \t18,079 | $16.68 | 2.4 | $20 |

The	aggregate	intrinsic	value	in	the	table	above	represents	the	total	pre-tax	intrinsic	value	(the	difference	between	the	Company's	closing	stock	price	on	the	last trading	day	of	the	fourth	quarter	of	2010	and	the	exercise	price,	multiplied	by	the	number	of	in-the-money	options)	that	would	have	been	received	by	the	option	holders had	all	option	holders	exercised	their	options	on	December	31,	2010.	The	amount	of	the	aggregate	intrinsic	value	will	change	based	on	the	fair	market	value	of	the Company's	stock.

The	Company	initially	recognizes	compensation	cost	on	the	estimated	number	of	instruments	for	which	the	requisite	service	is	expected	to	be	rendered.	In	2010, AES	has	estimated	a	forfeiture	rate	of	18.6%	and	12.09%	for	stock	options	granted	in	2010	to	non-officer	employees	and	officer	employees	of	AES,	respectively.	Those estimates	will	be	revised	if	subsequent	information	indicates	that	the	actual	number	of	instruments	forfeited	is	likely	to	differ	from	previous	estimates.	Based	on	the estimated	forfeiture	rates,	the	Company	expects	to	expense	$3.7	million	on	a	straight-line	basis	over	a	three	year	period	(approximately	$1.2	million	per	year)	related	to stock	options	granted	during	the	year	ended	December	31,	2010.

# RESTRICTED	STOCK

Restricted	Stock	Units	Without	Market	Conditions—The	Company	issues	restricted	stock	units	("RSUs")	without	market	conditions	under	its	long-term compensation	plan.	The	RSUs	are	generally	granted	based	upon	a	percentage	of	the	participant's	base	salary.	The	units	have	a	three-year	vesting	schedule	and	vest	in one-third	increments	over	the	three-year	period.	The	units	are	then	required	to	be	held	for	an	additional	two	years	before	they	can	be	converted	into	shares,	and	thus become	transferable.	In	all	circumstances,	restricted	stock	units	granted	by	AES	do	not	entitle	the	holder	the	right,	or	obligate	AES,	to	settle	the	restricted	stock	unit	in cash	or	other	assets	of	AES.

For	the	years	ended	December	31,	2010,	2009,	and	2008,	RSUs	issued	without	a	market	condition	had	a	grant	date	fair	value	equal	to	the	closing	price	of	the Company's	stock	on	the	grant	date.	The	Company	does	not	discount	the	grant	date	fair	values	to	reflect	any	post-vesting	restrictions.	RSUs	without	a	market	condition granted	to	non-executive	employees	during	the	years	ended	December	31,	2010,	2009,	and	2008	had	grant	date	fair	values	per	RSU	of	$12.18,	$6.71	and	$18.87, respectively.	The	total	grant	date	fair	value	of	RSUs	granted	in	2010	without	a	market	condition	was	$13	million.

The	following	table	summarizes	the	components	of	the	Company's	stock-based	compensation	related	to	its	employee	RSUs	issued	without	market	conditions recognized	in	the	Company's	consolidated	financial	statements:

|  | 2010 | 2009 | 2008 |
| :--- | :--- | :--- | :--- |
|  |  | (in\tmillions) |  |
| RSU\texpense\tbefore\tincome\ttax | $11 | $11 | $10 |
| Tax\tbenefit | (2) | (3) | (2) |
| RSU\texpense,\tnet\tof\ttax | $9 | $8 | $8 |
| Total\tvalue\tof\tRSUs\tconverted^(1) | $5 | $7 | $— |
| Total\tfair\tvalue\tof\tRSUs\tvested | $12 | $12 | $10 |

Amount	represents	fair	market	value	on	the	date	of	conversion.

There	was	no	cash	used	to	settle	RSUs	or	compensation	cost	capitalized	as	part	of	the	cost	of	an	asset	for	the	years	ended	December	31,	2010,	2009	and	2008.	As of	December	31,	2010,	$11	million	of	total	unrecognized	compensation	cost	related	to	RSUs	without	a	market	condition	is	expected	to	be	recognized	over	a	weighted average	period	of	approximately	1.8	years.	There	were	no	modifications	to	RSU	awards	during	the	year	ended	December	31,	2010.

A	summary	of	the	activity	of	RSUs	without	a	market	condition	for	the	year	ended	December	31,	2010	follows	(number	of	RSUs	in	thousands):

|  | RSUs | Weighted	Average<br>Grant	Date	Fair<br>Values | Weighted	Average<br>Remaining<br>Vesting	Term |
| :--- | :--- | :--- | :--- |
| Nonvested\tat\tDecember\t31,\t2009 | \t2,471 | $10.73 |  |
| Vested | (929) | 12.56 |  |
| Forfeited\tand\texpired | (455) | 12.20 |  |
| Granted | \t1,080 | 12.18 |  |
| Nonvested\tat\tDecember\t31,\t2010 | \t2,167 | $10.20 | 1.5 |
| Vested\tat\tDecember\t31,\t2010 | \t2,226 | $16.48 |  |
| Vested\tand\texpected\tto\tvest\tat\tDecember\t31,\t2010 | \t3,999 | $13.67 |  |

The	table	below	summarizes	the	RSUs	without	a	market	condition	that	vested	and	were	converted	during	the	years	ended	December	31,	2010,	2009	and	2008 (number	of	RSUs	in	thousands):

|  | 2010 | 2009 | 2008 |
| :--- | :--- | :--- | :--- |
| RSUs\tvested\tduring\tthe\tyear | \t929 | \t619 | \t597 |
| RSUs\tconverted\tduring\tthe\tyear^(1) | \t386 | \t772 | 59 |

Restricted	Stock	Units	With	Market	Conditions—Restricted	stock	units	issued	to	officers	of	the	Company	have	a	three-year	vesting	schedule	and	include	a market	condition	to	vest.	Vesting	will	occur	if	the	applicable	continued	employment	conditions	are	satisfied	and	the	Total	Stockholder	Return	("TSR")	on	AES	common stock	exceeds	the	TSR	of	the	Standard	and	Poor's	500	("S&P	500")	over	the	three-year	measurement	period	beginning	on	January	1st	in	the	year	of	grant	and	ending after	three	years	on	December	31st.	In	certain	situations	where	the	TSR	of	both	AES	common	stock	and	the	S&P	500	exhibit	a	gain	over	the	measurement	period,	the grant	may	vest	without	the	TSR	of	AES	common	stock	exceeding	the	TSR	of	the	S&P	500,	if	the	Compensation	Committee	exercises	its	discretion	to	permit	such vesting.	The	units	are	then	required	to	be	held	for	an	additional	two	years	subsequent	to	vesting	before	they	can	be	converted	into	shares,	and	thus	become	transferable. In	all	circumstances,	restricted	stock	units	granted	by	AES	do	not	entitle	the	holder	the	right,	or	obligate	AES,	to	settle	the	restricted	stock	unit	in	cash	or	other	assets	of AES.

The	effect	of	the	market	condition	on	restricted	stock	units	issued	to	officers	of	the	Company	is	reflected	in	the	award's	fair	value	on	the	grant	date	for	the	year ended	December	31,	2010.	A	discount	of	5.0%	was	applied	to	the	closing	price	of	the	Company's	stock	on	the	date	of	grant	to	estimate	the	fair	value	to	reflect	the	market condition	for	RSUs	with	market	conditions	granted	during	the	year	ended	December	31,	2010.	RSUs	that	included	a	market	condition	granted	during	the	year	ended December	31,	2010,	2009	and	2008	had	a	grant	date	fair	value	per	RSU	of	$11.57,	$6.68	and	$16.23,	respectively.	The	total	grant	date	fair	value	of	RSUs	with	a	market condition	granted	in	2010	was	$4	million.	If	no	discount	was	applied	to	reflect	the	market	condition	for	RSUs	issued	to	officers,	the	total	grant	date	fair	value	of	RSUs with	a	market	condition	granted	during	the	year	ended	December	31,	2010	would	have	increased	by	an	immaterial	amount.

The	following	table	summarizes	the	components	of	the	Company's	stock-based	compensation	related	to	its	RSUs	granted	with	market	conditions	recognized	in the	Company's	consolidated	financial	statements:

|  | 2010 | 2009 | 2008 |
| :--- | :--- | :--- | :--- |
|  |  | (in\tmillions) |  |
| RSU\texpense\tbefore\tincome\ttax | $4 | $4 | $4 |
| Tax\tbenefit | (1) | (1) | (1) |
| RSU\texpense,\tnet\tof\ttax | $3 | $3 | $3 |
| Total\tvalue\tof\tRSUs\tconverted^(1) | $3 | $4 | $— |
| Total\tfair\tvalue\tof\tRSUs\tvested^(2) | $— | $— | $5 |

RSUs	granted	in	2007	with	a	market	condition	did	not	vest	in	2010	because	the	TSR	on	AES	common	stock	did	not	exceed	the	TSR	of	the	S&P	500	over	the	three year	vesting	period.

There	was	no	cash	used	to	settle	RSUs	or	compensation	cost	capitalized	as	part	of	the	cost	of	an	asset	for	the	years	ended	December	31,	2010,	2009	and	2008.	As of	December	31,	2010,	$5	million	of	total	unrecognized	compensation	cost	related	to	RSUs	with	a	market	condition	is	expected	to	be	recognized	over	a	weighted average	period	of	approximately	1.7	years.	There	were	no	modifications	to	RSU	awards	during	the	year	ended	December	31,	2010.

A	summary	of	the	activity	of	RSUs	with	a	market	condition	for	the	year	ended	December	31,	2010	follows	(number	of	RSUs	in	thousands):

|  | RSUs | Weighted	Average<br>Grant	Date	Fair<br>Values | Weighted	Average<br>Remaining<br>Vesting	Term |
| :--- | :--- | :--- | :--- |
| Nonvested\tat\tDecember\t31,\t2009 | \t1,136 | $10.80 |  |
| Vested | — | — |  |
| Forfeited\tand\texpired | (223) | 17.78 |  |
| Granted | 370 | 11.57 |  |
| Nonvested\tat\tDecember\t31,\t2010 | \t1,283 | $9.80 | 1.3 |
| Vested\tat\tDecember\t31,\t2010 | — | $— |  |
| Vested\tand\texpected\tto\tvest\tat\tDecember\t31,\t2010 | \t1,125 | $9.76 |  |

The	table	below	summarizes	the	RSUs	with	a	market	condition	that	vested	and	were	converted	during	the	years	ended	2010,	2009	and	2008	(number	of	RSUs	in thousands):

|  | 2010 | 2009 | 2008 |
| :--- | :--- | :--- | :--- |
| RSUs\tvested\tduring\tthe\tyear | \t— | \t— | \t352 |
| RSUs\tconverted\tduring\tthe\tyear^(1) | \t245 | \t410 | \t— |

Net	of	shares	withheld	for	taxes	of	102,000	and	153,000	during	the	years	ended	December	31,	2010	and	2009,	respectively.	There	were	no	shares	withheld	for taxes	during	the	year	ended	December	31,	2008.

# 17.	SUBSIDIARY	STOCK

The	Company's	subsidiary	had	$60	million	of	cumulative	preferred	stock	outstanding	at	December	31,	2010	and	2009.	This	represented	five	series	of	preferred stock	of	IPL,	the	Company's	integrated	utility	in	Indiana.	The	total	annual	dividend	requirements	were	approximately	$3	million	at	December	31,	2010	and	2009.	Certain series	of	the	preferred	stock	were	redeemable	solely	at	the	option	of	the	issuer	at	prices	between	$100	and	$118	per	share.	Holders	of	the	preferred	stock	are	entitled	to elect	a	majority	of	IPL's	board	of	directors	if	IPL	has	not	paid	dividends	to	its	preferred	stockholders	for	four	consecutive	quarters.	Based	on	the	preferred	stockholders' ability	to	elect	a	majority	of	IPL's	board	of	directors	in	this	circumstance,	the	redemption	of	the	preferred	shares	is	considered	to	be	not	solely	within	the	control	of	the issuer	and	the	preferred	stock	is	considered	temporary	equity	and	presented	in	the	mezzanine	level	of	the	Consolidated	Balance	Sheets	in	accordance	with	the	relevant accounting	guidance	for	noncontrolling	interests	and	redeemable	securities.

In	February	2009,	in	connection	with	a	preemptive	rights	period	associated	with	a	share	issuance	(capital	increase)	at	AES	Gener,	Inversiones	Cachagua	Limitada ("Cachagua"),	a	wholly	owned	subsidiary	of	the	Company,	paid	$175	million	to	AES	Gener	to	maintain	its	current	ownership	percentage	of	approximately	70.6%.

On	November	6,	2008,	Cachagua	sold	a	9.6%	ownership	interest	in	AES	Gener	in	a	private	transaction	for	$174.9	million.	The	sale	reduced	the	Company's ownership	percentage	of	AES	Gener	from	80.2%	to	70.6%.	The	Company	recognized	a	pre-tax	loss	of	$30.8	million,	net	of	$3.6	million	of	related	fees,	from	this transaction	in	the	fourth	quarter	of	2008.

# 18.	OTHER	INCOME	AND	EXPENSE

The	components	of	other	income	are	summarized	as	follows:

|  | 2010 | 2009 | 2008 |
| :--- | :--- | :--- | :--- |
|  |  | (in\tmillions) |  |
| Gain\ton\textinguishment\tof\ttax\tand\tother\tliabilities | $65 | $ 168 | $199 |
| Tax\tcredit\tsettlement | \t — | 129 | — |
| Performance\tincentive\tfee | \t — | 80 | — |
| Insurance\tproceeds | \t — | \t — | 40 |
| Gain\ton\tsale\tof\tassets | 12 | 14 | 34 |
| Other | 31 | 74 | 102 |
| Total\tother\tincome | $ 108 | $ 465 | $375 |

Other	income	generally	includes	gains	on	asset	sales	and	extinguishments	of	liabilities,	favorable	judgments	on	contingencies,	and	other	income	from miscellaneous	transactions.

Other	income	of	$108	million	for	the	year	ended	December	31,	2010	included	the	extinguishment	of	a	swap	liability	owed	by	two	of	our	Brazilian	subsidiaries, resulting	in	the	recognition	of	a	$62	million	gain.	The	net	impact	to	the	Company	after	taxes	and	noncontrolling	interest	was	$9	million.	Other	income	also	included	a gain	on	sale	of	assets	at	Eletropaulo.

Other	income	of	$465	million	for	the	year	ended	December	31,	2009	included	$165	million	from	the	reduction	in	interest	and	penalties	associated	with	federal	tax debts	at	Eletropaulo	and	Sul	as	a	result	of	the	Programa	de	Recuperacao	Fiscal	("REFIS")	program	and	a	$129	million	gain	related	to	a	favorable	court	decision	enabling Eletropaulo	to	receive	reimbursement	of	excess	non-income	taxes	paid	from	1989	to	1992	in	the	form	of	tax	credits	to	be	applied	against	future	tax	liabilities.	The	net impact	to	the	Company	after	income	taxes	and	noncontrolling	interests	for	these	items	was	$44	million.	In	addition,	the	Company	recognized	income	of	$80	million from	a	performance	incentive	bonus	for	management	services	provided	to	Ekibastuz	and	Maikuben	in	2008.	The	management	agreement	was	related	to	the	sale	of	these businesses	in	Kazakhstan	in	May	2008;	see	further	discussion	of	this	transaction	in	Note	22—Acquisitions	and	Dispositions.

The	components	of	other	expense	are	summarized	as	follows:

|  | 2010 | 2009 | 2008 |
| :--- | :--- | :--- | :--- |
|  |  | (in\tmillions) |  |
| Loss\ton\tsale\tand\tdisposal\tof\tassets | $84 | $42 | $34 |
| Gener\tgas\tsettlement | 72 | \t — | — |
| Loss\ton\textinguishment\tof\tdebt | 37 | \t — | 70 |
| AES\tWind\ttransaction\tcosts | 22 | \t — | — |
| Other | 24 | 69 | 57 |
| Total\tother\texpense | $239 | $111 | $161 |

Other	expense	generally	includes	losses	on	asset	sales,	losses	on	extinguishment	of	debt,	legal	contingencies	and	losses	from	other	miscellaneous	transactions.

Other	expense	of	$239	million	for	the	year	ended	December	31,	2010	included	$72	million	for	a	settlement	agreement	of	gas	transportation	contracts	at	Gener. There	were	also	previously	capitalized	transaction	costs	of	$22	million	that	were	incurred	in	connection	with	the	preparation	for	the	sale	of	a	noncontrolling	interest	in our	Wind	Generation	business.	These	costs	were	written	off	upon	the	expiration	of	the	letter	of	intent	on	June	30,	2010.	In	addition,	there	were	losses	on	disposal	of assets	at	Eletropaulo,	Panama,	and	Gener,	an	$18	million	loss	on	debt	extinguishment	at	Andres	and	Itabo,	and	a	$15	million	loss	at	the	Parent	Company	from	the retirement	of	senior	notes.

Other	expense	of	$111	million	for	the	year	ended	December	31,	2009	included	a	$13	million	loss	recognized	when	three	of	our	businesses	in	the	Dominican Republic	received	$110	million	par	value	bonds	issued	by	the	Dominican	Republic	government	to	settle	existing	accounts	receivable	for	the	same	amount	from	the government-owned	distribution	companies.	The	loss	represented	an	adjustment	to	reflect	the	fair	value	of	the	bonds	on	the	date	received.	Other	expenses	also	included losses	on	the	disposal	of	assets	at	Eletropaulo	and	Andres	and	contingencies	at	Alicura	in	Argentina	and	our	businesses	in	Kazakhstan.

Other	expense	of	$161	million	for	the	year	ended	December	31,	2008	included	$69	million	of	losses	on	the	retirement	of	debt	at	the	Parent	Company	in	June	2008 and	at	IPALCO	associated	with	a	$375	million	refinancing	in	April	2008,	and	losses	on	the	disposal	of	assets	primarily	at	Eletropaulo	in	Brazil.

# 19.	IMPAIRMENT	EXPENSE

# Asset	Impairment

Asset	impairment	expense	for	the	year	ended	December	31,	2010	consisted	of:

Eastern	Energy—AES	Eastern	Energy	("AEE")	operates	four	coal-fired	power	plants:	Cayuga,	Greenidge,	Somerset	and	Westover,	representing	generation capacity	of	1,169	MW	in	the	western	New	York	power	market.	During	2010,	the	power	prices	in	the	New	York	power	market	trended	downward,	similar	to	North America	natural	gas	prices.	The	New	York	Independent	System	Operator	("NYISO")	continues	to	move	forward	with	the	potential	addition	of	a	new	capacity	zone, which	is	expected	to	put	further	downward	pressure	on	the	capacity	prices	paid	to	the	AEE	facilities.	In	November	2010,	legislation	was	proposed	in	the	state	of	New Jersey	for	the	addition	of	state	subsidized	capacity	additions	serving	to	lower	PJM	("Pennsylvania,	New	Jersey	and	Maryland")	Interconnection,	L.L.C.	capacity	price expectations.	Similar	changes	to	capacity	pricing	may	be	made	in	the	future	in	New	York.	Continued	pressure	on	energy	prices,	driven	by	falling	natural	gas	prices	and state	actions,	indicate	that	capacity	prices	are	unlikely	to	reach	levels	significantly	in	excess	of	those	achieved	historically.	Accordingly,	management's	view	of	long- term	capacity	markets	in	western	New	York	was	revised	downward.	In	December	2010,	management	revised	its	cash	flow	forecasts	based	on	these	developments	and forecasted	continuing	negative	operating	cash	flow	and	losses	through	2034.	The	forecasted	energy	prices	are	such	that	a	hedge	strategy	significantly	beyond	those	in place	at	December	31,	2010	would	not	be	economical.	Additionally,	on	November	15,	2010,	Standard	&	Poor's	downgraded	the	bond	rating	of	AEE	from	BB	to	B+. Collectively,	in	the	fourth	quarter	of	2010,	these	events	were	considered	an	impairment	indicator	for	the	AES	New	York	asset	group,	of	which	AEE	is	the	most significant	component	and	necessitated	a	recoverability	test	of	the	asset	group.

In	determining	the	fair	value	of	the	asset	group,	the	three	valuation	approaches	prescribed	by	the	fair	value	measurement	accounting	guidance	were	considered. The	fair	value	under	the	income	approach	was	considered	the	most	appropriate	and	resulted	in	a	zero	fair	value.	Any	salvage	value	of	the	asset	group	is	expected	to	be offset	by	environmental	and	other	remediation	costs.	The	carrying	value	of	the	AEE	plants	of	$827	million	exceeded	the	fair	value	of	$0	million	resulting	in	the recognition	of	asset	impairment	expense	of	$827	million	for	the	year	ended	December	31,	2010.	AEE	is	reported	in	the	North	America	Generation	segment.

Southland—In	May	2010,	the	California	State	Water	Board	approved	a	policy	to	reduce	the	number	of	marine	animals	killed	by	seawater	cooling	systems	in coastal	power	plants	in	California.	At	that	time	since	the	policy	required	the	approval	of	California's	Office	of	Administrative	Law,	it	was	unclear	whether	the	policy would	be	approved	and	the	exact	form	the	regulations	would	take.	In	October	2010,	the	Office	of	Administrative	Law	in	California	approved	the	policy	that	will	require the	Company	to	change	the	process	through	which	it	uses	ocean	water	to	cool	the	generation	turbines	at	its	Alamitos,	Huntington	Beach	and	Redondo	Beach (collectively	"Southland")	gas-fired	generation	facilities	in	California.	The	policy	requires	compliance	with	the	new	regulations	by	December	31,	2020.	The	change	in the	water	cooling	process	will	result	in	significant	future	capital	expenditures	to	ensure	compliance	with	the	new	regulations	and	the	Company	determined	that	an indicator	of	impairment	existed	at	September	30,	2010.	The	Company	performed	an	asset	impairment	test	in	accordance	with	the	accounting	guidance	on	property,	plant and	equipment.	The	asset	group	was	determined	to	be	at	the	individual	plant	level	and	based	on	the	undiscounted	cash	flow	analysis,	the	Company	determined	that 260

the	Huntington	Beach	asset	group	was	not	recoverable.	The	fair	value	of	the	Huntington	Beach	asset	group	was	then	determined	using	a	discounted	cash	flow	analysis. To	assist	management	in	determining	the	fair	value	of	the	asset	group,	an	independent	valuation	firm	was	engaged.	Cash	flow	forecasts	and	the	underlying	assumptions for	the	valuation	were	developed	by	management.	The	carrying	value	of	the	Huntington	Beach	plant	of	$288	million	exceeded	the	fair	value	of	$88	million	resulting	in the	recognition	of	asset	impairment	expense	of	$200	million	for	the	year	ended	December	31,	2010.	The	undiscounted	cash	flows	of	the	Alamitos	and	Redondo	Beach generation	facilities	exceeded	their	respective	carrying	values	and	resulted	in	no	impairment.	Huntington	Beach	is	reported	in	the	North	America	Generation	reportable segment.

Tisza	II—During	the	third	quarter	of	2010,	the	Company	entered	into	annual	negotiations	with	the	offtaker	of	its	Tisza	II	generation	plant	in	Hungary.	As	a	result of	these	preliminary	negotiations,	as	well	as	the	further	deterioration	of	the	economic	environment	in	Hungary,	the	Company	determined	that	an	indicator	of	impairment existed	at	September	30,	2010.	Thus,	the	Company	performed	an	asset	impairment	test	in	accordance	with	the	accounting	guidance	on	property,	plant	and	equipment	and determined	that	based	on	the	undiscounted	cash	flow	analysis,	the	carrying	amount	of	the	Tisza	II	asset	group	was	not	recoverable.	The	fair	value	of	the	asset	group	was then	determined	using	a	discounted	cash	flow	analysis.	The	carrying	value	of	the	Tisza	II	asset	group	of	$160	million	exceeded	the	fair	value	of	$75	million	resulting	in the	recognition	of	asset	impairment	expense	of	$85	million	during	the	year	ended	December	31,	2010.	Tisza	II	is	reported	in	the	Europe	Generation	reportable	segment.

In	the	fourth	quarter	of	2010,	further	adverse	trends	in	energy	and	pet	coke	pricing	curves	were	observed	in	management's	review	of	external	market	analyses. The	most	significant	impact	on	the	forecasted	energy	prices	reviewed	by	management	in	November	2010	related	to	the	general	external	market	consensus	that	Federal CO 	cap	and	trade	legislation	was	less	likely,	resulting	in	a	drop	in	long-term	energy	price	projections.	At	that	time,	Deepwater's	revised	forecasts	indicated	that Deepwater	would	have	operating	losses	which	would	extend	beyond	2020	and	negative	cash	flows	through	2019.	Management	concluded	that,	on	an	undiscounted	cash flow	basis,	the	carrying	amount	of	the	asset	group	was	no	longer	recoverable.	To	measure	the	amount	of	impairment	loss,	management	was	required	to	determine	the	fair value	of	the	asset	group.	To	this	end,	an	independent	valuation	firm	was	engaged	to	assist	management	in	its	estimation	of	fair	value.	Cash	flow	forecasts	and	the underlying	assumptions	for	the	valuation	were	developed	by	management.	In	determining	the	fair	value	of	the	asset	group,	all	three	valuation	approaches	described	by the	fair	value	measurement	accounting	guidance	were	considered.

The	fair	value	under	the	income	approach	was	considered	most	appropriate.	On	that	basis,	the	carrying	value	of	the	asset	group	was	determined	to	be	impaired	and	$79 million	of	impairment	expense	was	recognized	in	the	fourth	quarter	of	2010.	Deepwater	is	reported	in	the	North	America	Generation	reportable	segment.

During	the	fourth	quarter	of	2009,	the	Company	recognized	a	pre-tax	long-lived	asset	impairment	charge	of	$11	million	related	to	the	Company's	Piabanha	hydro project	in	Brazil.	The	Company	determined	that	the	carrying	value	exceeded	the	future	discounted	cash	flows	and	abandoned	the	project.	Piabanha	is	reported	in	the Company's	Latin	America	Generation	segment.

In	the	fourth	quarter	of	2008	and	in	response	to	the	financial	market	crisis,	the	Company	reviewed	and	prioritized	projects	in	the	development	pipeline.	From	this review,	the	Company	determined	that	the	carrying	value	exceeded	the	future	discounted	cash	flows	for	certain	projects.	In	accordance	with	the	accounting	standards	for the	impairment	or	disposal	of	long-lived	assets,	the	Company	recorded	a	total	pre-tax	impairment	charge	of	$75	million	($34	million,	net	of	noncontrolling	interests	and income	taxes)	related	to	two	liquefied	natural	gas	projects	in	North	America	and	a	non-power	development	project	at	one	of	our	facilities	in	North	America.	These projects	were	reported	in	the	North	America	Generation	segment.

Following	an	initial	impairment	charge	in	the	fourth	quarter	of	2007	at	Uruguaiana,	there	were	impairment	charges	of	$36	million	recognized	during	the	first	three quarters	of	2008.	The	impairment	was	triggered	by	a	combination	of	gas	curtailments	and	increases	in	the	spot	market	price	of	energy	in	2007	that	continued	in	2008. The	additional	impairment	charges	in	2008	were	primarily	due	to	fixed	asset	purchase	agreements	in	place.	Uruguaiana	is	a	thermoelectric	generation	plant	located	in Brazil	and	reported	in	the	Latin	America	Generation	segment.

The	Company	recognized	impairment	charges	totaling	$31	million	related	to	a	project	in	South	Africa	the	Company	withdrew	from	during	the	first	quarter	of 2008.	These	represented	project	development	costs	and	an	impairment	of	turbine	deposits	related	to	the	project.	All	costs	capitalized	and	incurred	on	the	project	have been	written	off	as	no	future	benefit	is	expected	from	these	assets.	This	project	was	reported	in	"Corporate	and	Other."

The	Anhui	Development	and	Reform	commission	issued	notice	to	our	Hefei	plant	in	China,	in	March	2007	as	a	result	of	the	2007	State	Council's	decision	to	shut down	smaller,	inefficient	and	potentially	polluting	generation	units	nationwide.	A	settlement	agreement	was	signed	March	30,	2008	to	end	the	contractual	PPA arrangement.	In	accordance	with	the	accounting	standards	for	goodwill	and	other	intangible	assets,	management	concluded	that	the	assets	were	impaired	in	March	2008, since	the	long-lived	asset	group	would	be	sold	or	otherwise	disposed	of	significantly	before	the	end	of	its	previously	estimated	life.	As	a	result,	impairment	charges	of $18	million	were	recognized	associated	with	the	settlement	agreement	to	shut	down	the	Hefei	plant,	which	is	reported	in	the	Asia	Generation	segment.

# Other	Impairments

In	addition	to	the	asset	impairment	expense	discussed	above,	other-than-temporary	impairments	of	cost	method	investments	of	$1	million,	$12	million	and	$15 million	were	recorded	in	the	years	ended	December	31,	2010,	2009	and	2008,	respectively.	The	impairment	charges	in	2009	and	2008	primarily	related	to	the Company's	investment	in	a	company	developing	a	commercial	facility	for	a	"blue	gas"	(coal	to	gas)	technology	project.	The	Company	accounted	for	the	investment	in convertible	preferred	shares	under	the	cost	method	of	accounting.	During	the	fourth	quarter	of	2008,	the	market	value	of	the	shares	materially	declined	due	to	downward trends	in	the	capital	markets	and	management	concluded	that	the	decline	was	other-than-temporary	and	recorded	an	impairment	charge	of	$10	million.	In	2009,	this investment	was	determined	to	be	further	impaired	and	an	additional	$10	million	other-than-temporary	impairment	charge,	representing	the	remaining	value	of	the	shares, was	recognized.

# 20.	INCOME	TAXES

# INCOME	TAX	PROVISION

The	following	table	summarizes	the	expense	for	income	taxes	on	continuing	operations,	for	the	years	ended	December	31,	2010,	2009	and	2008:

|  | 2010 | 2009 | 2008 |
| :--- | :--- | :--- | :--- |
|  |  | (in\tmillions) |  |
| Federal: |  |  |  |
| Current | $(8) | $3 | $12 |
| Deferred | (407) | (146) | \t 122 |
| State: |  |  |  |
| Current | 1 | \t — | (1) |
| Deferred | (19) | (9) | (7) |
| Foreign: |  |  |  |
| Current | 699 | 552 | \t 611 |
| Deferred | 41 | 199 | 34 |
| Total | $307 | $599 | $771 |

# EFFECTIVE	AND	STATUTORY	RATE	RECONCILIATION

The	following	table	summarizes	a	reconciliation	of	the	U.S.	statutory	federal	income	tax	rate	to	the	Company's	effective	tax	rate,	as	a	percentage	of	income	from continuing	operations	before	taxes	for	the	years	ended	December	31,	2010,	2009	and	2008:

|  | 2010 | 2009 | 2008 |
| :--- | :--- | :--- | :--- |
| Statutory\tFederal\ttax\trate | 35% | 35% | 35% |
| State\ttaxes,\tnet\tof\tFederal\ttax\tbenefit | (9) | (1) | \t— |
| Taxes\ton\tforeign\tearnings | (9) | (5) | (3) |
| Valuation\tallowance | 11 | \t— | 2 |
| Gain\ton\tsale\tof\tbusinesses | 6 | (3) | \t (12) |
| Chilean\twithholding\ttax\treversals | (5) | \t— | \t— |
| Taxes\ton\tcash\trepatriation | \t— | \t— | 5 |
| Other—net | \t— | \t— | 2 |
| Effective\ttax\trate | 29% | 26% | 29% |

The	current	income	taxes	receivable	and	payable	are	included	in	Other	Current	Assets	and	Accrued	and	Other	Liabilities,	respectively,	on	the	accompanying Consolidated	Balance	Sheets.	The	noncurrent	income	taxes	receivable	and	payable	are	included	in	Other	Assets	and	Other	Long-Term	Liabilities,	respectively,	on	the accompanying	Consolidated	Balance	Sheets.	The	following	table	summarizes	the	income	taxes	receivable	and	payable	as	of	December	31,	2010	and	2009:

|  | December	31, | December	31, |
| :--- | :--- | :--- |
|  | 2010 | 2009 |
|  | (in\tmillions) |  |
| Income\ttaxes\treceivable—current | $520 | $434 |
| Income\ttaxes\treceivable—noncurrent | 21 | 22 |
| Total\tincome\ttaxes\treceivable | $541 | $456 |
| Income\ttaxes\tpayable—current | $701 | $508 |
| Income\ttaxes\tpayable—noncurrent | 8 | 11 |
| Total\tincome\ttaxes\tpayable | $709 | $519 |

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	carryforwards.	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,	2010,	the	Company	had	federal	net	operating	loss	carryforwards	for	tax	purposes	of	approximately	$1.7	billion	expiring	in	years	2023	to 2029.	Approximately	$68	million	of	the	net	operating	loss	carryforward	related	to	stock	option	deductions	will	be	recognized	in	additional	paid-in	capital	when	realized. The	Company	also	had	federal	general	business	tax	credit	carryforwards	of	approximately	$18	million	expiring	primarily	from	2020	to	2030,	and	federal	alternative minimum	tax	credits	of	approximately	$5	million	that	carryforward	without	expiration.	The	Company	had	state	net	operating	loss	carryforwards	as	of	December	31, 2010	of	approximately	$3.5	billion	expiring	in	years	2016	to	2031.	As	of	December	31,	2010,	the	Company	had

foreign	net	operating	loss	carryforwards	of	approximately	$4.6	billion	that	expire	at	various	times	beginning	in	2011	and	some	of	which	carryforward	without	expiration, and	tax	credits	available	in	foreign	jurisdictions	of	approximately	$37	million,	$3	million	of	which	expire	in	2011	to	2013,	$15	million	of	which	expire	in	2014	to	2021 and	$19	million	of	which	carryforward	without	expiration.

Valuation	allowances	decreased	$338	million	during	2010	to	$1.3	billion	at	December	31,	2010.	This	net	decrease	was	primarily	the	result	of	the	removal	of valuation	allowances	against	deferred	tax	assets	at	foreign	subsidiaries.

Valuation	allowances	increased	$268	million	during	2009	to	$1.7	billion	at	December	31,	2009.	This	net	increase	was	primarily	the	result	of	an	increase	in	foreign net	operating	loss	carryforwards	that	required	full	offsetting	valuation	allowances.

The	Company	believes	that	it	is	more	likely	than	not	that	the	net	deferred	tax	assets	as	shown	below	will	be	realized	when	future	taxable	income	is	generated through	the	reversal	of	existing	taxable	temporary	differences	and	income	that	is	expected	to	be	generated	by	businesses	that	have	long-term	contracts	or	a	history	of generating	taxable	income.	The	Company	continues	to	monitor	the	utilization	of	its	deferred	tax	asset	for	its	U.S.	consolidated	net	operating	loss	carryforward.	Although management	believes	it	is	more	likely	than	not	that	this	deferred	tax	asset	will	be	realized	through	generation	of	sufficient	taxable	income	prior	to	expiration	of	the	loss carryforwards,	such	realization	is	not	assured.

The	following	table	summarizes	the	deferred	tax	assets	and	liabilities,	as	of	December	31,	2010	and	2009:

|  | 2010 | 2009 |
| :--- | :--- | :--- |
|  | (in\tmillions) |  |
| Differences\tbetween\tbook\tand\ttax\tbasis\tof\tproperty | $1,245 | $1,693 |
| Cumulative\ttranslation\tadjustment | 94 | (200) |
| Other\ttaxable\ttemporary\tdifferences | 392 | 310 |
| Total\tdeferred\ttax\tliability | 1,731 | 1,803 |
| Operating\tloss\tcarryforwards | (1,657) | (1,701) |
| Capital\tloss\tcarryforwards | (93) | (107) |
| Bad\tdebt\tand\tother\tbook\tprovisions | (544) | (562) |
| Retirement\tcosts | (315) | (283) |
| Tax\tcredit\tcarryforwards | (60) | (68) |
| Other\tdeductible\ttemporary\tdifferences | (414) | (427) |
| Total\tgross\tdeferred\ttax\tasset | (3,083) | (3,148) |
| Less:\tvaluation\tallowance | 1,339 | 1,677 |
| Total\tnet\tdeferred\ttax\tasset | (1,744) | (1,471) |
| Net\tdeferred\ttax\t(asset)/liability | $(13) | $332 |

The	Company	considers	undistributed	earnings	of	certain	foreign	subsidiaries	to	be	indefinitely	reinvested	outside	of	the	United	States	and,	accordingly,	no U.S.	deferred	taxes	have	been	recorded	with	respect	to	such	earnings	in	accordance	with	the	relevant	accounting	guidance	for	income	taxes.	Should	the	earnings	be remitted	as	dividends,	the	Company	may	be	subject	to	additional	U.S.	taxes,	net	of	allowable	foreign	tax	credits.	It	is	not	practicable	to	estimate	the	amount	of	any additional	taxes	which	may	be	payable	on	the	undistributed	earnings.

Income	from	operations	in	certain	countries	is	subject	to	reduced	tax	rates	as	a	result	of	satisfying	specific	commitments	regarding	employment	and	capital investment.	The	Company's	income	tax	benefits	related	to	the	tax	status	of	these	operations	are	estimated	to	be	$60	million,	$35	million	and	$23	million	for	the	years ended	December	31,	2010,	2009	and	2008,	respectively.	The	per	share	effect	of	these	benefits	after	noncontrolling	interests	was	$0.07,	$0.04	and	$0.03	for	the	year ended	December	31,	2010,	2009	and	2008,	respectively.

The	following	table	summarizes	the	income	(loss)	from	continuing	operations,	before	income	taxes,	net	equity	in	earnings	of	affiliates	and	noncontrolling interests,	for	the	years	ended	December	31,	2010,	2009	and	2008:

|  | 2010 | 2009 | 2008 |
| :--- | :--- | :--- | :--- |
|  |  | (in\tmillions) |  |
| U.S. | $(1,342) | $(976) | $(314) |
| Non-U.S. | 2,386 | \t 3,292 | \t 2,981 |
| Total | $1,044 | $2,316 | $2,667 |

# UNCERTAIN	TAX	POSITIONS

Uncertain	tax	positions	have	been	classified	as	noncurrent	income	tax	liabilities	unless	expected	to	be	paid	in	one	year.	The	Company's	policy	for	interest	and penalties	related	to	income	tax	exposures	is	to	recognize	interest	and	penalties	as	a	component	of	the	provision	for	income	taxes	in	the	Consolidated	Statements	of Operations.

As	of	December	31,	2010	and	2009,	the	total	amount	of	gross	accrued	income	tax	related	interest	included	in	the	Consolidated	Balance	Sheets	was	$12	million and	$21	million,	respectively.	The	total	amount	of	gross	accrued	income	tax	related	penalties	included	in	the	Consolidated	Balance	Sheets	as	of	December	31,	2010	and 2009	was	$4	million	and	$5	million,	respectively.

The	total	expense	(benefit)	for	interest	related	to	unrecognized	tax	benefits	for	the	years	ended	December	31,	2010,	2009	and	2008	amounted	to	$(10)	million, $4	million	and	$2	million,	respectively.	For	the	years	ended	December	31,	2010,	2009	and	2008,	the	total	expense	(benefit)	for	penalties	related	to	unrecognized	tax benefits	amounted	to	$(1)	million,	$0	million	and	$(2)	million,	respectively.

We	are	potentially	subject	to	income	tax	audits	in	numerous	jurisdictions	in	the	U.S.	and	internationally	until	the	applicable	statute	of	limitations	expires.	Tax audits	by	their	nature	are	often	complex	and	can	require	several	years	to	complete.	The	following	is	a	summary	of	tax	years	potentially	subject	to	examination	in	the significant	tax	and	business	jurisdictions	in	which	we	operate:

As	of	December	31,	2010,	2009	and	2008,	the	total	amount	of	unrecognized	tax	benefits	was	$437	million,	$511	million	and	$555	million,	respectively.	The	total amount	of	unrecognized	tax	benefits	that	would	benefit	the	effective	tax	rate	as	of	December	31,	2010,	2009	and	2008	is	$412	million,	$484	million	and	$527	million, respectively,	of	which	$51	million,	$55	million	and	$131	million,	respectively,	would	be	in	the	form	of	tax	attributes	that	would	warrant	a	full	valuation	allowance.

The	total	amount	of	unrecognized	tax	benefits	anticipated	to	result	in	a	net	decrease	to	unrecognized	tax	benefits	within	12	months	of	December	31,	2010	is estimated	to	be	between	$4	million	and	$8	million.

The	following	is	a	reconciliation	of	the	beginning	and	ending	amounts	of	unrecognized	tax	benefits	for	the	years	ended	December	31,	2010,	2009	and	2008:

|  | 2010 | 2009 | 2008 |
| :--- | :--- | :--- | :--- |
|  |  | (in\tmillions) |  |
| Balance\tat\tJanuary\t1 | $511 | $555 | $590 |
| Additions\tfor\tcurrent\tyear\ttax\tpositions | 14 | 72 | 6 |
| Additions\tfor\ttax\tpositions\tof\tprior\tyears | 51 | 7 | 80 |
| Reductions\tfor\ttax\tpositions\tof\tprior\tyears | (46) | (9) | (26) |
| Effects\tof\tforeign\tcurrency\ttranslation | (3) | 6 | (74) |
| Settlements | (67) | (104) | (18) |
| Lapse\tof\tstatute\tof\tlimitations | (23) | (16) | (3) |
| Balance\tat\tDecember\t31 | $437 | $511 | $555 |

The	amount	of	settlements	of	uncertain	tax	positions	in	2009	was	primarily	the	result	of	a	non-cash	audit	settlement	for	$105	million	at	a	Brazilian	subsidiary which	resulted	in	no	tax	expense	or	benefit.

The	Company	and	certain	of	its	subsidiaries	are	currently	under	examination	by	the	relevant	taxing	authorities	for	various	tax	years.	The	Company	regularly assesses	the	potential	outcome	of	these	examinations	in	each	of	the	taxing	jurisdictions	when	determining	the	adequacy	of	the	amount	of	unrecognized	tax	benefit recorded.	While	it	is	often	difficult	to	predict	the	final	outcome	or	the	timing	of	resolution	of	any	particular	uncertain	tax	position,	we	believe	we	have	appropriately accrued	for	our	uncertain	tax	benefits.	However,	audit

outcomes	and	the	timing	of	audit	settlements	and	future	events	that	would	impact	our	previously	recorded	unrecognized	tax	benefits	and	the	range	of	anticipated increases	or	decreases	in	unrecognized	tax	benefits	are	subject	to	significant	uncertainty.	It	is	possible	that	the	ultimate	outcome	of	current	or	future	examinations	may exceed	our	provision	for	current	unrecognized	tax	benefits	in	amounts	that	could	be	material,	but	cannot	be	estimated	as	of	December	31,	2010.	Our	effective	tax	rate and	net	income	in	any	given	future	period	could	therefore	be	materially	impacted.

The	following	table	summarizes	the	income	(loss)	on	disposal	and	impairment	for	the	following	discontinued	operations	for	the	years	ended	December	31,	2010, 2009	and	2008:

| Subsidiary | 2010 | 2009 | 2008 |
| :--- | :--- | :--- | :--- |
|  |  | (in\tmillions) |  |
| Barka | $80 | $ — | $— |
| Lal\tPir | (6) | (74) | \t — |
| Pak\tGen | (16) | (76) | \t — |
| Ras\tLaffan | 6 | \t — | \t — |
| Jiaozuo | \t — | \t — | 7 |
| Central\tValley | \t — | \t — | (1) |
| Gain\t(loss)\ton\tdisposal\tand\timpairment,\tafter\ttaxes | $64 | $(150) | $6 |

On	October	20,	2010,	the	Company	completed	the	sale	of	its	55%	equity	interest	in	Ras	Laffan	and	the	associated	operations	company	in	Qatar	for	aggregate proceeds	of	approximately	$234	million.	The	Ras	Laffan	facility,	which	was	previously	reported	in	the	Asia	Generation	segment,	is	comprised	of	a	756	MW	combined cycle	gas	plant	and	a	water	desalination	facility.	The	Company	recognized	a	gain	on	disposal	of	$6	million,	net	of	tax,	during	the	year	ended	December	31,	2010.

On	August	19,	2010,	the	Company	completed	the	sale	of	its	35%	ownership	interest	in	Barka,	a	456	MW	combined	cycle	gas	facility	and	water	desalination	plant and	its	wholly	owned	interest	in	two	Barka	related	service	companies.	Barka	is	located	in	Oman	and	was	previously	reported	in	the	Asia	Generation	segment.	Total consideration	received	in	the	transaction	was	approximately	$170	million,	of	which	$124	million	was	AES'	portion.	The	Company	recognized	a	gain	on	disposal	of	$63 million	during	the	year	ended	December	31,	2010,	net	of	noncontrolling	interest	and	$38	million	of	tax	expense	associated	with	the	sale.

On	June	11,	2010,	the	Company	completed	the	sale	of	its	55%	ownership	in	Lal	Pir	and	Pak	Gen,	two	oil-fired	facilities	in	Pakistan	with	respective	generation capacities	of	362	MW	and	365	MW.	These	businesses	were	previously	reported	in	the	Asia	Generation	segment.	Total	consideration	received	in	the	transaction	was approximately	$117	million,	of	which	$65	million	was	AES'	portion.	The	Company	recognized	a	loss	on	disposal	of	$150	million	during	the	year	ended	December	31, 2009	and	impairment	losses	totaling	$22	million	($14	million,	net	of	tax	and	noncontrolling	interests)	during	the	year	ended	December	31,	2010	to	reflect	the	change	in the	carrying	value	of	net	assets	of	Lal	Pir	and	Pak	Gen	subsequent	to	meeting	the	held	for	sale	criteria	as	of	December	31,	2009.

In	December	2008,	the	Company	completed	the	sale	of	its	70%	ownership	interest	in	Jiaozuo	AES	Wanfang	Power	Co.,	Ltd.	("Jiaozuo"),	which	was	reported	in the	Asia	Generation	segment,	for	approximately	$73	million

net	of	any	withholding	taxes.	The	Company	recognized	a	gain	on	the	sale	of	approximately	$7	million.	Goodwill	of	$4	million	was	written	off	in	connection	with	the gain	on	sale.

Information	for	business	components	included	in	discontinued	operations	is	as	follows:

|  | 2010 | 2009 | 2008 |
| :--- | :--- | :--- | :--- |
|  |  | (in\tmillions) |  |
| Revenue | $491 | $736 | $972 |
| Income\tfrom\toperations\tof\tdiscontinued\tbusinesses,\tbefore\ttaxes | $77 | $99 | $104 |
| Income\ttax\texpense | (2) | (3) | (7) |
| Income\tfrom\toperations\tof\tdiscontinued\tbusinesses | $75 | $96 | $97 |
| Gain\t(loss)\ton\tdisposal\tof\tdiscontinued\tbusinesses,\tafter\ttaxes | $64 | $(150) | $6 |

As	further	discussed	in	Note	22—Acquisitions	and	Dispositions,	in	February	2008,	the	Company	entered	into	an	agreement	to	sell	two	of	its	wholly	owned subsidiaries	in	Kazakhstan,	AES	Ekibastuz	LLP	("Ekibastuz")	and	Maikuben	West	LLP	("Maikuben").	These	businesses	are	included	in	the	Europe	Generation segment.	The	sale	was	completed	on	May	30,	2008.	As	a	result	of	AES'	continuing	involvement	in	the	management	and	operations	of	the	businesses	after	the	sale	was completed,	their	results	of	operations	continued	to	be	reflected	as	part	of	income	from	continuing	operations	for	all	periods	presented.	Revenue	recognized	subsequent	to the	sale	represented	the	management	fees	earned	for	the	Company's	continued	management	of	the	operations	of	the	businesses.

# 22.	ACQUISITIONS	AND	DISPOSITIONS

The	Company	completed	its	acquisition	of	the	Ballylumford	Power	Station	in	the	third	quarter	of	2010	and	in	accordance	with	the	accounting	guidance	for business	combinations,	has	recorded	the	preliminary	amounts	for	the	purchase	price	allocation.	The	purchase	price	allocation	is	preliminary	and	adjustments	will continue	to	be	made	during	the	measurement	period.	Subsequent	adjustments,	if	any,	will	be	retrospectively	adjusted	in	future	filings	with	the	SEC.

In	April	2008,	the	Company	completed	the	purchase	of	a	92%	interest	in	a	660	gross	MW	coal-fired	thermal	power	generation	facility	in	Masinloc,	Philippines ("Masinloc")	from	the	Power	Sector	Assets	&	Liabilities	Management	Corporation,	a	state	enterprise,	for	$930	million	in	cash.	Project	financing	of	$665	million	was obtained	from	International	Finance	Corporation	("IFC"),	the	Asian	Development	Bank	and	a	consortium	of	commercial	banks.	IFC	is	also	an	8%	minority	shareholder in	Masinloc.	AES	immediately	embarked	upon	a	comprehensive	rehabilitation	program	to	improve	the	output,	reliability	and	general	condition	of	the	plant.	Including transaction	costs	and	completion	of	the	planned	upgrade	program	to	improve	environmental	and	operational	performance,	the	total	project	cost	was	approximately $1.1	billion.	Beginning	on	the	acquisition	date	in	April	2008,	the	results	of	operations	of	Masinloc	are	reflected	in	the	Consolidated	Financial	Statements.	The	Company finalized	the	purchase	price	allocation	of	this	acquisition	in	the	fourth	quarter	of	2008.

# Dispositions

On	May	30,	2008,	the	Company	completed	the	sale	of	two	of	its	wholly	owned	subsidiaries	in	Kazakhstan,	Ekibastuz,	a	coal-fired	generation	plant,	and Maikuben,	a	coal	mine.	Total	consideration	received	in	the	transaction	was	approximately	$1.1	billion	plus	additional	potential	earn-out	provisions,	a	three-year management	and	operation	agreement	and	a	capital	expenditures	program	bonus.	Due	to	the	fact	that	AES	was	to	have	significant	continuing	involvement	in	the management	and	operations	of	the	businesses	through	its	three-year	management	and	operation	agreement,	the	results	of	operations	from	Ekibastuz	and	Maikuben	were included	in	income	from	continuing	operations	through	the	date	of	the	disposition.	Income	earned	as	a	result	of	the	three-year	management	and	operation	agreement	has been	recognized	as	management	fee	income	for	all	periods	subsequent	to	the	disposition.

On	March	23,	2009,	the	Company	and	Kazakhmys	PLC	("Kazakhmys"),	which	purchased	the	subsidiaries,	mutually	agreed	to	terminate	the	original	sale agreement	and	the	three-year	management	and	operation	agreement.	In	connection	with	the	termination	of	these	agreements,	the	Company	and	Kazakhmys	entered	into a	new	agreement	(the	"2009	Agreement").	Under	the	2009	Agreement,	Kazakhmys	agreed	to	pay	the	Company	an	$80	million	performance	incentive	bonus	in	April 2009	for	management	services	provided	in	2008.	This	was	recognized	as	"Other	Income"	during	the	first	quarter	of	2009.	A	$13	million	gain	was	recognized	related	to	a reversal	of	a	tax	contingency	for	a	contractual	obligation,	under	which	the	Company	provided	indemnification	to	Kazakhmys,	which	expired	in	January	2009.	This	was recorded	as	an	adjustment	to	the	gain	on	the	sale	of	Ekibastuz	and	Maikuben	during	the	first	quarter	of	2009.

The	2009	agreement	also	provided	for	an	additional	$102	million	payment,	primarily	related	to	the	termination	of	the	management	agreement,	payable	to	AES	in January	2010.	In	May	2009,	Kazakhmys	provided	an	irrevocable	standby	letter	of	credit	from	a	creditworthy	institution	to	AES	of	$102	million	to	secure	the	final payment.	The	payment	of	the	final	component	of	the	management	termination	agreement	was	not	contingent	upon	any	future	events.	As	a	result,	the	Company recognized	an	additional	gain	on	the	sale	of	Ekibastuz	and	Maikuben	of	approximately	$98.5	million	in	the	second	quarter	of	2009.	AES	received	the	final	payment	of $102	million	from	Kazakhmys	in	January	2010.

The	parties	agreed	to	terminate	both	the	Stock	Purchase	Agreement	and	the	Management	Agreement,	and	have	further	agreed	to	a	mutual	release	of	prior	claims. As	part	of	the	management	termination	agreement,	AES	agreed	to	transition	the	management	of	the	businesses	to	Kazakhmys	over	a	period	of	100	days	from	March	13, 2009.	The	transition	period	ended	June	21,	2009	and	at	that	time	the	management	of	Ekibastuz	and	Maikuben	became	the	responsibility	of	Kazakhmys.	The	Company's involvement	with	the	businesses	remained	in	place	for	more	than	one	year	from	the	date	of	the	sale;	therefore,	the	Company	has	continued	to	include	the	businesses	as part	of	continuing	operations	in	the	Consolidated	Financial	Statements	for	all	periods	presented,	despite	the	termination	of	the	management	agreement.

Excluding	income	earned	under	the	three-year	management	and	operation	agreement	(terminated	in	March	2009),	Ekibastuz	and	Maikuben	generated	no	revenue or	net	income	in	2010	and	2009	and	generated	revenue	and	net	income	of	$114	million	and	$61	million,	respectively,	for	the	year	ended	December	31,	2008.

# 23.	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.	Potential	common	stock,	for	purposes	of	determining	diluted	earnings	per	share,	includes	the	effects	of	dilutive	restricted	stock	units,	stock	options	and convertible

securities.	The	effect	of	such	potential	common	stock	is	computed	using	the	treasury	stock	method	or	the	if-converted	method,	as	applicable.

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):

|  | December	31,	2010 | December	31,	2010 | December	31,	2010 | December	31,	2009 | December	31,	2009 | December	31,	2009 | December	31,	2008 | December	31,	2008 | December	31,	2008 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Loss | Shares | $\tper\nShare | Income | Shares | $\tper\nShare | Income | Shares | $\tper\nShare |
| BASIC\tEARNINGS\tPER\tSHARE |  |  |  |  |  |  |  |  |  |
| Income\t(loss)\tfrom\tcontinuing\toperations\tattributable\tto\tThe\tAES |  |  |  |  |  |  |  |  |  |
| Corporation\tcommon\tstockholders | $ (86) | 769 | $(0.11) | $710 | 667 | $1.06 | $1,170 | 669 | $1.75 |
| EFFECT\tOF\tDILUTIVE\tSECURITIES |  |  |  |  |  |  |  |  |  |
| Convertible\tsecurities | \t — | \t — | — | — | \t — | \t — | 22 | 15 | (0.02) |
| Stock\toptions | \t — | \t — | — | — | 1 | \t — | — | 4 | — |
| Restricted\tstock\tunits | \t — | \t — | — | — | 2 | \t — | — | 1 | — |
| DILUTED\tEARNINGS\tPER\tSHARE | $ (86) | 769 | $(0.11) | $710 | 670 | $1.06 | $1,192 | 689 | $1.73 |

The	calculation	of	diluted	earnings	per	share	at	December	31,	2010	excluded	all	convertible	securities,	stock	options	and	restricted	stock	units	because	they	are antidilutive.

The	calculation	of	diluted	earnings	per	share	excluded	18,035,813	and	11,150,853	options	outstanding	at	December	31,	2009	and	2008,	respectively,	that	could potentially	dilute	basic	earnings	per	share	in	the	future.	Those	options	were	not	included	in	the	computation	of	diluted	earnings	per	share	because	the	exercise	price	of those	options	exceeded	the	average	market	price	during	the	related	period.	In	2009,	all	convertible	debentures	were	omitted	from	the	earnings	per	share	calculation because	they	were	antidilutive.	In	2008,	all	convertible	debentures	were	included	in	the	earnings	per	share	calculation.	In	arriving	at	income	attributable	to	AES Corporation	common	stockholders	in	computing	basic	earnings	per	share,	dividends	on	preferred	stock	of	our	subsidiary	were	deducted.

In	addition,	on	March	15,	2010,	the	Company	issued	125,468,788	shares	of	common	stock	to	an	investor	as	described	in	Note	14—Equity.

# 24.	RISKS	AND	UNCERTAINTIES

AES	is	a	global	power	producer	in	28	countries	on	five	continents.	See	additional	discussion	of	the	Company's	principal	markets	in	Note	15—Segment	and Geographic	Information.	Our	principal	lines	of	business	are	Generation	and	Utilities.	The	Generation	line	of	business	uses	a	wide	range	of	technologies,	including	coal, gas,	hydroelectric,	and	biomass	as	fuel	to	generate	electricity.	Our	Utilities	business	is	comprised	of	businesses	that	transmit,	distribute,	and	in	certain	circumstances, generate	power.	In	addition,	the	Company	continues	to	expand	its	reach	into	the	renewables	area.	These	efforts	include	projects	primarily	in	wind	and	solar.

POLITICAL	AND	ECONOMIC	RISKS—The	Company's	market	capitalization	was	negatively	impacted	largely	in	the	second	half	of	2008	and	in	2009. During	this	period,	credit	markets	and	global	markets	deteriorated	and	experienced	increased	market	volatility,	which	can	pose	risks	to	the	overall	liquidity	and/or	asset values	of

our	businesses	with	heightened	unpredictability	in	currencies,	counterparty	credit	risk	and	the	widening	of	credit	spreads	in	certain	markets.	If	market	conditions	are protracted	or	continue	to	deteriorate,	the	Company	may	be	at	risk	of	decreased	earnings	and	cash	flows	due	to,	among	other	factors,	adverse	fluctuations	in	the commodities	and	foreign	currency	spot	markets	or	deterioration	in	global	macroeconomic	conditions.	With	the	tightening	of	the	credit	markets,	there	is	a	risk	that	future investments	may	not	be	able	to	be	financed	through	accessing	capital	and	debt	markets	and	may	be	subject	to	restrictions	in	the	near	future.

Currently,	the	Company	has	a	below-investment	grade	rating	from	Standard	&	Poor's	of	BB-.	This	may	limit	the	ability	of	the	Company	to	finance	new	and existing	development	projects	to	cash	currently	available	on	hand	and	through	reinvestment	of	earnings.	As	of	December	31,	2010,	the	Company	had	$2.6	billion	of unrestricted	cash	and	cash	equivalents.

During	2010,	approximately	84%	of	our	revenue,	and	all	of	our	revenue	from	discontinued	businesses,	was	generated	outside	the	United	States	and	a	significant portion	of	our	international	operations	is	conducted	in	developing	countries.	We	continue	to	invest	in	projects	in	developing	countries	because	the	growth	rates	and	the opportunity	to	implement	operating	improvements	and	achieve	higher	operating	margins	may	be	greater	than	those	typically	achievable	in	more	developed	countries. International	operations,	particularly	the	operation,	financing	and	development	of	projects	in	developing	countries,	entail	significant	risks	and	uncertainties,	including, without	limitation:

•ability	to	economically	hedge	energy	prices;

•volatility	in	commodity	prices;

•difficulties	in	enforcing	our	contractual	rights	or	enforcing	judgments	or	obtaining	a	just	result	in	local	jurisdictions;	and

•potentially	adverse	tax	consequences	of	operating	in	multiple	jurisdictions.

Any	of	these	factors,	individually	or	in	combination	with	others,	could	materially	and	adversely	affect	our	business,	results	of	operations	and	financial	condition. In	addition,	our	Latin	American	operations	experience	volatility	in	revenue	and	earnings	which	have	caused	and	are	expected	to	cause	significant	volatility	in	our	results of	operations	and	cash	flows.	The	volatility	is	caused	by	regulatory	and	economic	difficulties,	political	instability	and	currency	fluctuations	being	experienced	in	many of	these	countries.	This	volatility	reduces	the	predictability	and	enhances	the	uncertainty	associated	with	cash	flows	from	these	businesses.

Our	inability	to	predict,	influence	or	respond	appropriately	to	changes	in	law	or	regulatory	schemes,	including	any	inability	to	obtain	expected	or	contracted increases	in	electricity	tariff	rates	or	tariff	adjustments	for	increased	expenses,	could	adversely	impact	our	results	of	operations	or	our	ability	to	meet	publicly	announced projections	or	analysts'	expectations.	Furthermore,	changes	in	laws	or	regulations	or	changes	in	the	application	or	interpretation	of	regulatory	provisions	in	jurisdictions where	we	operate,	particularly	our	Utilities	businesses	where	electricity	tariffs	are	subject	to	regulatory	review	or	approval,	could	adversely	affect	our	business, including,	but	not	limited	to:

•changes	in	the	determination,	definition	or	classification	of	costs	to	be	included	as	reimbursable	or	pass-through	costs;

•changes	in	environmental	regulations,	including	regulations	relating	to	GHG	emissions	in	any	of	our	businesses.

RISKS	RELATED	TO	FOREIGN	CURRENCIES—AES	operates	businesses	in	many	foreign	countries	and	such	operations	may	be	impacted	by	significant fluctuations	in	foreign	currency	exchange	rates.	The	Company's	financial	position	and	results	of	operations	have	been	significantly	affected	by	fluctuations	in	the	value of	the	Brazilian	real,	the	Argentine	peso,	the	Dominican	Republic	peso,	the	Euro,	the	Chilean	peso,	the	Colombian	peso	and	the	Philippine	peso	relative	to	the U.S.	Dollar.

RISKS	RELATED	TO	POWER	SALES	CONTRACTS—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	the	power	sales contracts	related	to	the	Company's	power	plants	range	from	less	than	one	to	38	years.	No	single	customer	accounted	for	10%	or	more	of	total	revenue	in	2010,	2009,	or 2008.

The	cash	flows	and	results	of	operations	of	such	plants	are	dependent	on	the	credit	quality	of	the	purchasers	and	the	continued	ability	of	their	customers	and suppliers	to	meet	their	obligations	under	the	relevant	power	sales	contract.	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.	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	cash	flow,	results	of	operations	and	financial	condition.

# 25.	RELATED	PARTY	TRANSACTIONS

Our	generation	businesses	in	Panama	are	partially	owned	by	the	Government	of	Panama	(the	"Panamanian	Government").	The	Panamanian	Government,	in	turn, partially	owns	the	distribution	companies	within	Panama.	For	the	years	ended	December	31,	2010,	2009	and	2008,	our	Panamanian	businesses	recognized	electricity sales	to	the	Panamanian	Government	totaling	$146	million,	$143	million	and	$203	million,	respectively.	For	the	same	period,	our	Panamanian	businesses	purchased electricity,	which	excludes	transmission	charges	from	the	Panamanian	Government,	totaling	$21	million,	$25	million	and	$27	million,	respectively.	As	of	December	31, 2010	and	2009,	our	Panamanian	businesses	owed	the	Panamanian	Government	$4	million	and	$7	million,	respectively,	payable	on	normal	trade	terms.	For	the	same period,	the	Panamanian	Government	owed	our	Panamanian	businesses	$12	million	and	$25	million,	respectively,	payable	on	normal	trade	terms.

Our	generation	businesses	in	the	Dominican	Republic	are	partially	owned	by	the	Government	of	the	Dominican	Republic	(the	"Dominican	Government").	The Dominican	Government,	in	turn,	owns	the	distribution	companies	within	the	Dominican	Republic.	For	the	years	ended	December	31,	2010,	2009	and	2008,	our Dominican	Republic	businesses	recognized	electricity	sales	to	the	Dominican	Government	totaling	$179	million,	$204	million	and	$244	million,	respectively.	For	the same	period,	the	Dominican	Government	owed	our	Dominican	Republic	businesses	$88	million	and	$121	million,	respectively,	payable	on	normal	trade	terms.

In	December	2010,	ESSA	,	one	of	our	subsidiaries	in	Latin	America,	signed	termination	agreements	related	to	its	long	term	gas	transportation	contracts	that	were under	dispute	in	arbitration	tribunals.	As	a	result	of	these	settlements,	ESSA	paid	$52	million	to	two	of	the	gas	transportation	companies	which	are	related	parties	and recorded	a	loss	of	$43	million.	In	addition,	an	aggregate	amount	of	$16	million	was	payable	to	these	related	parties	at	December	31,	2010.	See	Note	12—Contingencies, Litigations	for	details.

# 26.	SELECTED	QUARTERLY	FINANCIAL	DATA	(UNAUDITED)

# Quarterly	Financial	Data

The	following	tables	summarize	the	unaudited	quarterly	statements	of	operations	for	the	Company	for	2010	and	2009.	Amounts	reflect	all	adjustments	necessary in	the	opinion	of	management	for	a	fair	statement	of	the	results	for	interim	periods.	Amounts	have	been	restated	to	reflect	discontinued	operations	in	all	periods presented.

|  | Mar	31 | June	30 | Sept	30 | Dec	31 |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (in\tmillions,\texcept\tper\tshare\tdata) | (in\tmillions,\texcept\tper\tshare\tdata) |  |
| Revenue | $4,071 | $4,021 | $4,151 | $4,404 |
| Gross\tmargin | 986 | 982 | 985 | \t 1,011 |
| Income\t(loss)\tfrom\tcontinuing\toperations,\tnet\tof\ttax^(1) | 392 | 411 | 296 | (179) |
| Discontinued\toperations,\tnet\tof\ttax | 10 | 18 | 101 | 10 |
| Net\tincome | 402 | 429 | 397 | (169) |
| Net\tincome\t(loss)\tattributable\tto\tThe\tAES\tCorporation | $187 | $144 | $114 | $(436) |
| Basic\tincome\tper\tshare: |  |  |  |  |
| Income\t(loss)\tfrom\tcontinuing\toperations\tattributable\tto |  |  |  |  |
| The\tAES\tCorporation,\tnet\tof\ttax | $0.26 | $0.17 | $0.05 | $(0.56) |
| Discontinued\toperations\tattributable\tto |  |  |  |  |
| The\tAES\tCorporation,\tnet\tof\ttax | 0.01 | 0.01 | 0.09 | 0.01 |
| Basic\tincome\t(loss)\tper\tshare\tattributable\tto |  |  |  |  |
| The\tAES\tCorporation | $0.27 | $0.18 | $0.14 | $(0.55) |
| Diluted\tincome\tper\tshare: |  |  |  |  |
| Income\t(loss)\tfrom\tcontinuing\toperations\tattributable\tto |  |  |  |  |
| The\tAES\tCorporation,\tnet\tof\ttax | $0.26 | $0.17 | $0.05 | $(0.56) |
| Discontinued\toperations\tattributable\tto |  |  |  |  |
| The\tAES\tCorporation,\tnet\tof\ttax | 0.01 | 0.01 | 0.09 | 0.01 |
| Diluted\tincome\t(loss)\tper\tshare\tattributable\tto\nThe\tAES\tCorporation | $0.27 | $0.18 | $0.14 | $(0.55) |

|  | Mar	31 | June	30 | Sept	30 | Dec	31 |
| :--- | :--- | :--- | :--- | :--- |
|  |  | (in\tmillions,\texcept\tper\tshare\tdata) | (in\tmillions,\texcept\tper\tshare\tdata) |  |
| Revenue | $3,235 | $3,291 | $3,652 | $3,776 |
| Gross\tmargin | 849 | 803 | 967 | 814 |
| Income\tfrom\tcontinuing\toperations,\tnet\tof\ttax^(2) | 483 | 503 | 414 | 409 |
| Discontinued\toperations,\tnet\tof\ttax | 19 | 27 | 26 | (126) |
| Net\tincome | 502 | 530 | 440 | 283 |
| Net\tincome\t(loss)\tattributable\tto\tThe\tAES\tCorporation | $218 | $303 | $185 | $(48) |
| Basic\tincome\t(loss)\tper\tshare: |  |  |  |  |
| Income\tfrom\tcontinuing\toperations\tattributable\tto |  |  |  |  |
| The\tAES\tCorporation,\tnet\tof\ttax | $0.31 | $0.43 | $0.26 | $0.07 |
| Discontinued\toperations\tattributable\tto |  |  |  |  |
| The\tAES\tCorporation,\tnet\tof\ttax | 0.02 | 0.02 | 0.02 | (0.14) |
| Basic\tincome\t(loss)\tper\tshare\tattributable\tto |  |  |  |  |
| The\tAES\tCorporation | $0.33 | $0.45 | $0.28 | $(0.07) |
| Diluted\tincome\t(loss)\tper\tshare: |  |  |  |  |
| Income\tfrom\tcontinuing\toperations\tattributable\tto |  |  |  |  |
| The\tAES\tCorporation,\tnet\tof\ttax | $0.31 | $0.43 | $0.26 | $0.07 |
| Discontinued\toperations\tattributable\tto |  |  |  |  |
| The\tAES\tCorporation,\tnet\tof\ttax | 0.02 | 0.02 | 0.02 | (0.14) |
| Diluted\tincome\t(loss)\tper\tshare\tattributable\tto\nThe\tAES\tCorporation | $0.33 | $0.45 | $0.28 | $(0.07) |

Includes	pretax	impairment	expense	of	$314	million	and	$927	million,	for	the	third	and	fourth	quarters	of	2010,	respectively.	See	Note	19—Impairment	Expense and	Note	8—Goodwill	and	Other	Intangible	Assets	for	additional	discussion	on	these	impairment	expenses.

Includes	pretax	impairment	expense	$140	million	for	the	fourth	quarter	of	2009.	See	Note	19—Impairment	Expense	and	Note	8—Goodwill	and	Other	Intangible Assets	for	additional	discussion	on	the	impairment	expense.

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

# ITEM	9A. CONTROLS	AND	PROCEDURES

# Conclusion	Regarding	the	Effectiveness	of	Disclosure	Controls	and	Procedures

The	Company	maintains	disclosure	controls	and	procedures	that	are	designed	to	ensure	that	information	required	to	be	disclosed	in	the	reports	that	the	Company files	or	submits	under	the	Securities	Exchange	Act	of	1934,	as	amended	(the	"Exchange	Act"),	is	recorded,	processed,	summarized	and	reported	within	the	time	periods specified	in	the	SEC's	rules	and	forms,	and	that	such	information	is	accumulated	and	communicated	to	the	chief	executive	officer	("CEO")	and	chief	financial	officer ("CFO"),	as	appropriate,	to	allow	timely	decisions	regarding	required	disclosures.

The	Company	carried	out	the	evaluation	required	by	Rules	13a-15(b)	and	15d-15(b),	under	the	supervision	and	with	the	participation	of	our	management, including	the	CEO	and	CFO,	of	the	effectiveness	of	our	"disclosure	controls	and	procedures"	(as	defined	in	the	Exchange	Act	Rules	13a-15(e)	and	15d-15(e)).	Based upon	this	evaluation,	the	CEO	and	CFO	concluded	that	as	of	December	31,	2010,	our	disclosure	controls	and	procedures	were	effective.

# Management's	Report	on	Internal	Control	Over	Financial	Reporting

Management	of	the	Company	is	responsible	for	establishing	and	maintaining	adequate	internal	control	over	financial	reporting,	as	defined	in	Rule	13a-15(f)	under the	Exchange	Act.	The	Company's	internal	control	over	financial	reporting	is	a	process	designed	to	provide	reasonable	assurance	regarding	the	reliability	of	financial reporting	and	the	preparation	of	financial	statements	for	external	purposes	in	accordance	with	GAAP	and	includes	those	policies	and	procedures	that:

•pertain	to	the	maintenance	of	records	that	in	reasonable	detail,	accurately	and	fairly	reflect	the	transactions	and	dispositions	of	the	assets	of	the	Company;

•provide	reasonable	assurance	that	transactions	are	recorded	as	necessary	to	permit	preparation	of	financial	statements	in	accordance	with	GAAP,	and	that receipts	and	expenditures	of	the	Company	are	being	made	only	in	accordance	with	authorizations	of	management	and	directors	of	the	Company;	and •provide	reasonable	assurance	that	unauthorized	acquisition,	use	or	disposition	of	the	Company's	assets	that	could	have	a	material	effect	on	the	financial statements	are	prevented	or	detected	timely.

Management,	including	our	CEO	and	CFO,	does	not	expect	that	our	internal	controls	will	prevent	or	detect	all	errors	and	all	fraud.	A	control	system,	no	matter how	well	designed	and	operated,	can	provide	only	reasonable,	not	absolute,	assurance	that	the	objectives	of	the	control	system	are	met.	Further,	the	design	of	a	control system	must	reflect	the	fact	that	there	are	resource	constraints,	and	the	benefits	of	controls	must	be	considered	relative	to	their	costs.	In	addition,	any	evaluation	of	the effectiveness	of	controls	is	subject	to	risks	that	those	internal	controls	may	become	inadequate	in	future	periods	because	of	changes	in	business	conditions,	or	that	the degree	of	compliance	with	the	policies	or	procedures	deteriorates.

Management	assessed	the	effectiveness	of	our	internal	control	over	financial	reporting	as	of	December	31,	2010.	In	making	this	assessment,	management	used	the criteria	established	in	Internal	Control—Integrated	Framework	issued	by	the	Committee	of	Sponsoring	Organizations	("COSO").	Based	on	this	assessment	management, believes	that	the	Company	maintained	effective	internal	control	over	financial	reporting	as	of	December	31,	2010.

The	effectiveness	of	the	Company's	internal	control	over	financial	reporting	as	of	December	31,	2010,	has	been	audited	by	Ernst	&	Young	LLP,	an	independent registered	public	accounting	firm,	as	stated	in	their	report,	which	appears	herein.

# Changes	in	Internal	Control	Over	Financial	Reporting:

There	were	no	changes	that	occurred	during	the	quarter	ended	December	31,	2010	that	have	materially	affected,	or	are	reasonably	likely	to	materially	affect,	our internal	control	over	financial	reporting.

We	have	audited	The	AES	Corporation's	internal	control	over	financial	reporting	as	of	December	31,	2010	based	on	criteria	established	in	Internal	Control— Integrated	Framework	issued	by	the	Committee	of	Sponsoring	Organizations	of	the	Treadway	Commission	(the	COSO	criteria).	The	AES	Corporation's	management	is responsible	for	maintaining	effective	internal	control	over	financial	reporting,	and	for	its	assessment	of	the	effectiveness	of	internal	control	over	financial	reporting included	in	the	accompanying	Management's	Report	on	Internal	Control	over	Financial	Reporting.	Our	responsibility	is	to	express	an	opinion	on	the	company's	internal control	over	financial	reporting	based	on	our	audit.

We	conducted	our	audit	in	accordance	with	the	standards	of	the	Public	Company	Accounting	Oversight	Board	(United	States).	Those	standards	require	that	we plan	and	perform	the	audit	to	obtain	reasonable	assurance	about	whether	effective	internal	control	over	financial	reporting	was	maintained	in	all	material	respects.	Our audit	included	obtaining	an	understanding	of	internal	control	over	financial	reporting,	assessing	the	risk	that	a	material	weakness	exists,	testing	and	evaluating	the	design and	operating	effectiveness	of	internal	control	based	on	the	assessed	risk,	and	performing	such	other	procedures	as	we	considered	necessary	in	the	circumstances.	We believe	that	our	audit	provides	a	reasonable	basis	for	our	opinion.

A	company's	internal	control	over	financial	reporting	is	a	process	designed	to	provide	reasonable	assurance	regarding	the	reliability	of	financial	reporting	and	the preparation	of	financial	statements	for	external	purposes	in	accordance	with	generally	accepted	accounting	principles.	A	company's	internal	control	over	financial reporting	includes	those	policies	and	procedures	that	(1)	pertain	to	the	maintenance	of	records	that,	in	reasonable	detail,	accurately	and	fairly	reflect	the	transactions	and dispositions	of	the	assets	of	the	company;	(2)	provide	reasonable	assurance	that	transactions	are	recorded	as	necessary	to	permit	preparation	of	financial	statements	in accordance	with	generally	accepted	accounting	principles,	and	that	receipts	and	expenditures	of	the	company	are	being	made	only	in	accordance	with	authorizations	of management	and	directors	of	the	company;	and	(3)	provide	reasonable	assurance	regarding	prevention	or	timely	detection	of	unauthorized	acquisition,	use	or	disposition of	the	company's	assets	that	could	have	a	material	effect	on	the	financial	statements.

Because	of	its	inherent	limitations,	internal	control	over	financial	reporting	may	not	prevent	or	detect	misstatements.	Also,	projections	of	any	evaluation	of effectiveness	to	future	periods	are	subject	to	the	risk	that	controls	may	become	inadequate	because	of	changes	in	conditions,	or	that	the	degree	of	compliance	with	the policies	or	procedures	may	deteriorate.

In	our	opinion,	The	AES	Corporation	maintained,	in	all	material	respects,	effective	internal	control	over	financial	reporting	as	of	December	31,	2010,	based	on	the COSO	criteria.

We	also	have	audited,	in	accordance	with	the	standards	of	the	Public	Company	Accounting	Oversight	Board	(United	States),	the	consolidated	balance	sheets	of The	AES	Corporation	and	subsidiaries	as	of	December	31,	2010	and	2009,	and	the	related	consolidated	statements	of	operations,	stockholders'	equity	and	cash	flows	for each	of	the	three	years	in	the	period	ended	December	31,	2010	and	our	report	dated	February	25,	2011	expressed	an	unqualified	opinion	thereon.

/s/	Ernst	&	Young	LLP

# ITEM	9B. OTHER	INFORMATION.

# PART	III

# ITEM	10. DIRECTORS,	EXECUTIVE	OFFICERS	AND	CORPORATE	GOVERNANCE

The	following	information	is	incorporated	by	reference	from	the	Registrant's	Proxy	Statement	for	the	Registrant's	2011	Annual	Meeting	of	Stock	Holders	which the	Registrant	expects	will	be	filed	on	or	around	March	1,	2011	(the	"2011	Proxy	Statement"):

•Information	regarding	the	directors	required	by	this	item	found	under	the	heading	Board	of	Directors

•Information	regarding	AES'	Code	of	Ethics	found	under	the	heading	AES	Code	of	Business	Conduct	and	Corporate	Governance	Guidelines

•Information	regarding	compliance	with	Section	16	of	the	Exchange	Act	required	by	this	item	found	under	the	heading	Governance	Matters—Section	16(a) Beneficial	Ownership	Reporting	Compliance

•Information	regarding	AES'	Financial	Audit	Committee	found	under	the	heading	The	Committees	of	the	Board—Financial	Audit	Committee	(the	"Audit Committee")

Certain	information	regarding	executive	officers	required	by	this	Item	is	set	forth	as	a	supplementary	item	in	Part	I	hereof	(pursuant	to	Instruction	3	to	Item	401(b) of	Regulation	S-K).	The	other	information	required	by	this	Item,	to	the	extent	not	included	above,	will	be	contained	in	our	2011	Proxy	Statement	and	is	herein incorporated	by	reference.

# ITEM	11. EXECUTIVE	COMPENSATION

The	following	information	is	contained	in	the	2011	Proxy	Statement	and	is	incorporated	by	reference:	the	information	regarding	executive	compensation contained	under	the	heading	Compensation	Discussion	and	Analysis	and	the	Compensation	Committee	Report	on	Executive	Compensation	under	the	heading	Report	of the	Compensation	Committee.

# ITEM	12. SECURITY	OWNERSHIP	OF	CERTAIN	BENEFICIAL	OWNERS	AND	MANAGEMENT	AND	RELATED	STOCKHOLDER	MATTERS

# (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	2011	Annual	Meeting	of	Shareholders	of	the	Registrant,	which	information	is	incorporated	herein	by	reference.

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

# (c) Changes	in	Control.

# (d) Securities	Authorized	for	Issuance	under	Equity	Compensation	Plans.

The	following	table	provides	information	about	shares	of	AES	common	stock	that	may	be	issued	under	AES'	equity	compensation	plans,	as	of	December	31,

# Securities	Authorized	for	Issuance	under	Equity	Compensation	Plans	(As	of	December	31,	2010)

| Plan	category | Number	of	securities	to<br>be	issued	upon	exercise<br>of	outstanding	options,<br>warrants	and	rights | Weighted	average<br>exercise	price	of<br>outstanding	options,<br>warrants	and	rights | future	issuance	under<br>equity	compensation	plans<br>(excluding	securities<br>reflected	in	column	(a)) |
| :--- | :--- | :--- | :--- |
| Equity\tcompensation\tplans |  |  |  |
| approved\tby\tsecurity\tholders^(1) | 21,128,007^(2) | $17.21 | 19,723,531 |
| Equity\tcompensation\tplans\tnot |  |  |  |
| approved\tby\tsecurity\tholders^(3) | 5,618,255 | $13.15 | — |
| Total | 26,746,262 | $16.10 | 19,723,531 |

The	following	equity	compensation	plans	have	been	approved	by	the	Company's	Stockholders: The	LTC	Plan	was	adopted	in	2003	and	provided	for	17,000,000	shares	authorized	for	issuance	thereunder.	In	2008,	an	amendment	to	the	Plan	to	provide an	additional	12,000,000	shares	was	approved	by	AES'	stockholders,	bringing	the	total	authorized	shares	to	29,000,000.	In	2010,	an	additional	amendment to	the	Plan	to	provide	an	additional	9,000,000	shares	was	approved	by	AES'	stockholders,	bringing	the	total	authorized	shares	to	38,000,000.	The	weighted average	exercise	price	of	Options	outstanding	under	this	plan	included	in	Column	(b)	is	$14.87	(excluding	RSU	awards),	with	19,723,351	shares	available for	future	issuance. (A) (B)

The	AES	Corporation	2001	Stock	Option	Plan	adopted	in	2001	provided	for	15,000,000	shares	authorized	for	issuance.	The	weighted	average	exercise price	of	Options	outstanding	under	this	plan	included	in	Column	(b)	is	$14.95.	In	conjunction	with	the	2010	amendment	to	the	2003	Long	Term Compensation	plan,	ongoing	award	issuance	from	this	plan	was	discontinued	in	2010.	Any	remaining	shares	under	this	plan,	which	are	not	reserved	for issuance	under	outstanding	awards,	are	not	available	for	future	issuance	and	thus	the	amount	of	2,067,856	shares	is	not	included	in	Column	(c)	above. The	AES	Corporation	2001	Plan	for	Outside	Directors	adopted	in	2001	provided	for	2,750,000	shares	authorized	for	issuance.	The	weighted	average exercise	price	of	Options	outstanding	under	this	plan	included	in	Column	(b)	is	$11.70.	In	conjunction	with	the	2010	amendment	to	the	2003	Long	Term Compensation	plan,	ongoing	award	issuance	from	this	plan	was	discontinued	in	2010.	Any	remaining	shares	under	this	plan,	which	are	not	reserved	for issuance	under	outstanding	awards,	are	not	available	for	future	issuance	and	thus	the	amount	of	2,194,404	shares	is	not	included	in	Column	(c)	above. The	AES	Corporation	Second	Amended	and	Restated	Deferred	Compensation	Plan	for	Directors	provided	for	2,000,000	shares	authorized	for	issuance. Column	(b)	excludes	the	Director	stock	units	granted	thereunder.	In	conjunction	with	the	2010	amendment	to	the	2003	Long	Term	Compensation	Plan, ongoing	award	issuance	from	this	plan	was	discontinued	in	2010	as	Director	stock	units	will	be	issued	from	the	2003	Long	Term	Compensation	Plan.	Any remaining	shares	under	this	plan,	which	are	not	reserved	for	issuance	under	outstanding	awards,	are	not	available	for	future	issuance	and	thus	the	amount	of 105,341	shares	is	not	included	in	Column	(c)	above.

The	AES	Corporation	Incentive	Stock	Option	Plan	adopted	in	1991	provided	for	57,500,000	shares	authorized	for	issuance.	The	weighted	average	exercise price	of	Options	outstanding	under	this	plan	included	in	Column	(b)	is	$55.29.	This	plan	terminated	on	June	1,	2001,	such	that	no	additional	grants	may	be granted	under	the	plan	after	that	date.	Any	remaining	shares	under	this	plan,	which	are	not	reserved	for	issuance	under	outstanding	awards,	are	not available	for	future	issuance	in	light	of	this	plan's	termination	and	thus	the	amount	23,502,620	shares	is	not	included	in	Column	(c)	above.

Includes	5,448,036	(2,217,074	of	which	are	vested	and	3,230,962	are	unvested)	shares	underlying	RSU	awards	(assuming	performance	at	a	maximum	level), 778,328	shares	underlying	Director	stock	unit	awards,	and	14,901,643	shares	issuable	upon	the	exercise	of	Stock	Option	grants,	for	an	aggregate	number	of 21,128,007	shares.

The	AES	Corporation	2001	Non-Officer	Stock	Option	Plan	provided	for	12,000,000	shares	authorized	for	issuance.	The	weighted	average	exercise	price	of Options	outstanding	under	this	plan	shown	in	Column	(b)	is	$13.15.	In	conjunction	with	the	2010	amendment	to	the	2003	Long	Term	Compensation	plan, ongoing	award	issuance	from	this	plan	was	discontinued	in	2010.	Any	remaining	shares	under	this	plan,	which	are	not	reserved	for	issuance	under	outstanding awards,	are	not	available	for	future	issuance	and	thus	the	amount	of	1,549,919	shares	is	not	included	in	Column	(c)	above.	This	plan	is	described	in	the	narrative below.

The	AES	Corporation	2001	Non-Officer	Stock	Option	Plan	(the	"2001	Plan")	was	adopted	by	the	Board	on	October	18,	2001,	and	became	effective	October	25, 2001.	The	2001	Plan	did	not	require	approval	of	AES'	stockholders	under	SEC	or	NYSE	rules	and/or	regulations	at	that	time.	All	employees	that	are	not	Officers, Directors	or	beneficial	owners	of	more	than	10%	of	AES'	common	stock	are	eligible	to	participate	in	the	2001	Plan.	The	total	aggregate	number	of	shares	for	which Options	can	be	granted	pursuant	to	the	2001	Plan	is	12	million.	As	of	December	31,	2010,	approximately	3,423	employees	held	Options	under	the	2001	Plan.	The exercise	price	of	each	Option	awarded	under	the	2001	Plan	is	equal	to	the	fair	market	value	of	AES'	common	stock	on	the	grant	date	of	the	Option.	Options	under	the 2001	Plan	generally	vest	as	to	50%	of	their	underlying	shares	on	each	anniversary	of	the	Option	grant	date;	however,	grants	dated	October	25,	2001	vested	in	one	year. Unless	otherwise	provided	by	the	Compensation	Committee	of	the	Board,	upon	the	death	or	disability	of	an	employee,	or	a	change	of	control	(as	defined	therein),	all Options	granted	under	the	2001	Plan	will	become	fully	vested	and	exercisable.	Unless	otherwise	provided	by	the	Compensation	Committee	of	the	Board,	in	the	event that	the	employee's	employment	with	the	Company	terminates	for	any	reason	other	than	death	or	disability,	all	Options	held	by	such	employee	will	automatically	expire on	the	earlier	of	(a)	the	date	the	Option	would	have	expired	had	the	employee	continued	in	such	employment,	and	(b)	180	days	after	the	date	that	such	employee's employment	ceases.	The	2001	Plan	will	expire	on	October	25,	2011.	The	Board	may	amend,	modify	or	terminate	the	2001	Plan	at	any	time.

# ITEM	13. CERTAIN	RELATIONSHIPS	AND	RELATED	TRANSACTIONS,	AND	DIRECTOR	INDEPENDENCE

The	information	regarding	related	party	transactions	required	by	this	item	is	included	in	the	2011	Proxy	Statement	found	under	the	headings	Transactions	with Related	Persons,	Proposal	I:	Election	of	Directors	and	The	Committees	of	the	Board	and	are	incorporated	herein	by	reference.

# ITEM	14. PRINCIPAL	ACCOUNTANT	FEES	AND	SERVICES

The	information	concerning	principal	accountant	fees	and	services	included	in	the	2011	Proxy	Statement	contained	under	the	heading	Information	Regarding	The Independent	Registered	Public	Accounting	Firm's	Fees,	Services	and	Independence	and	is	incorporated	herein	by	reference.

# PART	IV

# ITEM	15. EXHIBITS	AND	FINANCIAL	STATEMENT	SCHEDULES

# (a) Financial	Statements.

# (b) Exhibits.

3.1 Sixth	Restated	Certificate	of	Incorporation	of	The	AES	Corporation	is	incorporated	herein	by	reference	to	Exhibit	3.1	of	the	Company's	Form	10-K	for	the year	ended	December	31,	2008.

3.2 By-Laws	of	The	AES	Corporation,	as	amended	and	incorporated	herein	by	reference	to	Exhibit	3.1	of	the	Company's	Form	8-K	filed	on	August	11,	2009.

4 There	are	numerous	instruments	defining	the	rights	of	holders	of	long-term	indebtedness	of	the	Registrant	and	its	consolidated	subsidiaries,	none	of	which exceeds	ten	percent	of	the	total	assets	of	the	Registrant	and	its	subsidiaries	on	a	consolidated	basis.	The	Registrant	hereby	agrees	to	furnish	a	copy	of	any	of such	agreements	to	the	Commission	upon	request.	Since	these	documents	are	not	required	filings	under	Item	601	of	Regulation	S-K,	the	Company	has elected	to	file	certain	of	these	documents	as	Exhibits	4(a)—4(o).

4.(a) Junior	Subordinated	Indenture,	dated	as	of	March	1,	1997,	between	The	AES	Corporation	and	Wells	Fargo	Bank,	National	Association,	as	successor	to Bank	One,	National	Association	(formerly	known	as	The	First	National	Bank	of	Chicago)	is	incorporated	herein	by	reference	to	Exhibit	4.(a)	of	the Company's	Form	10-K	for	the	year	ended	December	31,	2008.

4.(b) Third	Supplemental	Indenture,	dated	as	of	October	14,	1999,	between	The	AES	Corporation	and	Wells	Fargo	Bank,	National	Association,	as	successor	to Bank	One,	National	Association	is	incorporated	herein	by	reference	to	Exhibit	4.(b)	of	the	Company's	Form	10-K	for	the	year	ended	December	31,	2008.

4.(c) Senior	Indenture,	dated	as	of	December	8,	1998,	between	The	AES	Corporation	and	Wells	Fargo	Bank,	National	Association,	as	successor	to	Bank	One, National	Association	(formerly	known	as	The	First	National	Bank	of	Chicago)	is	incorporated	herein	by	reference	to	Exhibit	4.01	of	the	Company's Form	8-K	filed	on	December	11,	1998.

4.(d) Form	of	Second	Supplemental	Indenture,	dated	as	of	June	11,	1999,	between	The	AES	Corporation	and	Wells	Fargo	Bank,	National	Association,	as successor	to	Bank	One,	National	Association	(formerly	known	as	The	First	National	Bank	of	Chicago)	is	incorporated	herein	by	reference	to	Exhibit	4.01 of	the	Company's	Form	8-K	filed	on	June	11,	1999.

4.(e) Third	Supplemental	Indenture,	dated	as	of	September	12,	2000,	between	The	AES	Corporation	and	Wells	Fargo	Bank,	National	Association,	as	successor to	Bank	One,	National	Association	is	incorporated	herein	by	reference	to	Exhibit	4.(e)	of	the	Company's	Form	10-K	for	the	year	ended	December	31, 2008.

4.(f) Form	of	Fifth	Supplemental	Indenture,	dated	as	of	February	9,	2001,	between	The	AES	Corporation	and	Wells	Fargo	Bank,	National	Association,	as successor	to	Bank	One,	National	Association	is	incorporated	herein	by	reference	to	Exhibit	4.1	of	the	Company's	Form	8-K	filed	on	February	8,	2001.

		4.(g) Form	of	Sixth	Supplemental	Indenture,	dated	as	of	February	22,	2001,	between	The	AES	Corporation	and	Wells	Fargo	Bank,	National	Association,	as successor	to	Bank	One,	National	Association	is	incorporated	herein	by	reference	to	Exhibit	4.1	of	the	Company's	Form	8-K	filed	on	February	21,	2001.

		4.(h) Ninth	Supplemental	Indenture,	dated	as	of	April	3,	2003,	between	The	AES	Corporation	and	Wells	Fargo	Bank,	National	Association	(as	successor	by consolidation	to	Wells	Fargo	Bank	Minnesota,	National	Association)	is	incorporated	herein	by	reference	to	Exhibit	4.6	of	the	Company's	Form	S-4	filed on	December	7,	2007.

		4.(i) Form	of	Tenth	Supplemental	Indenture,	dated	as	of	February	13,	2004,	between	The	AES	Corporation	and	Wells	Fargo	Bank,	National	Association	(as successor	by	consolidation	to	Wells	Fargo	Bank	Minnesota,	National	Association)	is	incorporated	herein	by	reference	to	Exhibit	4.1	of	the	Company's Form	8-K	filed	on	February	13,	2004.

		4.(j) Eleventh	Supplemental	Indenture,	dated	as	of	October	15,	2007,	between	The	AES	Corporation	and	Wells	Fargo	Bank,	National	Association	is incorporated	herein	by	reference	to	Exhibit	4.7	of	the	Company's	Form	S-4	filed	on	December	7,	2007.

		4.(k) Twelfth	Supplemental	Indenture,	dated	as	of	October	15,	2007,	between	The	AES	Corporation	and	Wells	Fargo	Bank,	National	Association	is incorporated	herein	by	reference	to	Exhibit	4.8	of	the	Company's	Form	S-4	filed	on	December	7,	2007.

		4.(l) Thirteenth	Supplemental	Indenture,	dated	as	of	May	19,	2008,	between	The	AES	Corporation	and	Wells	Fargo	Bank,	National	Association	is incorporated	herein	by	reference	to	Exhibit	4.(l)	of	the	Company's	Form	10-K	for	the	year	ended	December	31,	2008.

		4.(m) Fourteenth	Supplemental	indenture,	dated	as	of	April	2,	2009,	between	The	AES	Corporation	and	Wells	Fargo	Bank,	National	Association	is incorporated	herein	by	reference	to	Exhibit	99.1	of	the	Company's	Form	8-K	filed	on	April	2,	2009.

		4.(n) Senior	Indenture,	dated	as	of	May	8,	2003,	between	The	AES	Corporation	and	Wells	Fargo	Bank,	National	Association	(as	successor	by	consolidation	to Wells	Fargo	Bank	Minnesota,	National	Association)	is	incorporated	herein	by	reference	to	Exhibit	4.(m)	of	the	Company's	Form	10-K	for	the	year	ended December	31,	2008.

# SIGNATURES

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

(Company)

# /s/				PAUL	HANRAHAN

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	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

# UNCONSOLIDATED	BALANCE	SHEETS

|  | 2010 | 2009 |
| :--- | :--- | :--- |
|  | (in\tmillions) |  |
| ASSETS |  |  |
| Current\tAssets: |  |  |
| Cash\tand\tcash\tequivalents | $594 | $628 |
| Restricted\tcash | 10 | 9 |
| Accounts\tand\tnotes\treceivable\tfrom\tsubsidiaries | 1,031 | 514 |
| Deferred\tincome\ttaxes | 23 | 27 |
| Prepaid\texpenses\tand\tother\tcurrent\tassets | 31 | 34 |
| Total\tcurrent\tassets | 1,689 | 1,212 |
| Investment\tin\tand\tadvances\tto\tsubsidiaries\tand\taffiliates | 9,240 | 8,639 |
| Office\tEquipment: |  |  |
| Cost | 93 | 86 |
| Accumulated\tdepreciation | (59) | (47) |
| Office\tequipment,\tnet | 34 | 39 |
| Other\tAssets: |  |  |
| Deferred\tfinancing\tcosts\t(net\tof\taccumulated\tamortization\tof\t$39\tand\t$76,\trespectively) | 64 | 72 |
| Deferred\tincome\ttaxes | 352 | 516 |
| Other\tassets | 1 | 25 |
| Total\tother\tassets | 417 | 613 |
| Total | $11,380 | $10,503 |
| LIABILITIES\tAND\tSTOCKHOLDERS'\tEQUITY |  |  |
| Current\tLiabilities: |  |  |
| Accounts\tpayable | $2 | $5 |
| Accrued\tand\tother\tliabilities | 187 | 208 |
| Term\tloan | 200 | — |
| Senior\tnotes\tpayable—current\tportion | 263 | 214 |
| Total\tcurrent\tliabilities | 652 | 427 |
| Long-term\tLiabilities: |  |  |
| Term\tloan | — | 200 |
| Senior\tnotes\tpayable | 3,631 | 4,584 |
| Junior\tsubordinated\tnotes\tand\tdebentures\tpayable | 517 | 517 |
| Other\tlong-term\tliabilities | 107 | 100 |
| Total\tlong-term\tliabilities | 4,255 | 5,401 |
| Stockholders'\tequity: |  |  |
| Common\tstock | 8 | 7 |
| Additional\tpaid-in\tcapital | 8,444 | 6,868 |
| Retained\tearnings | 620 | 650 |
| Accumulated\tother\tcomprehensive\tloss | (2,383) | (2,724) |
| Treasury\tstock | (216) | (126) |
| Total\tstockholders'\tequity | 6,473 | 4,675 |
| Total | $11,380 | $10,503 |

See	Notes	to	Schedule	I

# STATEMENTS	OF	UNCONSOLIDATED	OPERATIONS

|  | 2010 | 2009 | 2008 |
| :--- | :--- | :--- | :--- |
|  |  | (in\tmillions) |  |
| Revenues\tfrom\tsubsidiaries\tand\taffiliates | $34 | $39 | $36 |
| Equity\tin\tearnings\tof\tsubsidiaries\tand\taffiliates | 590 | 983 | \t 2,019 |
| Interest\tincome | 279 | 131 | 173 |
| General\tand\tadministrative\texpenses | (261) | (218) | (264) |
| Interest\texpense | (461) | (485) | (516) |
| Income\t(loss)\tbefore\tincome\ttaxes | 181 | 450 | \t 1,448 |
| Income\ttax\tbenefit\t(expense) | (172) | 208 | (214) |
| Net\tincome | $9 | $658 | $1,234 |

# STATEMENTS	OF	UNCONSOLIDATED	CASH	FLOWS

|  | 2010 | 2009 | 2008 |
| :--- | :--- | :--- | :--- |
|  |  | (in\tmillions) |  |
| Net\tcash\tprovided\tby\toperating\tactivities | $488 | $178 | $863 |
| Investing\tActivities: |  |  |  |
| Investment\tin\tand\tadvances\tto\tsubsidiaries | (1,185) | (452) | (1,098) |
| Acquisitions—net\tof\tcash\tacquired | (3) | (5) | (95) |
| Return\tof\tcapital | 300 | 166 | 89 |
| (Increase)\tdecrease\tin\trestricted\tcash | (2) | 4 | 2 |
| Additions\tto\tproperty,\tplant\tand\tequipment | (22) | (8) | (23) |
| Net\tcash\tused\tin\tinvesting\tactivities | (912) | (295) | (1,125) |
| Financing\tActivities: |  |  |  |
| Borrowings\tof\tnotes\tpayable\tand\tother\tcoupon\tbearing\tsecurities | — | 503 | 625 |
| Repayments\tof\tnotes\tpayable\tand\tother\tcoupon\tbearing\tsecurities | (914) | (154) | (1,037) |
| Loans\t(to)\tfrom\tsubsidiaries | (154) | 205 | 90 |
| Proceeds\tfrom\tissuance\tof\tcommon\tstock | 1,569 | 14 | 28 |
| Purchase\tof\ttreasury\tstock | (99) | \t — | (143) |
| Payments\tfor\tdeferred\tfinancing\tcosts | (12) | (23) | (14) |
| Net\tcash\tprovided\tby\t(used\tin)\tfinancing\tactivities | 390 | 545 | (451) |
| Increase\t(decrease)\tin\tcash\tand\tcash\tequivalents | (34) | 428 | (713) |
| Cash\tand\tcash\tequivalents,\tbeginning | 628 | 200 | 913 |
| Cash\tand\tcash\tequivalents,\tending | $594 | $628 | $200 |
| Supplemental\tDisclosures: |  |  |  |
| Cash\tpayments\tfor\tinterest,\tnet\tof\tamounts\tcapitalized | $412 | $410 | $469 |
| Cash\tpayments\tfor\tincome\ttaxes,\tnet\tof\trefunds | $— | $ — | $— |

# 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	financial	information.

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

Income	Taxes—Positions	taken	on	the	Company's	income	tax	return	which	satisfy	a	more-likely-than-not	threshold	will	be	recognized	in	the	financial statements.	The	unconsolidated	income	tax	expense	or	benefit	computed	for	the	Company	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.

# Selected	Unconsolidated	Balance	Sheet	Data:

|  | 2010 |  | 2009 |
| :--- | :--- | :--- | :--- |
|  |  | (in\tmillions) |  |
| Assets |  |  |  |
| Investment\tin\tand\tadvances\tto\tsubsidiaries\tand\taffiliates | $9,240 |  | $8,639 |
| Deferred\tincome\ttaxes | $352 |  | $516 |
| Total\tother\tassets | $417 |  | $613 |
| Total\tassets | $ 11,380 |  | $ 10,503 |
| Liabilities\tand\tStockholders'\tEquity |  |  |  |
| Other\tlong-term\tliabilities | $107 |  | $100 |
| Total\tlong-term\tliabilities | $4,255 |  | $5,401 |
| Additional\tpaid-in\tcapital | $8,444 |  | $6,868 |
| Retained\tearnings | $620 |  | $650 |
| Accumulated\tother\tcomprehensive\tloss | $(2,383) |  | $(2,724) |
| Total\tstockholders'\tequity | $6,473 |  | $4,675 |
| Total\tliabilities\tand\tstockholders'\tequity | $ 11,380 |  | $ 10,503 |

# Selected	Unconsolidated	Operations	Data:

|  | 2010 | 2009 | 2008 |
| :--- | :--- | :--- | :--- |
|  |  | (in\tmillions) |  |
| Equity\tin\tearnings\tof\tsubsidiaries\tand\taffiliates | $590 | $983 | $2,019 |
| Income\tbefore\tincome\ttaxes | $181 | $450 | $1,448 |
| Income\ttax\tbenefit\t(expense) | $(172) | $208 | $(214) |
| Net\tincome\tattributable\tto\tThe\tAES\tCorporation | $9 | $658 | $1,234 |

# 2.	Notes	Payable

|  | Interest	Rate | Maturity | 2010 | 2009 |
| :--- | :--- | :--- | :--- | :--- |
|  |  |  | (in\tmillions) |  |
| Senior\tUnsecured\tNote | 9.375% | 2010 | $— | $214 |
| Senior\tSecured\tTerm\tLoan | \tLIBOR\t+\t1.75% | 2011 | 200 | 200 |
| Senior\tUnsecured\tNote | 8.875% | 2011 | 129 | 129 |
| Senior\tUnsecured\tNote | 8.375% | 2011 | 134 | 139 |
| Second\tPriority\tSenior\tSecured\tNote | 8.75% | 2013 | — | 690 |
| Senior\tUnsecured\tNote | 7.75% | 2014 | 500 | 500 |
| Senior\tUnsecured\tNote | 7.75% | 2015 | 500 | 500 |
| Senior\tUnsecured\tNote | 9.75% | 2016 | 535 | 535 |
| Senior\tUnsecured\tNote | 8.00% | 2017 | \t 1,500 | \t 1,500 |
| Senior\tUnsecured\tNote | 8.00% | 2020 | 625 | 625 |
| Term\tConvertible\tTrust\tSecurities | 6.75% | 2029 | 517 | 517 |
| Unamortized\tdiscounts |  |  | (28) | (34) |
| SUBTOTAL |  |  | $4,612 | $5,515 |
| Less:\tCurrent\tmaturities |  |  | (463) | (214) |
| Total |  |  | $4,149 | $5,301 |

FUTURE	MATURITIES	OF	DEBT—Recourse	debt	as	of	December	31,	2010	is	scheduled	to	reach	maturity	as	set	forth	in	the	table	below:

|  | Annual |
| :--- | :--- |
| December\t31, | Maturities |
|  | (in\tmillions) |
| 2011 | $463 |
| 2012 | — |
| 2013 | — |
| 2014 | 497 |
| 2015 | 500 |
| Thereafter | 3,152 |
| Total\tdebt | $4,612 |

# 3.	Dividends	from	Subsidiaries	and	Affiliates

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

|  | 2010 | 2009 | 2008 |
| :--- | :--- | :--- | :--- |
|  |  | (in\tmillions) |  |
| Subsidiaries | $944 | $948 | $738 |
| Affiliates | $10 | $60 | $61 |

# 4.	Guarantees	and	Letters	of	Credit

GUARANTEES—In	connection	with	certain	of	its	project	financing,	acquisition,	and	power	purchase	agreements,	the	Company	has	expressly	undertaken limited	obligations	and	commitments,	most	of	which	will	only	be	effective	or	will	be	terminated	upon	the	occurrence	of	future	events.	These	obligations	and commitments,	excluding	those	collateralized	by	letter	of	credit	and	other	obligations	discussed	below,	were	limited	as	of	December	31,	2010,	by	the	terms	of	the agreements,	to	an	aggregate	of	approximately	$415	million	representing	24	agreements	with	individual	exposures	ranging	from	less	than	$1	million	up	to	$62	million.

LETTERS	OF	CREDIT—At	December	31,	2010,	the	Company	had	$85	million	in	letters	of	credit	outstanding	representing	30	agreements	with	individual exposures	ranging	from	less	than	$1	million	up	to	$26	million,	which	operate	to	guarantee	performance	relating	to	certain	project	development	and	construction activities	and	subsidiary	operations.	During	2010,	the	Company	paid	letter	of	credit	fees	ranging	from	3.19%	to	3.75%	per	annum	on	the	outstanding	amounts.

# SCHEDULE	II

# VALUATION	AND	QUALIFYING	ACCOUNTS

# (IN	MILLIONS)

|  | Balance	at<br>Beginning	of<br>the	Period | Charged	to<br>Cost<br>and	Expense | Amounts<br>Written	off | Translation<br>Adjustment | Balance	at<br>the	End	of<br>the	Period |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Allowance\tfor\taccounts\treceivables |  |  |  |  |  |
| (current\tand\tnoncurrent) |  |  |  |  |  |
| Year\tended\tDecember\t31,\t2008\t. | $257 | $128 | $(56) | $(74) | $255 |
| Year\tended\tDecember\t31,\t2009\t. | 255 | 106 | (109) | 41 | 293 |
| Year\tended\tDecember\t31,\t2010\t. | 293 | 53 | (41) | 3 | 308 |



Question: what percentage of recourse debt as of december 31 , 2010 matures after 2015?
Calculation: recourse_debt_maturity = 3152
recourse_debt_total = 4612
percent_after_2015 = recourse_debt_maturity / recourse_debt_total
answer = percent_after_2015 * 100
Answer: 68%